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Home My WebLink AboutAIO 018 DArea Injection Order 18D Docket Number: AIO-17-003 Colville River Field Colville River Unit Alpine Oil Pool 1. January 30, 2017 CPAI’s request for Alpine Oil Pool expansion (confidential pages 23 – 27 held in secure storage) 2. February 8, 2017 Notice of public hearing, affidavit of publication, email distribution, mailings 3. March 14, 2017 Transcript, sign-in sheet, exhibits (confidential Exhibits 1 – 4 held in secure storage) 4. June 26, 2017 Request for Reconsideration Errata Ordered 5. August 29, 2017 CPAI’s Request for Administrative Approval CD2-73 (AIO 18D.001) 6. September 21, 2017 Request for Reconsideration Errata Ordered (Corrected AIO18D.001) 7. October 12, 2017 Administrative approval to allow well CD2-55 (PTD 2031180) to be online in water only injection service with a known tubing by inner annulus communication. (AIO 18D.002) 8. December 17, 2017 CPAI’s request for AA CRU CD2-30 9. December 19, 2017 CPAI request for w/d December 17, 2017 request 10. February 28, 2018 CPAI’s request to cancel AIO 18B.001 11. October 29, 2018 CPAI’s request for AA CD2-02 (AIO 18D.003) 12. December 2, 2018 CPAI’s request for AA CD5-316 (AIO 18D.004) 13. May 6, 2019 CPAI’s request for AA CD4-12 (AIO 18D.005) 14. September 28, 2019 CPAI’s request for AA CD5-06 (AIO 18D.006) 15. January 27, 2021 CPAI’s request to cancel AIO18D.004 CD5-316 (AIO 18D.004) 16. August 17, 2021 Request for Administrative Approval to allow CD5-06 to continue WAG injection service (AIO 18D.006) 17. February 21, 2023 Request to amend AIO 18D.005 (AIO 18D.005 amended) ORDERS STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West Seventh Avenue Anchorage, Alaska 99501 Re: THE APPLICATION OF ConocoPhillips ) Area Injection Order No. 18D (Errata) Alaska, Inc. for expansion and contraction of ) Docket Number: AIO-17-003 the Affected Area of Area Injection Order No. ) 18C and the addition of rules pertaining to ) Colville River Field authorized injection pressure and authorized ) Colville River Unit injection fluids, Alpine Oil Pool, Colville River ) Alpine Oil Pool Unit, Arctic Slope, Alaska ) June 20, 2017 IT APPEARING THAT: ConocoPhillips Alaska, Inc. (CPAI), in its capacity as unit operator, by letter dated January 30, 2017, and received January 31, 2017, requests an order expanding and contracting the affected area of Area Injection Order (AIO) 18C. CPAI also requests the addition of a rule pertaining to maximum authorized injection pressure for enhanced oil recovery (EOR) purposes and another rule pertaining to fluids authorized for EOR purposes. 2. Pursuant to 20 AAC 25.540, the Alaska Oil and Gas Conservation Commission (AOGCC) scheduled a public hearing for March 14, 2017. On February 7, 2017, the AOGCC published notice of the opportunity for that hearing on the State of Alaska's Online Public Notice website, on the AOGCC's website, electronically transmitted the notice to all persons on the AOGCC's email distribution list, and mailed printed copies of the notice to all persons on the AOGCC's mailing distribution list. On February 8, 2017, the AOGCC published the notice in the ALASKA DISPATCH NEWS. 3. No comments on the application were received. 4. The hearing commenced at 9:00 AM on March 14, 2017. Testimony was received from representatives of CPAI. FINDINGS: 1. CPAI is the operator of the Colville River Unit (CRU) and all lands that are affected by this order. 2. The affected area and vertical limits of the Alpine Oil Pool (AOP) strata authorized for EOR injection in the CRU were initially defined on January 24, 2000, in AIO 18. The areal and vertical extent of the AOP has since been modified, most recently on March 26, 2009, by AIO 18C. 3. CPAI and Anadarko Petroleum Corporation are the owners of the leases affected by this order. The State of Alaska, Arctic Slope Regional Corporation, and Bureau of Land Management (BLM) are the landowners of the affected area AIO 18C. BLM is the landowner of the acreage proposed to be added to the affected area of AIO 18C. 4. Ongoing development of the CRU CD5 drillsite indicates that the productive area of the AOP likely extends beyond the western boundary of the current pool and AIO boundaries. 5. During an in camera session during the hearing, seismic and geologic data showed that the strata in which EOR injection is occurring appears to extend beyond the current affected area defined in AIO 18C. Additional injectors and producers will likely be drilled to locations in the proposed expansion acreage. AI018D (Errata) June 20, 2017 Page 2 of 6 6. Portions of the affected area of AIO 18C along the eastern portion of the affected area boundary do not appear to be contributing to production and are on acreage that is beyond the current CRU boundary. 7. AID 18C does not contain a rule that limits the maximum allowable injection pressure for EOR purposes in the affected area. 8. The authorized injection strata are overlain by 200 to 300 feet of Kalubik and HRZ shale and underlain by approximately 200 feet of Miluveach shale. Fracture modeling, that has been calibrated using rock mechanical properties from core data, indicates that the fracture gradient of the confining layer is at least 0.85 psi/ft. 9. CPAI proposes a maximum injection pressure limit of 0.81 psi/ft to ensure that injected fluids will not propagate fractures into the confining layers and thus confine injected fluids to the authorized injection interval. 10. AIO 18C does not specify what fluids may be injected for EOR purposes in the injection interval. 11. CPAI operates a miscible injectant water alternating gas (MWAG) project, utilizing both produced water and seawater from the Kuparuk River Unit seawater treatment plant. They have used this EOR method since field startup and the compatibility of the injection fluids was analyzed when preparing AIO 18. 12. Because the current order is silent on the topic, CPAI also requests clarification that it is authorized to inject lean gas and small volumes of other fluids that are associated with routine well work. All of these fluids have been injected in the injection interval for over 15 years of production with no indication of adversely affecting injection operations. 13. Rule 8 and a portion of Rule 9 simply restate permitting and reporting requirements, respectively, that are contained in the AOGCC's regulations. CONCLUSIONS: 1. Amending AIO 18C to expand the southwestern geographic boundaries of the AIO is consistent with the provisions of AS 31.05. The AIO expansion will not promote waste, jeopardize correlative rights, or compromise ultimate recovery and is based on sound engineering principles. Amending AIO 18C to contract the eastern geographic boundaries of the AIO to exclude the acreage that does not contribute to pool production is consistent with the provisions of AS 31.05. 2. Establishing a pressure limitation for EOR injection activities will help ensure that the injected fluids remain within the authorized injection interval. 3. Specifying which fluids are authorized in the EOR injection interval will help to avoid injection of fluids that may damage the reservoir or not contribute to the EOR process. 4. The purpose of an order issued by the AOGCC is to provide rules for operations that are not contained in its regulations. Therefore, there is no need to restate existing regulations in this AIO and eliminating Rule 8 and the portion of Rule 9 where this was done is appropriate. NOW, THEREFORE, IT IS ORDERED: This Area Injection Order supersedes AIO 18C, issued March 26, 2009. The findings, conclusions, and administrative records for AIO 18C are adopted by reference and incorporated in this decision, except where inconsistent with this AIO . The following rules, in addition to any other AI018D (Errata) June 20, 2017 Page 3 of 6 requirements (including the statewide regulatory requirements) that are not superseded by these rules, apply to the EOR and disposal injection intervals within the following affected area: Umiat Meridian Township Range Sections T10N R3E 1-3: All T 1 ON R4E 1-6: All T10N R5E 5: N1/2NW1/4, SW1/4NW1/4, & NW1/4SW1/4 6: All TI IN R3E 1-2: All 11-14: All 22-27: All 34-36: All T1 IN R4E 1-36: All TI IN R5E 1: WI/2W1/2 2-11: All 14: NW1/4NW1/4 15: W1/2, NEI/4, NI/2SE1/4, &SWI/4SE1/4 16-21: All 22: NW1/4 & NW1/4SW1/4 28-33: All T12N R3E 25, 26, 35, & 36: All T12N R4E 20-36: All T12N R5E 13-15: All 19-23: All 26: NW1/4NW1/4, S1/2NW1/4, SW1/4, & W1/2SE1/4 27-35: All 36: SWI/4SW1/4 Rule 1 Authorized Iniection Strata for Enhanced Recovery (Revised this Order) Within the affected area, authorized fluids may be injected for purposes of pressure maintenance and enhanced recovery into strata that are common to and correlate with the interval between the measured depths of 6,980 feet and 7,276 feet in the Alpine No. 1 well. The fluids authorized for injection in the EOR interval are: a. Source water from the Kuparuk seawater treatment plant, b. Produced water from the Alpine Central Facility, AI018D (Errata) June 20, 2017 Page 4 of 6 c. Enriched hydrocarbon gas (MI) from Alpine Central Facility, d. Lean gas, e. Tracer survey fluids to monitor reservoir performance (chemical, radioactive, etc.), f. Fluids used to improve near wellbore injectivity (via use of acid or similar treatment), g. Fluids used to seal wellbore intervals which negatively impact recovery efficiency (cement, resin, etc.), h. Fluids associated with freeze protection (diesel, dead crude, glycol methanol, etc.), and i. Standard oilfield chemicals (corrosion inhibitor, scale inhibitor, etc.) Rule 2 Authorized Iniection Strata for Disposal (Source: AIO 18A) Within the affected area, Class II fluids may be injected for purposes of disposal into strata that are common to and correlate with the interval between the measured depths of 8,432 and 9,540 feet in the Sohio Alaska Petroleum Company Nechelik No. 1 well. Rule 3 Fluid Injection Wells (Source: AIO 18) The underground injection of fluids must be through a well permitted for drilling as a service well for injection in conformance with 20 AAC 25.005 or through a well approved for conversion to a service well for injection in conformance with 20 AAC 25.280. Rule 4 Monitoring the Tubing -Casing Annulus Pressure Variations (Source: AIO 18) The tubing -casing annulus pressure and injection rate of each injection well must be checked at least weekly to ensure there is no leakage and that it does not exceed a pressure that will subject the casing to a hoop stress greater than 70% of the casing's minimum yield strength. Rule 5 Reporting the Tubing -Casing Annulus Pressure Variations (Source: AIO 18) Tubing -casing annulus pressure variations between consecutive observations need not be reported to the Commission unless well integrity failure is indicated as in Rule 7 below. Rule 6 Demonstration of Tubing/Casing Annulus Mechanical Integrity (Source: AI018) The mechanical integrity of an injection well must be demonstrated before injection begins, after a workover affecting mechanical integrity, and at least once every 4 years while actively injecting. For slurry injection wells, the tubing/casing annulus must be tested for mechanical integrity every 2 years. The MIT surface pressure must be 1,500 psi or 0.25 psi/ft multiplied by the vertical depth, whichever is greater, must show stabilizing pressure and may not change more than 10% during a 30 minute period. Any alternate means of demonstrating mechanical integrity must be approved by the Commission. The Commission must be notified at least 24 hours in advance to enable a representative to witness pressure tests. Rule 7 Well Integrity Failure and Confinement (Source: AIO 18) 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 Commission and submit a plan of corrective action on a Form 10-403 for Commission approval. The operator shall immediately shut in the well if continued operation would be unsafe or would threaten contamination of freshwater, or if so directed by the Commission. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating well integrity failure or lack of injection zone isolation. AI018D (Errata) June 20, 2017 Page 5 of 6 Rule 8 Plugljing and Abandonment of Injection Wells (Rescinded this order) Rule 9 Surveillance (Revised this order) For grind -and -inject slurry injection wells, a baseline temperature survey from surface to total depth, initial step -rate test to pressure equal or exceeding maximum injection pressure and pressure falloff are required prior to sustained disposal injection. Regular fill depth tags are required at least once annually or as warranted following consultation with the Commission. For slurry injection wells, an annual performance report will be required including rate and pressure performance, surveillance logging, fill depth, survey results, and volumetric analysis of the disposal storage volume, estimate of fracture growth, if any, and updates of operational plans. Report submission must be on or before April 1, in conjunction with the Alpine Pool Annual Reservoir Report. Rule 10 Notification (Source: AIO 18A) The operator must notify the Commission if it learns of any improper Class Il injection. Additional notification requirements of any other State or Federal agency remain the operators' responsibility. Rule 11 Administrative Actions (Source: AIO 18B) Unless notice and public hearing are otherwise required, the Commission may administratively waive or amend any rule stated above as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in fluid movement outside of the authorized injection zone. Rule 12 Authorized Injection Pressure for Enhanced Recovery (New this order) For the injection interval specified in Rule 1 above pressures will be managed not to exceed the maximum injection gradient of 0.81 psi/ft to ensure containment of injected fluids within the injectional interval. ENTERED at Anchorage, Alaska and dated June 27, 2017, nunc pro tunc June 20, 2017. Cathy . Foerster m I eamount, Jr. Hollis S. French Chair, CommissionerCommissioner Commissioner AI018D (Errata) June 20, 2017 Page 6 of 6 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 aweekend or state holiday. Stephen Thatcher Manager, WNS Development ConocoPhillips Alaska, Inc. ATC -1770 700 G St. Anchorage, AK 99501 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West Seventh Avenue Anchorage, Alaska 99501 Re: THE APPLICATION OF ConocoPhillips ) Area Injection Order No. 18D (Errata) Alaska, Inc. for expansion and contraction of ) Docket Number: AIO-17-003 the Affected Area of Area Injection Order No. ) 18C and the addition of rules pertaining to ) Colville River Field authorized injection pressure and authorized ) Colville River Unit injection fluids, Alpine Oil Pool, Colville River ) Alpine Oil Pool Unit, Arctic Slope, Alaska ) ) June 20, 2017 IT APPEARING THAT: ConocoPhillips Alaska, Inc. (CPAI), in its capacity as unit operator, by letter dated January 30, 2017, and received January 31, 2017, requests an order expanding and contracting the affected area of Area Injection Order (AIO) 18C. CPAI also requests the addition of a rule pertaining to maximum authorized injection pressure for enhanced oil recovery (EOR) purposes and another rule pertaining to fluids authorized for EOR purposes. 2. Pursuant to 20 AAC 25.540, the Alaska Oil and Gas Conservation Commission (AOGCC) scheduled a public hearing for March 14, 2017. On February 7, 2017, the AOGCC published notice of the opportunity for that hearing on the State of Alaska's Online Public Notice website, on the AOGCC's website, electronically transmitted the notice to all persons on the AOGCC's email distribution list, and mailed printed copies of the notice to all persons on the AOGCC's mailing distribution list. On February 8, 2017, the AOGCC published the notice in the ALASKA DISPATCH NEWS. 3. No comments on the application were received. 4. The hearing commenced at 9:00 AM on March 14, 2017. Testimony was received from representatives of CPAI. FINDINGS: 1. CPAI is the operator of the Colville River Unit (CRU) and all lands that are affected by this order. 2. The affected area and vertical limits of the Alpine Oil Pool (AOP) strata authorized for EOR injection in the CRU were initially defined on January 24, 2000, in AIO 18. The areal and vertical extent of the AOP has since been modified, most recently on March 26, 2009, by AIO 18C. 3. CPAI and Anadarko Petroleum Corporation are the owners of the leases affected by this order. The State of Alaska, Arctic Slope Regional Corporation, and Bureau of Land Management (BLM) are the landowners of the affected area AIO 18C. BLM is the landowner of the acreage proposed to be added to the affected area of AIO 18C. 4. Ongoing development of the CRU CD5 drillsite indicates that the productive area of the AOP likely extends beyond the western boundary of the current pool and AIO boundaries. 5. During an in camera session during the hearing, seismic and geologic data showed that the strata in which EOR injection is occurring appears to extend beyond the current affected area defined in AIO 18C. Additional injectors and producers will likely be drilled to locations in the proposed expansion acreage. A1018D (Errata) June 20, 2017 Page 2 of 6 6. Portions of the affected area of AIO 18C along the eastern portion of the affected area boundary do not appear to be contributing to production and are on acreage that is beyond the current CRU boundary. 7. AIO 18C does not contain a rule that limits the maximum allowable injection pressure for EOR purposes in the affected area. 8. The authorized injection strata are overlain by 200 to 300 feet of Kalubik and HRZ shale and underlain by approximately 200 feet of Miluveach shale. Fracture modeling, that has been calibrated using rock mechanical properties from core data, indicates that the fracture gradient of the confining layer is at least 0.85 psi/ft. 9. CPAI proposes a maximum injection pressure limit of 0.81 psi/ft to ensure that injected fluids will not propagate fractures into the confining layers and thus confine injected fluids to the authorized injection interval. 10. AIO 18C does not specify what fluids may be injected for EOR purposes in the injection interval. 11. CPAI operates a miscible injectant water alternating gas (MWAG) project, utilizing both produced water and seawater from the Kuparuk River Unit seawater treatment plant. They have used this EOR method since field startup and the compatibility of the injection fluids was analyzed when preparing AIO 18. 12. Because the current order is silent on the topic, CPAI also requests clarification that it is authorized to inject lean gas and small volumes of other fluids that are associated with routine well work. All of these fluids have been injected in the injection interval for over 15 years of production with no indication of adversely affecting injection operations. 13. Rule 8 and a portion of Rule 9 simply restate permitting and reporting requirements, respectively, that are contained in the AOGCC's regulations. CONCLUSIONS: Amending AIO 18C to expand the southwestern geographic boundaries of the AIO is consistent with the provisions of AS 31.05. The AIO expansion will not promote waste, jeopardize correlative rights, or compromise ultimate recovery and is based on sound engineering principles. Amending AIO 18C to contract the eastern geographic boundaries of the AIO to exclude the acreage that does not contribute to pool production is consistent with the provisions of AS 31.05. 2. Establishing a pressure limitation for EOR injection activities will help ensure that the injected fluids remain within the authorized injection interval. 3. Specifying which fluids are authorized in the EOR injection interval will help to avoid injection of fluids that may damage the reservoir or not contribute to the EOR process. 4. The purpose of an order issued by the AOGCC is to provide rules for operations that are not contained in its regulations. Therefore, there is no need to restate existing regulations in this AIO and eliminating Rule 8 and the portion of Rule 9 where this was done is appropriate. NOW, THEREFORE, IT IS ORDERED: This Area Injection Order supersedes AIO 18C, issued March 26, 2009. The findings, conclusions, and administrative records for AIO 18C are adopted by reference and incorporated in this decision, except where inconsistent with this AIO . The following rules, in addition to any other A1018D (Errata) June 20, 2017 Page 3 of 6 requirements (including the statewide regulatory requirements) that are not superseded by these rules, apply to the EOR and disposal injection intervals within the following affected area: Umiat Meridian Township Range Sections TION R3E 1-3: All TION R4E 1 1-6: All TION R5E 5: N1/2NW1/4, SWI/4NW1/4, & NW1/4SW1/4 6: All T1 IN R3E 1-2: All 11-14: All 22-27: All 34-36: All TI IN R4E 1-36: All TI IN R5E 1: W1/2W1/2 2-11: All 14: NW1/4NW1/4 15: W1/2, NEI/4, N1/2SE1/4, &SWI/4SE1/4 16-21: All 22: NWI/4 & NW1/4SW1/4 28-33: All T12N R3E 25, 26, 35, & 36: All T12N R4E 20-36: All T12N R5E 13-15: All 19-23: All 26: NW1/4NW1/4, S1/2NW1/4, SWI/4, & W1/2SE1/4 27-35: All 36: SWI/4SW1/4 Rule 1 Authorized Injection Strata for Enhanced Recovery (Revised this Order) Within the affected area, authorized fluids may be injected for purposes of pressure maintenance and enhanced recovery into strata that are common to and correlate with the interval between the measured depths of 6,980 feet and 7,276 feet in the Alpine No. 1 well. The fluids authorized for injection in the EOR interval are: a. Source water from the Kuparuk seawater treatment plant, b. Produced water from the Alpine Central Facility, AIOI8D (Errata) June 20, 2017 Page 4 of 6 c. Enriched hydrocarbon gas (MI) from Alpine Central Facility, d. Lean gas, e. Tracer survey fluids to monitor reservoir performance (chemical, radioactive, etc.), f. Fluids used to improve near wellbore injectivity (via use of acid or similar treatment), g. Fluids used to seal wellbore intervals which negatively impact recovery efficiency (cement, resin, etc.), h. Fluids associated with freeze protection (diesel, dead crude, glycol methanol, etc.), and i. Standard oilfield chemicals (corrosion inhibitor, scale inhibitor, etc.) Rule 2 Authorized Infection Strata for Disposal (Source: AIO 18A) Within the affected area, Class II fluids may be injected for purposes of disposal into strata that are common to and correlate with the interval between the measured depths of 8,432 and 9,540 feet in the Sohio Alaska Petroleum Company Nechelik No. 1 well. Rule 3 Fluid Infection Wells (Source: AIO 18) The underground injection of fluids must be through a well permitted for drilling as a service well for injection in conformance with 20 AAC 25.005 or through a well approved for conversion to a service well for injection in conformance with 20 AAC 25.280. Rule 4 Monitoring the Tubing -Casing Annulus Pressure Variations (Source: AIO 18) The tubing -casing annulus pressure and injection rate of each injection well must be checked at least weekly to ensure there is no leakage and that it does not exceed a pressure that will subject the casing to a hoop stress greater than 70% of the casing's minimum yield strength. Rule 5 Reporting the Tubing -Casing Annulus Pressure Variations (Source: AIO 18) Tubing -casing annulus pressure variations between consecutive observations need not be reported to the Commission unless well integrity failure is indicated as in Rule 7 below. Rule 6 Demonstration of Tubing/Casing Annulus Mechanical Integrity (Source: AI018) The mechanical integrity of an injection well must be demonstrated before injection begins, after a workover affecting mechanical integrity, and at least once every 4 years while actively injecting. For slurry injection wells, the tubing/casing annulus must be tested for mechanical integrity every 2 years. The MIT surface pressure must be 1,500 psi or 0.25 psi/ft multiplied by the vertical depth, whichever is greater, must show stabilizing pressure and may not change more than 10% during a 30 minute period. Any alternate means of demonstrating mechanical integrity must be approved by the Commission. The Commission must be notified at least 24 hours in advance to enable a representative to witness pressure tests. Rule 7 Well Integrity Failure and Confinement (Source: AIO 18) 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 Commission and submit a plan of corrective action on a Form 10-403 for Commission approval. The operator shall immediately shut in the well if continued operation would be unsafe or would threaten contamination of freshwater, or if so directed by the Commission. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating well integrity failure or lack of injection zone isolation. A1018D (Errata) June 20, 2017 Page 5 of 6 Rule 8 Plugging and Abandonment of Iniection Wells (Rescinded this order) Rule 9 Surveillance (Revised this order) For grind -and -inject slurry injection wells, a baseline temperature survey from surface to total depth, initial step -rate test to pressure equal or exceeding maximum injection pressure and pressure falloff are required prior to sustained disposal injection. Regular fill depth tags are required at least once annually or as warranted following consultation with the Commission. For slurry injection wells, an annual performance report will be required including rate and pressure performance, surveillance logging, fill depth, survey results, and volumetric analysis of the disposal storage volume, estimate of fracture growth, if any, and updates of operational plans. Report submission must be on or before April 1, in conjunction with the Alpine Pool Annual Reservoir Report. Rule 10 Notification (Source: AIO 18A) The operator must notify the Commission if it learns of any improper Class II injection. Additional notification requirements of any other State or Federal agency remain the operators' responsibility. Rule 11 Administrative Actions (Source: AIO 18B) Unless notice and public hearing are otherwise required, the Commission may administratively waive or amend any rule stated above as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in fluid movement outside of the authorized injection zone. Rule 12 Authorized Iniection Pressure for Enhanced Recovery (New this order) For the injection interval specified in Rule 1 above pressures will be managed not to exceed the maximum injection gradient of 0.81 psi/ft to ensure containment of injected fluids within the injectional interval. ENTERED at Anchorage, Alaska and dated June 27, 2017, nunc pro tunc June 20, 2017. //signature on file// //signature on file// //signature on file// Cathy P. Foerster Daniel T. Seamount, Jr. Hollis S. French Chair, Commissioner Commissioner Commissioner AI018D (Errata) June 20, 2017 Page 6 of 6 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. Bernie Karl K&K Recycling Inc. Gordon Severson Penny Vadla P.O. Box 58055 3201 Westmar Cir. 399 W. Riverview Ave. Fairbanks, AK 99711-0055 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 99639-0309 Fairbanks, AK 99706-0868 �0 CL CQ-3o�2,c,�Z Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Wednesday, June 28, 2017 10:45 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); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA); French, Hollis (DOA); Frystacky, Michal (DOA); Guhl, Meredith D (DOA); Kair, Michael N (DOA); Link, Liz M (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Quick, Michael J (DOA); Regg, James B (DOA); Roby, David S (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Wallace, Chris D (DOA); AK, GWO Projects Well Integrity; AKDCWellIntegrityCoordinator; Alan Bailey; Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew VanderJack; Ann Danielson; Anna Raff; Barbara F Fullmer; bbritch; bbohrer@ap.org; Ben Boettger; Bill Bredar; Bob Shavelson; Brandon Viator; Brian Havelock; Bruce Webb; Caleb Conrad; Candi English; Cocklan-Vendl, Mary E; Colleen Miller, Connie Downing; Crandall, Krissell; D Lawrence; Dale Hoffman; Darci Horner; Dave Harbour, David Boelens; David Duffy; David House; David McCaleb; David McCraine; ddonkel@cfl.rr.com; DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elizabeth Harball; Elowe, Kristin; Elwood Brehmer; Evan Osborne; Evans, John R (LDZX); George Pollock; Gordon Pospisil; Greeley, Destin M (DOR); Gretchen Stoddard; gspfoff; Hunter Cox; Hurst, Rona D (DNR); Hyun, James J (DNR); Jacki Rose; Jason Brune; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jill Simek; Jim Watt; Jim White; Joe Lastufka; Radio Kenai; Burdick, John D (DNR); Easton, John R (DNR); Larsen, John M (DOR); John Stuart; Jon Goltz; Chmielowski, Josef (DNR); Juanita Lovett; Judy Stanek; Kari Moriarty; Kasper Kowalewski; Kazeem Adegbola; Keith Torrance; Keith Wiles; Kelly Sperback; Frank, Kevin J (DNR); Kruse, Rebecca D (DNR); Gregersen, Laura S (DNR); Leslie Smith; Lori Nelson; Louisiana Cutler, Luke Keller; Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Mealear Tauch; Michael Bill; Michael Calkins; Michael Moora; Mike Morgan; MJ Loveland; mkm7200; Motteram, Luke A; Mueller, Marta R (DNR); Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nick Ostrovsky; Nikki Martin; NSK Problem Well Supv; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Renan Yanish; Richard Cool; Robert Brelsford; Sara Leverette; Scott Griffith; Shahla Farzan; Shannon Donnelly; Sharon Yarawsky; Skutca, Joseph E (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Stephanie Klemmer; Stephen Hennigan; Sternicki, Oliver R; Moothart, Steve R (DNR); Steve Quinn; Suzanne Gibson; sheffield@aoga.org; Ted Kramer; Teresa Imm; 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); Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Fair, Holly S (DNR); Jamie M. Long; Jason Bergerson; Jesse Chielowski; Jim Magill; Shine, Jim M (DNR); 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); Tostevin, Breck C (LAW); William Van Dyke Subject: AI018D and C0443C Errata and Amended Orders Attachments: co443c (Errata).pdf, aiol8d (Errata).pdf; C0443C and AI018D Errata.pdf Please see attached. Jody J. Colombie AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7" Avenue Anchorage, Alaska ,99501 Office: (907) 793-1221 Fax: (907) 276-7542 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jody Colombie at 907.793.1221 or iodv.colombie@alaska.gov. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West Seventh Avenue Anchorage, Alaska 99501 Re: THE APPLICATION OF ConocoPhillips Alaska, Inc. for expansion and contraction of the Affected Area of Area Injection Order No. 18C and the addition of rules pertaining to authorized injection pressure and authorized injection fluids, Alpine Oil Pool, Colville River Unit, Arctic Slope, Alaska IT APPEARING THAT: Area Injection Order No. 18D Docket Number: AIO-17-003 Colville River Field Colville River Unit Alpine Oil Pool June 20, 2017 1. ConocoPhillips Alaska, Inc. (CPAI), in its capacity as unit operator, by letter dated January 30, 2017, and received January 31, 2017, requests an order expanding and contracting the affected area of Area Injection Order (AIO) 18C. CPAI also requests the addition of a rule pertaining to maximum authorized injection pressure for enhanced oil recovery (EOR) purposes and another rule pertaining to fluids authorized for EOR purposes. 2. Pursuant to 20 AAC 25.540, the Alaska Oil and Gas Conservation Commission (AOGCC) scheduled a public hearing for March 14, 2017. On February 7, 2017, the AOGCC published notice of the opportunity for that hearing on the State of Alaska's Online Public Notice website, on the AOGCC's website, electronically transmitted the notice to all persons on the AOGCC's email distribution list, and mailed printed copies of the notice to all persons on the AOGCC's mailing distribution list. On February 8, 2017, the AOGCC published the notice in the ALASKA DISPATCH NEWS. 3. No comments on the application were received. 4. The hearing commenced at 9:00 AM on March 14, 2017. Testimony was received from representatives of CPAI. FINDINGS: 1. CPAI is the operator of the Colville River Unit (CRU) and all lands that are affected by this order. 2. The affected area and vertical limits of the Alpine Oil Pool (AOP) strata authorized for EOR injection in the CRU were initially defined on January 24, 2000, in AIO 18. The areal and vertical extent of the AOP has since been modified, most recently on March 26, 2009, by AIO 18C. 3. CPAI and Anadarko Petroleum Corporation are the owners of the leases affected by this order. The State of Alaska, Arctic Slope Regional Corporation, and Bureau of Land Management (BLM) are the landowners of the affected area AIO 18C. BLM is the landowner of the acreage proposed to be added to the affected area of AIO 18C. 4. Ongoing development of the CRU CD5 drillsite indicates that the productive area of the AOP likely extends beyond the western boundary of the current pool and AIO boundaries. 5. During an in camera session during the hearing, seismic and geologic data showed that the strata in which EOR injection is occurring appears to extend beyond the current affected area defined in AIO 18C. Additional injectors and producers will likely be drilled to locations in the proposed expansion acreage. AI018D June 20, 2017 Page 2 of 6 6. Portions of the affected area of AIO 18C along the eastern portion of the affected area boundary do not appear to be contributing to production and are on acreage that is beyond the current CRU boundary. 7. AIO 18C does not contain a rule that limits the maximum allowable injection pressure for EOR purposes in the affected area. 8. The authorized injection strata are overlain by 200 to 300 feet of Kalubik and HRZ shale and underlain by approximately 200 feet of Miluveach shale. Fracture modeling, that has been calibrated using rock mechanical properties from core data, indicates that the fracture gradient of the confining layer is at least 0.85 psi/ft. 9. CPAI proposes a maximum injection pressure limit of 0.81 psi/ft to ensure that injected fluids will not propagate fractures into the confining layers and thus confine injected fluids to the authorized injection interval. 10. AIO 18C does not specify what fluids may be injected for EOR purposes in the injection interval. 11. CPAI operates a miscible injectant water alternating gas (MWAG) project, utilizing both produced water and seawater from the Kuparuk River Unit seawater treatment plant. They have used this EOR method since field startup and the compatibility of the injection fluids was analyzed when preparing AIO 18. 12. Because the current order is silent on the topic, CPAI also requests clarification that it is authorized to inject lean gas and small volumes of other fluids that are associated with routine well work. All of these fluids have been injected in the injection interval for over 15 years of production with no indication of adversely affecting injection operations. 13. Rule 8 and a portion of Rule 9 simply restate permitting and reporting requirements, respectively, that are contained in the AOGCC's regulations. CONCLUSIONS: 1. Amending AIO 18C to expand the southwestern geographic boundaries of the AIO is consistent with the provisions of AS 31.05. The AIO expansion will not promote waste, jeopardize correlative rights, or compromise ultimate recovery and is based on sound engineering principles. Amending AIO 18C to contract the eastern geographic boundaries of the AIO to exclude the acreage that does not contribute to pool production is consistent with the provisions of AS 31.05. 2. Establishing a pressure limitation for EOR injection activities will help ensure that the injected fluids remain within the authorized injection interval. 3. Specifying which fluids are authorized in the EOR injection interval will help to avoid injection of fluids that may damage the reservoir or not contribute to the EOR process. 4. The purpose of an order issued by the AOGCC is to provide rules for operations that are not contained in its regulations. Therefore, there is no need to restate existing regulations in this AIO and eliminating Rule 8 and the portion of Rule 9 where this was done is appropriate. NOW, THEREFORE, IT IS ORDERED: This Area Injection Order supersedes AIO 18C, issued March 26, 2009. The findings, conclusions, and administrative records for AIO 18C are adopted by reference and incorporated AI018D June 20, 2017 Page 3 of 6 in this decision, except where inconsistent with this AIO . The following rules, in addition to any other requirements (including the statewide regulatory requirements) that are not superseded by these rules, apply to the EOR and disposal injection intervals within the following affected area: Umiat Meridian Township Range Sections TION R3E 1-3: All T10N R4E 1 1-6: All T10N R5E 5: N1/2NW1/4, SWIANW1/4, & NW1/4SW1/4 6: All TI IN R3E 1-2: All 11-14: All 22-17: All 34-36: All TI IN R4E 1-36: All TI IN R5E 1: W1/2W1/2 2-11: All 14: NW1/4NW1/4 15: W1/2, NEI/4, N1/2SE1/4, &SWI/4SE1/4 16-21: All 22: NW1/4 & NW1/4SW1/4 28-33: All T12N R3E 25, 26, 35, & 36: All T12N R4E 20-36: All T12N R5E 13-15: All 19-23: All 26: NW1/4NW1/4, S1/2NW1/4, SWI/4, & W1/2SE1/4 27-35: All 36: SWI/4SW1/4 Rule 1 Authorized Iniection Strata for Enhanced Recovery (Revised this Order) Within the affected area, authorized fluids may be injected for purposes of pressure maintenance and enhanced recovery into strata that are common to and correlate with the interval between the measured depths of 6,980 feet and 7,276 feet in the Alpine No. 1 well. The fluids authorized for injection in the EOR interval are: AI018D June 20, 2017 Page 4 of 6 a. Source water from the Kuparuk seawater treatment plant, b. Produced water from the Alpine Central Facility, c. Enriched hydrocarbon gas (MI) from Alpine Central Facility, d. Lean gas, e. Tracer survey fluids to monitor reservoir performance (chemical, radioactive, etc.), f. Fluids used to improve near wellbore injectivity (via use of acid or similar treatment), g. Fluids used to seal wellbore intervals which negatively impact recovery efficiency (cement, resin, etc.), h. Fluids associated with freeze protection (diesel, dead crude, glycol methanol, etc.), and i. Standard oilfield chemicals (corrosion inhibitor, scale inhibitor, etc.) Rule 2 Authorized Injection Strata for Disposal (Source: AIO 18A) Within the affected area, Class II fluids may be injected for purposes of disposal into strata that are common to and correlate with the interval between the measured depths of 8,432 and 9,540 feet in the Sohio Alaska Petroleum Company Nechelik No. 1 well. Rule 3 Fluid Iniection Wells (Source: AIO 18) The underground injection of fluids must be through a well permitted for drilling as a service well for injection in conformance with 20 AAC 25.005 or through a well approved for conversion to a service well for injection in conformance with 20 AAC 25.280. Rule 4 Monitoring the Tubing -Casing Annulus Pressure Variations (Source: AIO 18) The tubing -casing annulus pressure and injection rate of each injection well must be checked at least weekly to ensure there is no leakage and that it does not exceed a pressure that will subject the casing to a hoop stress greater than 70% of the casing's minimum yield strength. Rule 5 Reporting the Tubing -Casing Annulus Pressure Variations (Source: AIO 18) Tubing -casing annulus pressure variations between consecutive observations need not be reported to the Commission unless well integrity failure is indicated as in Rule 7 below. Rule 6 Demonstration of Tubing/Casing Annulus Mechanical Integrity (Source: AI018) The mechanical integrity of an injection well must be demonstrated before injection begins, after a workover affecting mechanical integrity, and at least once every 4 years while actively injecting. For slurry injection wells, the tubing/casing annulus must be tested for mechanical integrity every 2 years. The MIT surface pressure must be 1,500 psi or 0.25 psi/ft multiplied by the vertical depth, whichever is greater, must show stabilizing pressure and may not change more than 10% during a 30 minute period. Any alternate means of demonstrating mechanical integrity must be approved by the Commission. The Commission must be notified at least 24 hours in advance to enable a representative to witness pressure tests. Rule 7 Well Integrity Failure and Confinement (Source: AIO 18) 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 Commission and submit a plan of corrective action on a Form 10- 403 for Commission approval. The operator shall immediately shut in the well if continued AI018D June 20, 2017 Page 5 of 6 operation would be unsafe or would threaten contamination of freshwater, or if so directed by the Commission. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating well integrity failure or lack of injection zone isolation. Rule 8 Plugging and Abandonment of Injection Wells (Rescinded this order) Rule 9 Surveillance (Revised this order) For grind -and -inject slurry injection wells, a baseline temperature survey from surface to total depth, initial step -rate test to pressure equal or exceeding maximum injection pressure and pressure falloff are required prior to sustained disposal injection. Regular fill depth tags are required at least once annually or as warranted following consultation with the Commission. For slurry injection wells, an annual performance report will be required including rate and pressure performance, surveillance logging, fill depth, survey results, and volumetric analysis of the disposal storage volume, estimate of fracture growth, if any, and updates of operational plans. Report submission must be on or before April 1, in conjunction with the Alpine Pool Annual Reservoir Report. Rule 10 Notification (Source: AIO 18A) The operator must notify the Commission if it learns of any improper Class II injection. Additional notification requirements of any other State or Federal agency remain the operators' responsibility. Rule 11 Administrative Actions (Source: AIO 18B) Unless notice and public hearing are otherwise required, the Commission may administratively waive or amend any rule stated above as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in fluid movement outside of the authorized injection zone. Rule 12 Authorized Iniection Pressure for Enhanced Recovery (New this order) For the injection interval specified in Rule 1 above pressures will be managed not to exceed the maximum injection gradient of 0.81 psi/ft to ensure containment of injected fluids within the injectional interval. ENTERED at Anchorage, Cathy,T'. Foerster Chair, Commissioner and date�i;i,9 2017. Daniel T. Seamount, Jr Commissioner Hollis S. French Commissioner AI018D June 20, 2017 Page 6 of 6 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(x), 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, he 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 eventhe period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Misty Alexa Manager, WNS Development North Slope Operations and Development ConocoPhillips Alaska, Inc. ATO -1770 700 G St. Anchorage, AK 99501 (e - 22- 201-T T STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West Seventh Avenue Anchorage, Alaska 99501 Re: THE APPLICATION OF ConocoPhillips Alaska, Inc. for expansion and contraction of the Affected Area of Area Injection Order No. 18C and the addition of rules pertaining to authorized injection pressure and authorized injection fluids, Alpine Oil Pool, Colville River Unit, Arctic Slope, Alaska IT APPEARING THAT: Area Injection Order No. 18D Docket Number: AIO-17-003 Colville River Field Colville River Unit Alpine Oil Pool June 20, 2017 1. ConocoPhillips Alaska, Inc. (CPAI), in its capacity as unit operator, by letter dated January 30, 2017, and received January 31, 2017, requests an order expanding and contracting the affected area of Area Injection Order (AIO) 18C. CPAI also requests the addition of a rule pertaining to maximum authorized injection pressure for enhanced oil recovery (EOR) purposes and another rule pertaining to fluids authorized for EOR purposes. 2. Pursuant to 20 AAC 25.540, the Alaska Oil and Gas Conservation Commission (AOGCC) scheduled a public hearing for March 14, 2017. On February 7, 2017, the AOGCC published notice of the opportunity for that hearing on the State of Alaska's Online Public Notice website, on the AOGCC's website, electronically transmitted the notice to all persons on the AOGCC's email distribution list, and mailed printed copies of the notice to all persons on the AOGCC's mailing distribution list. On February 8, 2017, the AOGCC published the notice in the ALASKA DISPATCH NEWS. 3. No comments on the application were received. 4. The hearing commenced at 9:00 AM on March 14, 2017. Testimony was received from representatives of CPAI. FINDINGS: 1. CPAI is the operator of the Colville River Unit (CRU) and all lands that are affected by this order. 2. The affected area and vertical limits of the Alpine Oil Pool (AOP) strata authorized for EOR injection in the CRU were initially defined on January 24, 2000, in AIO 18. The areal and vertical extent of the AOP has since been modified, most recently on March 26, 2009, by AIO 18C. 3. CPAI and Anadarko Petroleum Corporation are the owners of the leases affected by this order. The State of Alaska, Arctic Slope Regional Corporation, and Bureau of Land Management (BLM) are the landowners of the affected area AIO 18C. BLM is the landowner of the acreage proposed to be added to the affected area of AIO 18C. 4. Ongoing development of the CRU CD5 drillsite indicates that the productive area of the AOP likely extends beyond the western boundary of the current pool and AIO boundaries. 5. During an in camera session during the hearing, seismic and geologic data showed that the strata in which EOR injection is occurring appears to extend beyond the current affected area defined in AIO 18C. Additional injectors and producers will likely be drilled to locations in the proposed expansion acreage. AI018D June 20, 2017 Page 2 of 6 6. Portions of the affected area of AIO 18C along the eastern portion of the affected area boundary do not appear to be contributing to production and are on acreage that is beyond the current CRU boundary. 7. AIO 18C does not contain a rule that limits the maximum allowable injection pressure for EOR purposes in the affected area. 8. The authorized injection strata are overlain by 200 to 300 feet of Kalubik and HRZ shale and underlain by approximately 200 feet of Miluveach shale. Fracture modeling, that has been calibrated using rock mechanical properties from core data, indicates that the fracture gradient of the confining layer is at least 0.85 psi/ft. 9. CPAI proposes a maximum injection pressure limit of 0.81 psi/ft to ensure that injected fluids will not propagate fractures into the confining layers and thus confine injected fluids to the authorized injection interval. 10. AIO 18C does not specify what fluids may be injected for EOR purposes in the injection interval. 11. CPAI operates a miscible injectant water alternating gas (MWAG) project, utilizing both produced water and seawater from the Kuparuk River Unit seawater treatment plant. They have used this EOR method since field startup and the compatibility of the injection fluids was analyzed when preparing AIO 18. 12. Because the current order is silent on the topic, CPAI also requests clarification that it is authorized to inject lean gas and small volumes of other fluids that are associated with routine well work. All of these fluids have been injected in the injection interval for over 15 years of production with no indication of adversely affecting injection operations. 13. Rule 8 and a portion of Rule 9 simply restate permitting and reporting requirements, respectively, that are contained in the AOGCC's regulations. CONCLUSIONS: 1. Amending AIO 18C to expand the southwestern geographic boundaries of the AIO is consistent with the provisions of AS 31.05. The AIO expansion will not promote waste, jeopardize correlative rights, or compromise ultimate recovery and is based on sound engineering principles. Amending AIO 18C to contract the eastern geographic boundaries of the AIO to exclude the acreage that does not contribute to pool production is consistent with the provisions of AS 31.05. 2. Establishing a pressure limitation for EOR injection activities will help ensure that the injected fluids remain within the authorized injection interval. 3. Specifying which fluids are authorized in the EOR injection interval will help to avoid injection of fluids that may damage the reservoir or not contribute to the EOR process. 4. The purpose of an order issued by the AOGCC is to provide rules for operations that are not contained in its regulations. Therefore, there is no need to restate existing regulations in this AIO and eliminating Rule 8 and the portion of Rule 9 where this was done is appropriate. NOW, THEREFORE, IT IS ORDERED: This Area Injection Order supersedes AIO 18C, issued March 26, 2009. The findings, conclusions, and administrative records for AIO 18C are adopted by reference and incorporated AI018D June 20, 2017 Page 3 of 6 in this decision, except where inconsistent with this AIO . The following rules, in addition to any other requirements (including the statewide regulatory requirements) that are not superseded by these rules, apply to the EOR and disposal injection intervals within the following affected area: Umiat Meridian Township Range Sections TION R3E 1-3: All T l ON R4E 1-6: All T10N R5E 5: Nl/2NW1/4, SWIANWI/4, & NW1/4SW1/4 6: All TI IN R3E 1-2: All 11-14: All 22-17: All 34-36: All TI IN R4E 1-36: All TI IN R5E 1: W1/2W1/2 2-11: All 14: NW1/4NW1/4 15: W1/2, NEI/4, N1/2SE1/4, &SWI/4SE1/4 16-21: All 22: NWIA & NW1/4SW1/4 28-33: All T12N R3E 25, 26, 35, & 36: All T12N R4E 20-36: All T12N R5E 13-15: All 19-23: All 26: NW1/4NW1/4, S1/2NW1/4, SWI/4, & W1/2SE1/4 27-35: All 36: SW1/4SW1/4 Rule 1 Authorized Iniection Strata for Enhanced Recovery (Revised this Order) Within the affected area, authorized fluids may be injected for purposes of pressure maintenance and enhanced recovery into strata that are common to and correlate with the interval between the measured depths of 6,980 feet and 7,276 feet in the Alpine No. 1 well. The fluids authorized for injection in the EOR interval are: AI018D June 20, 2017 Page 4 of 6 a. Source water from the Kuparuk seawater treatment plant, b. Produced water from the Alpine Central Facility, c. Enriched hydrocarbon gas (MI) from Alpine Central Facility, d. Lean gas, e. Tracer survey fluids to monitor reservoir performance (chemical, radioactive, etc.), f. Fluids used to improve near wellbore injectivity (via use of acid or similar treatment), g. Fluids used to seal wellbore intervals which negatively impact recovery efficiency (cement, resin, etc.), h. Fluids associated with freeze protection (diesel, dead crude, glycol methanol, etc.), and i. Standard oilfield chemicals (corrosion inhibitor, scale inhibitor, etc.) Rule 2 Authorized Iniection Strata for Disposal (Source: AIO 18A) Within the affected area, Class II fluids may be injected for purposes of disposal into strata that are common to and correlate with the interval between the measured depths of 8,432 and 9,540 feet in the Sohio Alaska Petroleum Company Nechelik No. 1 well. Rule 3 Fluid Iniection Wells (Source: A10 18) The underground injection of fluids must be through a well permitted for drilling as a service well for injection in conformance with 20 AAC 25.005 or through a well approved for conversion to a service well for injection in conformance with 20 AAC 25.280. Rule 4 Monitoring the Tubing -Casing Annulus Pressure Variations (Source: AIO 18) The tubing -casing annulus pressure and injection rate of each injection well must be checked at least weekly to ensure there is no leakage and that it does not exceed a pressure that will subject the casing to a hoop stress greater than 70% of the casing's minimum yield strength. Rule 5 Reporting the Tubing -Casing Annulus Pressure Variations (Source: AIO 18) Tubing -casing annulus pressure variations between consecutive observations need not be reported to the Commission unless well integrity failure is indicated as in Rule 7 below. Rule 6 Demonstration of Tubing/Casing Annulus Mechanical Integrity (Source: A1018) The mechanical integrity of an injection well must be demonstrated before injection begins, after a workover affecting mechanical integrity, and at least once every 4 years while actively injecting. For slurry injection wells, the tubing/casing annulus must be tested for mechanical integrity every 2 years. The MIT surface pressure must be 1,500 psi or 0.25 psi/ft multiplied by the vertical depth, whichever is greater, must show stabilizing pressure and may not change more than 10% during a 30 minute period. Any alternate means of demonstrating mechanical integrity must be approved by the Commission. The Commission must be notified at least 24 hours in advance to enable a representative to witness pressure tests. Rule 7 Well Integrity Failure and Confinement (Source: AIO 18) 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 Commission and submit a plan of corrective action on a Form 10- 403 for Commission approval. The operator shall immediately shut in the well if continued AI018D June 20, 2017 Page 5 of 6 operation would be unsafe or would threaten contamination of freshwater, or if so directed by the Commission. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating well integrity failure or lack of injection zone isolation. Rule 8 Plugging and Abandonment of Iniection Wells (Rescinded this order) Rule 9 Surveillance (Revised this order) For grind -and -inject slurry injection wells, a baseline temperature survey from surface to total depth, initial step -rate test to pressure equal or exceeding maximum injection pressure and pressure falloff are required prior to sustained disposal injection. Regular fill depth tags are required at least once annually or as warranted following consultation with the Commission. For slurry injection wells, an annual performance report will be required including rate and pressure performance, surveillance logging, fill depth, survey results, and volumetric analysis of the disposal storage volume, estimate of fracture growth, if any, and updates of operational plans. Report submission must be on or before April 1, in conjunction with the Alpine Pool Annual Reservoir Report. Rule 10 Notification (Source: AIO 18A) The operator must notify the Commission if it learns of any improper Class Il injection. Additional notification requirements of any other State or Federal agency remain the operators' responsibility. Rule 11 Administrative Actions (Source: AIO 18B) Unless notice and public hearing are otherwise required, the Commission may administratively waive or amend any rule stated above as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in fluid movement outside of the authorized injection zone. Rule 12 Authorized Infection Pressure for Enhanced Recovery (New this order) For the injection interval specified in Rule 1 above pressures will be managed not to exceed the maximum injection gradient of 0.81 psi/ft to ensure containment of injected fluids within the injectional interval. ENTERED at Anchorage, Alaska and dated June 20, 2017. //signature on file// //signature on file// //signature on file// Cathy P. Foerster Daniel T. Seamount, Jr. Hollis S. French Chair, Commissioner Commissioner Commissioner A1018D June 20, 2017 Page 6 of 6 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 eventhe 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. Gordon Severson Penny Vadla P.O. Box 58055 3201 Westmar Cir. 399 W. Riverview Ave. Fairbanks, AK 99711-0055 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639-0309 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706-0868 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Tuesday, June 20, 2017 1:00 PM To: DOA AOGCC Prudhoe Bay; Bender, Makana K (DOA); Bettis, Patricia K (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA); French, Hollis (DOA); Frystacky, Michal (DOA); Guhl, Meredith D (DOA); Kair, Michael N (DOA); Link, Liz M (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Quick, Michael J (DOA); Regg, James B (DOA); Roby, David S (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Wallace, Chris D (DOA); AK, GWO Projects Well Integrity; AKDCWellIntegrityCoordinator; Alan Bailey; Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew VanderJack; Ann Danielson; Anna Raff; Barbara F Fullmer; bbritch; bbohrer@ap.org; Ben Boettger; Bill Bredar; Bob Shavelson; Brandon Viator; Brian Havelock; Bruce Webb; Caleb Conrad; Candi English; Cocklan-Vendl, Mary E; Colleen Miller; Connie Downing; Crandall, Krissell; D Lawrence; Dale Hoffman; Darci Horner; Dave Harbour; David Boelens; David Duffy; David House; David McCaleb; David McCraine; ddonkel@cfl.rr.com; DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elizabeth Harball; Elowe, Kristin; Elwood Brehmer; Evan Osborne; Evans, John R (LDZX); George Pollock; Gordon Pospisil; Greeley, Destin M (DOR); Gretchen Stoddard; gspfoff, Hunter Cox; Hurst, Rona D (DNR); Hyun, James J (DNR); Jacki Rose; Jason Brune; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jill Simek; Jim Watt; Jim White; Joe Lastufka; Radio Kenai; Burdick, John D (DNR); Easton, John R (DNR); Larsen, John M (DOR); John Stuart; Jon Goltz; Chmielowski, Josef (DNR); Juanita Lovett; Judy Stanek; Kari Moriarty; Kasper Kowalewski; Kazeem Adegbola; Keith Torrance; Keith Wiles; Kelly Sperback; Frank, Kevin J (DNR); Kruse, Rebecca D (DNR); Gregersen, Laura S (DNR); Leslie Smith; Lori Nelson; Louisiana Cutler, Luke Keller; Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Mealear Tauch; Michael Bill; Michael Calkins; Michael Moora; Mike Morgan; MJ Loveland; mkm7200; Motteram, Luke A; Mueller, Marta R (DNR); Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nick Ostrovsky; Nikki Martin; NSK Problem Well Supv; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Renan Yanish; Richard Cool; Robert Brelsford; Sara Leverette; Scott Griffith; Shahla Farzan; Shannon Donnelly; Sharon Yarawsky; Skutca, Joseph E (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Stephanie Klemmer; Stephen Hennigan; Sternicki, Oliver R; Moothart, Steve R (DNR); Steve Quinn; Suzanne Gibson; Sheffield@aoga.org; Ted Kramer; Teresa Imm; Thor Cutler; Tim Jones; Tim Mayers; Todd Durkee; 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; David Tetta; Don Shaw; Eppie Hogan ; Eric Lidji; Garrett Haag; Smith, Graham O (DNR); Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Fair, Holly S (DNR); Jamie M. Long; Jason Bergerson; Jesse Chielowski; Jim Magill; Shine, Jim M (DNR); 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); Tostevin, Breck C (LAW); William Van Dyke Subject: AIO 18D Attachments: aiol8d.pdf Please see attached. Re: THE APPLICATION OF ConocoPhillips ) Area Injection Order No. 18D Alaska, Inc. for expansion and contraction of ) Docket Number: AIO-17-003 the Affected Area of Area Injection Order No. ) 18C and the addition of rules pertaining to ) Colville River Field authorized injection pressure and authorized ) Colville River Unit injection fluids, Alpine Oil Pool, Colville River ) Alpine Oil Pool Unit, Arctic Slope, Alaska ) June 20, 2017 Jody J. Colombie AOGCC SpeciaCAssistant .Alaska Oil and Gas Conservation Commission 333 -West 7'ti Avenue .Anchorage, .Alaska 99501 Office: (907) 793-1221 fax: (907) 276-7542 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jody Colombie at 907.793.1221 or iody.colombie@alaska.gov. THE STATE Alaska Oil and Gas °fALASKA Conservation Commission GOVERNOR BILL WALKER CONSERVATION ORDER NO. 443C ERRATA AREA INJECTION ORDER NO. 18D ERRATA Mr. Stephen Thatcher Manager, WNS Development ConocoPhillips Alaska, Inc. ATO -1770 700 G Street Anchorage, AK 99501 Re: Docket Numbers: CO -17-004 & AIO-17-003 Request for reconsideration Conservation Order No. 443C Area Injection Order No. 18D Colville River Unit Alpine Oil Pool Dear Mr. Thatcher: 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov By letter dated June 26, 2017, ConocoPhillips Alaska, Inc. (CPAI) requested reconsideration of Conservation Order No. 443C (CO 443C) and Area Injection Order 18D (AIO 18D) to correct typographical errors. CPAI's request is hereby GRANTED. As pointed out in CPAI's letter CO 443C, which was issued on June 15, 2007, and AIO 18D, which was issued on June 20, 2017, both contain a typographical error in the table showing the legal description of the affected area. Both orders reference sections "22-17 All" of Township 11 North, Range 3 East when the correct citation should be sections "22-27 All". Additionally, Rule 12 of CO 443C states in part "...must not exceed MMCFPD." When it should state "...must not exceed 1 MMCFPD." The Alaska Oil and Gas Conservation Commission will issue errata versions of these two orders to correct the noted typographical errors. DONE at Anchorage, Alaska and dated June 27, 2017. Cathy, . Foerster iel . ount, Jr. 44 /�� Chair, Commissioner V Commissioner CO 443C (Errata) AIO 18D (Errata) June 27, 2017 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 oil 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. l'l 11: S l'ATI. A LAS -KA Ali L !�ti;'ir hi 3. Alaska Oil and Gas Conservation Commission CONSERVATION ORDER NO. 443C ERRATA AREA INJECTION ORDER NO. 18D ERRATA Mr. Stephen Thatcher Manager, WNS Development ConocoPhillips Alaska, Inc. ATO -1770 700 G Street Anchorage, AK 99501 Re: Docket Numbers: CO -17-004 & AIO-17-003 Request for reconsideration Conservation Order No. 443C Area Injection Order No. 18D Colville River Unit Alpine Oil Pool Dear Mr. Thatcher: 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 aogcc.alaska.gov By letter dated June 26, 2017, ConocoPhillips Alaska, Inc. (CPAI) requested reconsideration of Conservation Order No. 443C (CO 443C) and Area Injection Order 18D (AIO 18D) to correct typographical errors. CPAI's request is hereby GRANTED. As pointed out in CPAI's letter CO 443C, which was issued on June 15, 2007, and AIO 18D, which was issued on June 20, 2017, both contain a typographical error in the table showing the legal description of the affected area. Both orders reference sections "22-17 All" of Township 11 North, Range 3 East when the correct citation should be sections "22-27 All". Additionally, Rule 12 of CO 443C states in part "...must not exceed MMCFPD." When it should state "...must not exceed 1 MMCFPD." The Alaska Oil and Gas Conservation Commission will issue errata versions of these two orders to correct the noted typographical errors. DONE at Anchorage, Alaska and dated June 27, 2017. OIL q�,0 //signature on file// //signature on file// //signature on file//" G' Cathy P. Foerster Daniel T. Seamount, Jr. Hollis S. French Chair, Commissioner Commissioner Commissioner �Pj9noN �� CO 443C (Errata) A10 18D (Errata) June 27, 2017 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. Bernie Karl K&K Recycling Inc. Gordon Severson Penny Vadla P.O. Box 58055 3201 Westmar Cir. 399 W. Riverview Ave. Fairbanks, AK 99711-0055 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639-0309 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706-0868 CQ-3o-2c�1� am Singh, Angela K (DOA) From: Colombie, Jody J (DOA) Sent: Wednesday, lune 28, 2017 10:45 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); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA); French, Hollis (DOA); Frystacky, Michal (DOA); Guhl, Meredith D (DOA); Kair, Michael N (DOA); Link, Liz M (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Quick, Michael J (DOA); Regg, James B (DOA); Roby, David S (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Wallace, Chris D (DOA); AK, GWO Projects Well Integrity, AKDCWellIntegrityCoordinator, Alan Bailey, Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew Vanderlack; Ann Danielson; Anna Raff; Barbara F Fullmer, bbritch; bbohrer@ap.org; Ben Boettger; Bill Bredar; Bob Shavelson; Brandon Viator; Brian Havelock; Bruce Webb; Caleb Conrad; Candi English; Cocklan-Vendl, Mary E; Colleen Miller, Connie Downing; Crandall, Krissell; D Lawrence; Dale Hoffman; Darci Horner, Dave Harbour, David Boelens; David Duffy, David House; David McCaleb; David McCraine; ddonkel@cfl.rr.com; DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elizabeth Harball; Elowe, Kristin; Elwood Brehmer; Evan Osborne; Evans, John R (LDZX); George Pollock; Gordon Pospisil; Greeley, Destin M (DOR); Gretchen Stoddard; gspfoff, Hunter Cox; Hurst, Rona D (DNR); Hyun, James J (DNR); Jacki Rose; Jason Brune; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jill Simek; Jim Watt; Jim White; Joe Lastufka; Radio Kenai; Burdick, John D (DNR); Easton, John R (DNR); Larsen, John M (DOR); John Stuart; Jon Goltz; Chmielowski, Josef (DNR); Juanita Lovett; Judy Stanek, Kari Moriarty; Kasper Kowalewski; Kazeem Adegbola; Keith Torrance; Keith Wiles; Kelly Sperback; Frank, Kevin J (DNR); Kruse, Rebecca D (DNR); Gregersen, Laura S (DNR); Leslie Smith; Lori Nelson; Louisiana Cutler, Luke Keller, Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Mealear Tauch; Michael Bill; Michael Calkins; Michael Moora; Mike Morgan; MJ Loveland; mkm7200; Motteram, Luke A; Mueller, Marta R (DNR); Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nick Ostrovsky, Nikki Martin; NSK Problem Well Supv; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Renan Yanish; Richard Cool; Robert Brelsford; Sara Leverette; Scott Griffith; Shahla Farzan; Shannon Donnelly; Sharon Yarawsky; Skutca, Joseph E (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Stephanie Klemmer; Stephen Hennigan; Sternicki, Oliver R; Moothart, Steve R (DNR); Steve Quinn; Suzanne Gibson; sheffield@aoga.org; Ted Kramer, Teresa Imm; 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 1 (DNR); Casey Sullivan; Corey Munk; Don Shaw; Eppie Hogan; Eric Lidji; Garrett Haag; Smith, Graham O (DNR); Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Fair, Holly S (DNR); Jamie M. Long; Jason Bergerson; Jesse Chielowski; Jim Magill; Shine, Jim M (DNR); 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); Tostevin, Breck C (LAW); William Van Dyke Subject: AI018D and C0443C Errata and Amended Orders Attachments: co443c (Errata).pdf, aiol8d (Errata).pdf, C0443C and AI018D Errata.pdf Please see attached. Jody J CoCombie AOGCC Special -Assistant .Alaska OiCand Gas Conservation Commission 333 'Nest 7`h .Avenue Anchorage, Alaska 99501 Office: (907) 793-1221 Fax: (907) 276-7542 CONFIDENTIALITY NOTICE. This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jody Colombie at 907.793.1221 or iody.colombie@alaska.gov. THE STATE °fALASKA GOVERNOR BILL WALKER Ms. Rachel Kautz Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 18D.001 Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-17-027 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1 433 Fax: 907.276.7542 www.aogcc.alaska.gov Request for administrative approval to allow well CD2 -73 (PTD 2081960) to be online in water only injection service with a known outer annulus x atmosphere pressure communication. Colville River Unit (CRU) CD2 -73 (PTD 2081960) Colville River Field Alpine Oil Pool Dear Ms. Kautz: By letter dated August 29, 2017, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 11 of Area Injection Order (AIO) 18D.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 outer annulus (OA) x atmosphere pressure communication to AOGCC on May 2, 2017. CPAI completed diagnostic evaluations including a passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on May 2, 2017 which indicates that CD2 -73 exhibits at least two competent barriers to the release of well pressure. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. AIO 18D.001 August 31, 2017 Page 2 of 2 AOGCC's approval to continue water injection only in CRU CD2 -73 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 (MITIA) every 2 years to the maximum anticipated injection pressure; 4. CPAI shall limit the well's IA operating pressure to 2000 psi and the OA operating pressure to as low as reasonably possible not to exceed 100 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 June 2018. 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 August 31, Cathy. . Foerster Daniel T. mount, Jr. Commissioner Co sioner TION 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. Y1IE STATE "'ALASKA GOVERNOR BILL W.,kLKER Ms. Rachel Kautz Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 18D.001 Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-17-027 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 aogcc.alaska.gov Request for administrative approval to allow well CD2 -73 (PTD 2081960) to be online in water only injection service with a known outer annulus x atmosphere pressure communication. Colville River Unit (CRU) CD2 -73 (PTD 2081960) Colville River Field Alpine Oil Pool Dear Ms. Kautz: By letter dated August 29, 2017, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 11 of Area Injection Order (AIO) I8D.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 outer annulus (OA) x atmosphere pressure communication to AOGCC on May 2, 2017. CPAI completed diagnostic evaluations including a passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on May 2, 2017 which indicates that CD2 -73 exhibits at least two competent barriers to the release of well pressure. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. AIO 18D.001 August 31, 2017 Page 2 of 2 AOGCC's approval to continue water iniection only in CRU CD2 -73 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 (MITIA) every 2 years to the maximum anticipated injection pressure; 4. CPAI shall limit the well's IA operating pressure to 2000 psi and the OA operating pressure to as low as reasonably possible not to exceed 100 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 June 2018. 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 August 31, 2017. aa.,6ta //signature on file// //signature on file// Cathy P. Foerster Daniel T. Seamount, Jr. P; Commissioner Commissioner gran aovs� 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 AOOCC 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 fled. 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. Gordon Severson Penny Vadla P.O. Box 58055 3201 Westmar Cir. 399 W. Riverview Ave. Fairbanks, AK 99711-0055 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 99639-0309 Fairbanks, AK 997060868 me&'a'k_ I-4 -'Zc,k7 QC Singh, Angela K (DOA) From: Carlisle, Samantha J (DOA) Sent: Thursday, August 31, 2017 3:18 PM To: Ballantine, Tab A (LAW); Bender, Makana K (DOA); Bettis, Patricia K (DOA); Bixby, Brian D (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Cook, Guy D (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA); French, Hollis (DOA); Frystacky, Michal (DOA); Guhl, Meredith D (DOA); Herrera, Matthew F (DOA); Jones, Jeffery B (DOA); Kair, Michael N (DOA); Link, Liz M (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Quick, Michael J (DOA); Regg, James B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Wallace, Chris D (DOA); AK, GWO Projects Well Integrity; AKDCWellIntegrityCoordinator; Alan Bailey; Alex Demarban; Alexander Bridge, Alicia Showalter, Allen Huckabay; Andrew Vandedack; 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; 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, Hunter Cox; Hurst, Rona D (DNR); Hyun, James J (DNR); Jacki Rose; Jason Brune; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jill Simek; Jim Watt; Jim White; Joe Lastufka; Radio Kenai; Burdick, John D (DNR); Easton, John R (DNR); Larsen, John M (DOR); John Stuart; Jon Goltz; Chmielowski, Josef (DNR); Juanita Lovett, Judy Stanek, Kari Moriarty; Kasper Kowalewski; Kazeem Adegbola; Keith Torrance; Keith Wiles; Kelly Sperback; Frank, Kevin J (DNR); Kruse, Rebecca D (DNR); Kyla Choquette; Gregersen, Laura S (DNR); Leslie Smith; Lori Nelson; Louisiana Cutler, Luke Keller, Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Mealear Tauch; Michael Bill; Michael Calkins, Michael Moora; Mike Morgan; MJ Loveland; mkm7200, Motteram, Luke A; Mueller, Marta R (DNR); knelson@petroleumnews.com; Nichole Saunders, Nick Ostrovsky, Nikki Martin; NSK Problem Well Supv; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Renan Yanish; Richard Cool; Robert Brelsford; Robert Warthen; Sara Leverette; Scott Griffith; Shahla Farzan; Shannon Donnelly, Sharon Yarawsky; Skutca, Joseph E (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Stephanie Klemmer, Stephen Hennigan; Sternicki, Oliver R; Moothart, Steve R (DNR); Steve Quinn; Suzanne Gibson; sheffield@aoga.org; Ted Kramer, Teresa Imm; 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; Shine, Jim M (DNR); 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 To: Van Dyke Subject: Area Injection Order 18D.001 (Colville River Unit) Attachments: aiol8D.001.pdf Administrative approval to allow well C132-73 (PCD 2081960) to be online in water only injection service with a known outer annulus x atmosphere pressure communication. Samantha Carlisle Executive Secretary III Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 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, and, so that the AOGCC is aware of the mistake in sending it to you, contact Samantha Carlisle at (907) 793-1223 or Samantha.Carhsle@alaska.eov. THE STATE °fALASKA Alaska Oil and Gas Conservation Commission 333 west Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 18D.001 CANCELLATION Mr. Travis Smith Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-18-015 Request to cancel Area Injection Order (AIO) 18D.001 Colville River Unit (CRU) CD2 -73 (PTD 2081960) Colville River Field Alpine Oil Pool Dear Mr. Smith: By letter dated February 28, 2018, ConocoPhillips Alaska, Inc. (CPAI) requested cancellation of administrative approval (AA) Area Injection Order 18D.001. In accordance with Rule 11 of Area Injection Order (AIO) 18D.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request to cancel the AA. CRU CD2 -73 developed a surface casing (outer annulus) leak to atmosphere and on August 31, 2017 the AOGCC issued AIO 18D.001 (corrected on September 21, 2017). AOGCC determined that water injection could safely continue if CPAI complied with the restrictive conditions set out in AA AIO 18D.001. CPAI has performed a rig workover of CD2 -73 in February 2018 which repaired the surface casing leak. AA AIO 18D.001 is no longer necessary to the operation of CD2 -73 and is hereby CANCELLED. Injection into CD2 -73 will be governed by provisions of AIO No. 18D. AIO 18D.001 Cancellation March 6, 2018 Page 2 of 2 DONE at Anchorage, Alaska and dated March 6, 2018. Hollis French Chair. Commissioner 4qr6'0"- /'/� Daniel T. Seamount, Jr. Commissioner 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 m 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 he 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 oftime above, the date ofthe event or default after which the designated period begins to mn 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 eventthe period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Tuesday, March 06, 2018 11:06 AM To: DOA AOGCC Prudhoe Bay; Bender, Makana K (DOA sponsored); Bettis, Patricia K (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Davies, Stephen F (DOA); Foerster, Catherine P (DOA); French, Hollis (DOA); Frystacky, Michal (DOA); Guhl, Meredith D (DOA); Kair, Michael N (DOA); Link, Liz M (DOA); Loepp, Victoria T (DOA); McPhee, Megan S (DOA); Rixse, Melvin G (DOA); Mumm, Joseph (DOA sponsored); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Ballantine, Tab A (LAW); Erickson, Tamara K (DOA); Wallace, Chris D (DOA); AK, GWO Projects Well Integrity; AKDCWellIntegrityCoordinator; Alan Bailey; Alex Demarban; Alicia Showalter; Allen Huckabay; Andrew Vanderlack; Ann Danielson; Anna Lewallen; Anna Raff; Barbara F Fullmer, bbritch; bbohrer@ap.org; Ben Boettger, Bill Bredar; Bob Shavelson; Bonnie Bailey, Brandon Viator; Brian Havelock, Bruce Webb; Caleb Conrad; Candi English; Cody Gauer; Cody Terrell; Colleen Miller, Connie Downing; Crandall, Krissell; D Lawrence; Dale Hoffman; Danielle Mercurio; Darci Horner; Dave Harbour, David Boelens; David Duffy; David House; David McCaleb; 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 1 (DNR); Jacki Rose; Jason Brune; Jdarlington (arlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jill Simek; Jim Shine; Jim Watt; Jim White; Young, Jim P (DNR); Joe Lastufka; Radio Kenai; Burdick, John D (DNR); Easton, John R (DNR); Larsen, John M (DOR); Jon Goltz; Chmielowski, Josef (DNR); Joshua Stephen; Juanita Lovett, Judy Stanek; Kari Moriarty; Kasper Kowalewski; Kazeem Adegbola; Keith Torrance; Keith Wiles; Kelly Sperback; Frank, Kevin 1 (DNR); Kruse, Rebecca D (DNR); Kyla Choquette; Gregersen, Laura S (DNR); Leslie Smith; Lori Nelson; Luke Keller; Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Michael Bill; Michael Calkins; Michael Moora; Michael Quick, Michael Schoetz; Mike Morgan; MJ Loveland; mkm7200; Motteram, Luke A; Mueller, Marta R (DNR); Nathaniel Herz; knelson@petroleumnews.com; Nichole Saunders; Nick Ostrovsky; NSK Problem Well Supv; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Renan Yanish; Richard Cool; Robert Brelsford; Robert Warthen; Ryan Gross; Sara Leverette; Scott Griffith; Shahla Farzan; Shannon Donnelly; Sharon Yarawsky; Skutca, Joseph E (DNR); Smith, Kyle S (DNR); Stephanie Klemmer; Stephen Hennigan; Sternicki, Oliver R, Moothart, Steve R (DNR); Steve Quinn; Suzanne Gibson; sheffield@aoga.org; Tanisha Gleason; Ted Kramer; Teresa Imm; Tim Jones; Tim Mayers; Todd Durkee; Tom Maloney, trmjrl; Tyler Senden; Umekwe, Maduabuchi P (DNR); Vinnie Catalano; Well Integrity; Well Integrity; Weston Nash; Whitney Pettus; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andy Bond; Bajsarowicz, Caroline J; Bruce Williams; Casey Sullivan; Corey Munk; D. McCraine; Don Shaw, Eppie Hogan; Eric Lidji; Garrett Haag; Smith, Graham O (DNR); Heusser, Heather A (DNR); Fair, Holly S (DNR); Jamie M. Long; Jason Bergerson; Jesse Chielowski; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Keith Lopez; Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Melonnie Amundson; Franger, James M (DNR); Morgan, Kirk A (DNR); Umekwe, Maduabuchi P (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Rachel Davis; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); William Van Dyke Subject: AIO 18D.001 (Cancellation) Attachments: aio18D.001 cancellation.pdf Please see attached. Docket Number: AIO-18-015 Request to cancel Area Injection Order (AIO) 18D.001 Colville River Unit (CRU) CD2 -73 (PTD 2081960) Jody J. CoCombie .AOGCC SyeciaC Assistant Alaska.OifandGas Conservation Commission 333 west 711 .Avenue .Anchorage, ACaska 99501 Office: (907) 793-1221 Fax: (907) 276-7542 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC(, State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jody Colombie at 907.793.1221 or iodv.colombie@oloska.aov. Bernie Karl K&K Recycling Inc. Gordon Severson Penny Vadla P.O. Box 58055 3201 Westmar Cir. 399 W. Riverview Ave. Fairbanks, AK 99711 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 George Vaught, Jr. Darwin Waldsmith Richard Wagner P.O. Box 13557 P.O. Box 39309 P.O. Box 60868 Denver, CO 80201-3557 Ninilchik, AK 99639 Fairbanks, AK 99706 THE STATE °fALASKA 1.1. GOVERNOR BILL WALKER Alaska Oil and Gas Conservation Commission CORRECTED ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 18D.001 Ms. Rachel Kautz 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 W Wva.a0gcc.alaska.g0v Re: Docket Number: AIO-17-027 Request for administrative approval to allow well CD2 -73 (PTD 2081960) to be online in water only injection service with a known outer annulus x atmosphere pressure communication. Colville River Unit (CRU) C132-73 (PTD 2081960) Colville River Field Alpine Oil Pool Dear Ms. Kautz: By letter dated August 29, 2017, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 11 of Area Injection Order (AIO) 18D.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 outer annulus (OA) x atmosphere pressure communication to AOGCC on May 2, 2017. CPAI completed diagnostic evaluations including a passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on May 2, 2017 which indicates that CD2 -73 exhibits at least two competent barriers to the release of well pressure. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. AIO 18D.001 Corrected September 21, 2017 Page 2 of 2 AOGCC's approval to continue water injection only in CRU CD2 -73 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, pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. CPAI shall perform a mechanical integrity test of the inner annulus 4. 5. 6. 7. years to the maximum anticipated injection pressure; injection rates, and (MITIA) every 2 CPAI shall limit the well's IA operating pressure to 2000 psi and the OA operating pressure to as low as reasonably possible not to exceed 250 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 June 2018. 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 September 21, 2017 nuc pr Cathy/P. Foerster Commissioner Daniel T. Seamount, Jr. Commissioner 7. RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. THE SfATF °ALASKA 60 VERWR BILL WALKER Alaska Oil and Gas Conservation Commission CORRECTED ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 18D.001 Ms. Rachel Kautz 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 aogcc.olaska.gov Re: Docket Number: AIO-17-027 Request for administrative approval to allow well CD2 -73 (PTD 2081960) to be online in water only injection service with a known outer annulus x atmosphere pressure communication. Colville River Unit (CRU) CD2 -73 (PTD 2081960) Colville River Field Alpine Oil Pool Dear Ms. Kautz: By letter dated August 29, 2017, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 11 of Area Injection Order (AIO) 18D.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 outer annulus (OA) x atmosphere pressure communication to AOGCC on May 2, 2017. CPAI completed diagnostic evaluations including a passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on May 2, 2017 which indicates that CD2 -73 exhibits at least two competent barriers to the release of well pressure. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. ATO 18D.001 Corrected September 21, 2017 Page 2 of 2 AOGCC's approval to continue water iniection only in CRU CD2 -73 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 (MITIA) every 2 years to the maximum anticipated injection pressure; 4. CPAI shall limit the well's IA operating pressure to 2000 psi and the OA operating pressure to as low as reasonably possible not to exceed 250 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 June 2018. 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 September 21, 2017 nuc pro tunc August 31, 2017. OIL NQ //signature on file// //signature on file// Cathy P. Foerster Daniel T. Seamount, Jr. _ Commissioner Commissioner fl�rrON co', •�. NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. if the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to ran is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Bernie Karl K&K Recycling Inc. Gordon Severson Penny Vadla P.O. Box 58055 3201 Westmar Cir. 399 W. Riverview Ave. Fairbanks, AK 99711-0055 Anchorage, AK 995084336 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 99639-0309 Fairbanks, AK 99706-0868 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Thursday, September 21, 2017 11:10 AM To: aogcc.inspectors@alaska.gov, Well Integrity; Bender, Makana K (DOA) (makana.bender@alaska.gov); Bettis, Patricia K (DOA) (patricia.bettis@alaska.gov); Brooks, Phoebe L (DOA) (phoebe.brooks@alaska.gov); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA) oody.colombie@alaska.gov); Davies, Stephen F (DOA) (steve.davies@alaska.gov); Foerster, Catherine P (DOA) (cathy.foerster@alaska.gov); French, Hollis (DOA); Frystacky, Michal (michal.frystacky@alaska.gov); Guhl, Meredith (DOA sponsored) (meredith.guhl@alaska.gov); Kair, Michael N (DOA); Link, Liz M (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored) Qoseph.mumm@alaska.gov); Paladijczuk, Tracie L (DOA) (tracie.paladijczuk@alaska.gov); Pasqual, Maria (DOA) (maria.pasqual@alaska.gov); Quick, Michael (DOA sponsored); Regg, James B (DOA) (im.regg@alaska.gov); Roby, David S (DOA) (dave.roby@alaska.gov); Schwartz, Guy L (DOA) (guy.schwartz@alaska.gov); Seamount, Dan T (DOA) (dan.seamount@alaska.gov); Singh, Angela K (DOA); Wallace, Chris D (DOA) (chris.wallace@alaska.gov); AK, GWO Projects Well Integrity, AKDCWeIIIntegrityCoordinator, Alan Bailey; Alex Demarban; Alicia Showalter; Allen Huckabay; Andrew Vanderlack; Ann Danielson; Anna Raff; Barbara F Fullmer; bbritch; Becky Bohrer; Ben Boettger; Bill Bredar, Bob; 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; Darci Horner, Dave Harbour, David Boelens; David Duffy; David House; David McCaleb; David McCraine; ddonkel@cfl.rr.com; Diemer, Kenneth J (DNR); DNROG Units; Donna Ambruz; Ed Jones; Elizabeth Harball; Elowe, Kristin; Elwood Brehmer; Evan Osborne; Evans, John R (LDZX); Garrett Brown; George Pollock; Gordon Pospisil; Greeley, Destin M (DOR); Gretchen Stoddard; gspfoff, Hunter Cox; Hurst, Rona D (DNR); Hyun, James J (DNR); Jacki Rose; Jason Brune, Jdarlington (arlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jill Simek; Jim Watt; Jim White; Joe Lastufka; Joe Nicks; John Burdick, John Easton; John Larsen; John Stuart; Jon Goltz; Josef Chmielowski; Juanita Lovett; Judy Stanek; Kari Moriarty; Kasper Kowalewski; Kazeem Adegbola; Keith Torrance; Keith Wiles; Kelly Sperback; Kevin Frank, Kruse, Rebecca D (DNR); Kyla Choquette; Laura Silliphant (laura.gregersen@alaska.gov); Leslie Smith; Lori Nelson; Luke Keller; Marc Kovak; Mark Dalton; Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Mealear Tauch; Michael Bill; Michael Calkins; Michael Moora; Mike Morgan; MJ Loveland; mkm7200; Motteram, Luke A; Mueller, Marta R (DNR); nelson; Nichole Saunders; Nick Ostrovsky, Nikki Martin; NSK Problem Well Supv; Patty Alfaro; Paul Craig; Paul Decker (paul.decker@alaska.gov); 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); Smart Energy Universe; Smith, Kyle S (DNR); Stephanie Klemmer; Stephen Hennigan; Sternicki, Oliver R; Steve Moothart (steve.moothart@alaska.gov); Steve Quinn; Suzanne Gibson; Tamera Sheffield; Ted Kramer; Teresa Imm; Tim Jones; Tim Mayers; Todd Durkee; Tom Maloney; trmjrl; Tyler Senden; Umekwe, Maduabuchi P (DNR); Vinnie Catalano; 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; Graham Smith; Heusser, Heather A (DNR); Holly Fair, Jamie M. Long; Jason Bergerson; Jesse Chielowski; Jim Magill; Jim Shine; Joe Longo; John Martineck, Josh Kindred; Keith Lopez, Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck, Marcia Hobson; Marie Steele; Matt Armstrong; Melonnie Amundson; Mike Franger; Morgan, Kirk A (DNR); Pascal Umekwe; Pat Galvin; Pete Dickinson; Peter Contreras; Rachel Davis; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Susan Pollard; Talib Syed; Tina Grovier (tmgrovier@stoel.com); William Van Dyke Cc: 'Tyler Senden' Subject: Corrected AIO 18D.001 Attachments: aio18D.001 Corrected.pdf Please see attached. Corrected Re: Docket Number: A10-1 7-027 Request for administrative approval to allow well CD2 -73 (PTD 2081960) to be online in water only injection service with a known outer annulus x atmosphere pressure communication. Colville River Unit (CRU) CD2 -73 (PTD 2081960) Colville River Field Alpine Oil Pool Jody J. Cotombie A015CC Speciat.rlssistant Alaska OitandGas Conservation Commission 333 West;,"' Avenue Anchorage, Alaska 9,95oi Office: (907) 793-1221 Fax: (907) 276-7542 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jody Colombie at 907.793.1221 or iodv.colombie@alaska aov. THE STATE °fALASKA GOVERNOR BILL WALKER Mr. Travis Smith Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 18D.002 Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-17-035 333 west Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1 433 Fax: 907.276.7542 www.aogcc.claska.gov Request for administrative approval to allow well CD2 -55 (PTD 2031180) to be online in water only injection service with a known tubing by inner annulus communication. Colville River Unit (CRU) C132-55 (PTD 2031180) Colville River Field Alpine Oil Pool Dear Mr. Smith: By letter dated October 12, 2017, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 11 of Area Injection Order (AIO) 18D.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) x Inner Annulus (IA) pressure communication to AOGCC on July 25, 2017 while the well was on miscible gas injection. CPAI performed diagnostics including a passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on August 4, 2017 which indicates that CD2 -55 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 18D.002 October 23, 2017 Page 2 of 2 AOGCC's approval to continue water injection only in CRU CD2 -55 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 maximum anticipated injection pressure; 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 shalt be required to restart injection; and 7. The next required MIT is to be before or during the month of June 2018. 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, 2017. Cathy 11. Foerster Daniel T. Seamount, Jr. Commissioner Commissioner As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC rants for good muse 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. TI IE STAFF °ALASKA (.�tri'BRNttR f, I L L WAIKiP Mr. Travis Smith Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 18D.002 Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-17-035 333 West Seventh Avenue Anchorage. Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 aogcc.alaska.gov Request for administrative approval to allow well CD2 -55 (PTD 2031180) to be online in water only injection service with a known tubing by inner annulus communication. Colville River Unit (CRU) CD2 -55 (PTD 2031180) Colville River Field Alpine Oil Pool Dear Mr. Smith: By letter dated October 12, 2017, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 11 of Area Injection Order (AIO) 18D.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) x Inner Annulus (IA) pressure communication to AOGCC on July 25, 2017 while the well was on miscible gas injection. CPAI performed diagnostics including a passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on August 4, 2017 which indicates that CD2 -55 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 18D.002 October 23, 2017 Page 2 of 2 AOGCC's approval to continue water injection only in CRU CD2 -55 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 maximum anticipated injection pressure; 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 June 2018. 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, 2017. //signature on file// Cathy P. Foerster Commissioner //signature on file// Daniel T. Seamount, Jr. Commissioner AND APPEAL As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Colombie, Jody J (DOA) From: Colombie, Jody 1 (DOA) Sent: Monday, October 23, 2017 11:56 AM To: DOA AOGCC Prudhoe Bay; Ballantine, Tab A (LAW); 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); Quick, Michael J (DOA); Regg, James B (DOA); Roby, David S (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Wallace, Chris D (DOA); AK, GWO Projects Well Integrity, AKDCWellIntegrityCoordinator, Alan Bailey, Alex Demarban; Alicia Showalter; Allen Huckabay; Andrew Vandedack, 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; 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, Hunter Cox; Hurst, Rona D (DNR); Hyun, James 1 (DNR); Jacki Rose; Jason Brune; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jill Simek; Jim Watt; Jim White; Joe Lastufka; Radio Kenai; Burdick, John D (DNR); Easton, John R (DNR); Larsen, John M (DOR); John Stuart, Jon Goltz; Chmielowski, Josef (DNR); Juanita Lovett; Judy Stanek; Kari Moriarty; Kasper Kowalewski; Kazeem Adegbola; Keith Torrance; Keith Wiles; Kelly Sperback; Frank, Kevin J (DNR); Kruse, Rebecca D (DNR); Kyla Choquette; Gregersen, Laura S (DNR); Leslie Smith; Lori Nelson; Luke Keller; Marc Koval; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Mealear Tauch; Michael Bill; Michael Calkins; Michael Moora; Mike Morgan; MJ Loveland; mkm7200; Motteram, Luke A; Mueller, Marta R (DNR); 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); Smart Energy Universe; Smith, Kyle S (DNR); Stephanie Klemmer; Stephen Hennigan; Sternicki, Oliver R; Moothart, Steve R (DNR); Steve Quinn; Suzanne Gibson; sheffield@aoga.org; 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; Shine, Jim M (DNR); 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 18D.002 Attachments: aiol8D.002.pdf Please see attached. Re: Docket Number: AIO-17-035 Request for administrative approval to allow well CD2 -55 (PTD 2031180) to be online in water only injection service with a known tubing by inner annulus communication. Colville River Unit (CRU) CD2 -55 (PTD 2031180) Colville River Field Alpine Oil Pool Jody J. Coi(ombie .AOqCC SpeciaC.Assistant .Alaska OiCandgas Conservation Commission 333 -West 7'F Avenue .Anchorage, Alaska 99501 Office: (907) 793-1221 Fax: (907) 276-7542 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC(, State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jody Colombie at 907.793.1221 or iodv.colombie0alaska.aov. THE STATE °1LASKA .L 1. GOVERNOR BILL WALKER Ms. Rachel Kautz Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 18D.003 Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-18-040 333 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 CD2 -02 (PTD 2051090) to be online in water only injection service with a known tubing by inner annulus communication. Colville River Unit (CRU) CD2 -02 (PTD 2051090) Colville River Field Alpine Oil Pool Dear Ms. Kautz: By letter dated October 29, 2018, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 11 of Area Injection Order (AIO) 18D.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 June 26, 2018 while the well was on miscible gas injection. CPAI WAG'ed the well to water for an AOGCC approved monitor period in which communication was not observed. CPAI WAG'ed the well back to miscible gas injection for an additional monitoring period and confirmed the TxIA communication. CPAI performed diagnostics including a state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on June 27, 2018 which indicates that CD2 -02 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 18D.003 November 2, 2018 Page 2 of 2 AOGCC's approval to continue water injection only in CRU CD2 -02 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 maximum anticipated injection pressure; 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 June 2020. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent tes for pad testing. DONE at Anchorage, Alaska and dated November 2, 2018. Hollis S. French Cath P. Foerster Daniel T. Seamount, Jr. Chair, Commissioner Commissioner Commissioner As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. THE STATE °fALASKA GOVERNOR BILL WALKER Ms. Rachel Kautz Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 18D.003 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 oogcc.olaska.gov Re: Docket Number: AIO- 18-040 Request for administrative approval to allow well CD2 -02 (PTD 2051090) to be online in water only injection service with a known tubing by inner annulus communication. Colville River Unit (CRU) CD2 -02 (PTD 2051090) Colville River Field Alpine Oil Pool Dear Ms. Kautz: By letter dated October 29, 2018, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 11 of Area Injection Order (AIO) 18D.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 June 26, 2018 while the well was on miscible gas injection. CPAI WAG'ed the well to water for an AOGCC approved monitor period in which communication was not observed. CPAI WAG'ed the well back to miscible gas injection for an additional monitoring period and confirmed the TxIA communication. CPAI performed diagnostics including a state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on June 27, 2018 which indicates that C132-02 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. Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 Penny Vadla 399 W. Riverview Ave. Soldotna, AK 99669-7714 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 THE STATE °fALASKA Alaska Oil and Gas Conservation Commission GOVERNOR MIKE DUNLEAVY 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 ww .aogcc.olaska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 18D.004 Ms. Sara Carlisle Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-18-046 Request for administrative approval to allow well CD5-316 (PTD 2170400) to be online in water only injection service with a known tubing by inner annulus communication. Colville River Unit (CRU) CD5-316 (PTD 2170400) Colville River Field Alpine Oil Pool Dear Ms. Carlisle: By letter dated December 2, 2018, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 11 of Area Injection Order (AIO) 18D.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 October 27, 2018 while the well was on miscible gas injection. CPAI performed diagnostics including a non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on October 29, 2018 which indicates that CD5-316 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. A10 18D.004 December 10, 2018 Page 2 of 2 AOGCC's approval to continue water injection only in CRU CD5-316 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 maximum anticipated injection pressure, 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 2019. 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 December 10, 2018. Hollis S. French Chair, Commissioner Daniel Daniel T. Seamount, Jr. Commissioner As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 18D.004 Ms. Sara Carlisle Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-18-046 333 west Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.oloska.gov Request for administrative approval to allow well CD5-316 (PTD 2170400) to be online in water only injection service with a known tubing by inner annulus communication. Colville River Unit (CRU) CD5-316 (PTD 2170400) Colville River Field Alpine Oil Pool Dear Ms. Carlisle: By letter dated December 2, 2018, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 11 of Area Injection Order (AIO) 18D.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 October 27, 2018 while the well was on miscible gas injection. CPAI performed diagnostics including a non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on October 29, 2018 which indicates that CD5-316 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. Bernie Karl K&K Recycling Inc. Gordon Severson Penny Vadla P.O. Box 58055 3201 Westmar Cir. 399 W. Riverview Ave. Fairbanks, AK 99711 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 George Vaught, Jr. Darwin Waldsmith Richard Wagner P.O. Box 13557 P.O. Box 39309 P.O. Box 60868 Denver, CO 80201-3557 Ninilchik, AK 99639 Fairbanks, AK 99706 voo A THE STATE °fALASKA GOVERNOR BILL WALKER Ms. Rachel Kautz Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 18D.005 Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-19-018 333 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 CD4 -12 (PTD 2100910) to be online in water only injection service with a known tubing by inner annulus communication. Colville River Unit (CRU) CD4 -12 (PTD 2100910) Colville River Field Alpine Oil Pool Dear Ms. Kautz: By letter dated May 6, 2019, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 11 of Area Injection Order (AIO) 18D.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 March 30, 2019 while the well was on miscible gas injection. CPAI performed diagnostics including a non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on March 30, 2019 which indicates that CD4 -12 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. A10 18D.005 May 15, 2019 Page 2 of 2 AOGCC's approval to continue water injection only in CRU CD4 -12 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 maximum anticipated injection pressure, 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; bol 7 After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and The next required MIT is to be before or during the month of June 2019. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent test schedule forpad testing. DONE at Anchorage, Alaska and dated May 15, 2/0199. — ov Daniel T. Seamount, Jr. Jeskk L. Chmielowski Commissioner Commissioner NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to ran is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m, on the next day that does not fall on a weekend or state holiday. THE STATE °ALASKA GOVERNOR MICHAEL I. DUNLEA\•'Y Ms. Rachel Kautz Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 18D.005 Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-19-018 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.olaska.gov Request for administrative approval to allow well CD4 -12 (PTD 2100910) to be online in water only injection service with a known tubing by inner annulus communication. Colville River Unit (CRU) CD4 -12 (PTD 2100910) Colville River Field Alpine Oil Pool Dear Ms. Kautz: By letter dated May 6, 2019, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 11 of Area Injection Order (AIO) 18D.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 March 30, 2019 while the well was on miscible gas injection. CPAI performed diagnostics including a non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on March 30, 2019 which indicates that CD4 -12 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 18D.005 May 15, 2019 Page 2 of 2 AOGCC's approval to continue water infection only in CRU CD4 -12 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 maximum anticipated injection pressure, 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 June 2019. 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 May 15, 2019. //signature on file// Daniel T. Seamount, Jr. Commissioner //signature on file// Jessie L. Chmielowski Commissioner As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by iL 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. 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 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 18D.005 AMENDED Ms. Kathleen Dodson Well Integrity Specialist ConocoPhillips Alaska, Inc. P.O. Box 1000360 Anchorage, AK 99510 Re: Docket Number: AIO-23-005 Request to Amend Area Injection Order 18D.005; Water Alternating Gas Injection Colville River Unit (CRU) CD4-12 (PTD 2100910), Alpine Oil Pool Dear Ms. Dodson: By emailed letter dated February 21, 2023, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to amend Area Injection Order (AIO) 18D.005to include water alternating gas (WAG) injection with a known tubing by inner annulus (TxIA) pressure communication. In accordance with 20AAC 25.556(d), the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS, subject to conditions,CPAI’s requestto amend the administrative approval to continue WAG injection in the subject well. CPAI reported a potential TxIA pressure communication to AOGCC on March 30, 2019, while the well was on miscible gas injection. CPAI performed diagnostics and confirmed the TxIA pressure communication was only present during gas injection. AOGCC issued AIO 18D.005 on May 15, 2019, restricting the well to water only injection. CPAI has recently changed an internal policy to allow WAG injection in wells that have casing rated to support the higher pressures of gas injection should a barrier fail, and that can meet stringent testing criteria. CPAI has performed additional diagnostics including a passing non-state witnessed mechanical integrity test (MIT) of the inner annulus (to a test pressure greater than the anticipated gas injection pressure of 3,900 psi) on December 22, 2022. This indicates that CD4- 12 exhibits at least two competent barriers to the release of well pressure. CPAI has installed an injection line choke and surface safety valve (SSV) on CD4-12. Both of these devices have remote shut down capability by the Board Operator. Combining this with live transmitters on the inner and outer annulus and the alarm functions in the Supervisory Control and Data Acquisition (SCADA) system create robust layers of protection from an over pressure event. These inner and outer annulus alarms and shut-in protocols combined with the planned inner and outer annulus operating pressure limits enable AOGCC to remove the original water only restriction and re-authorize gas injection. AOGCC believes CPAI can safely manage the TxIA communication with periodic pressure bleeds by maintaining the inner annulus AIO 18D.005 Amended March 2, 2023 Page 2 of 3 to a pressure not to exceed 2,400 psi when on gas injection and 2,000 psi when injecting water. Accordingly, the AOGCC believes that the well’s condition does not compromise overall well integrity so as to threaten human safety or the environment. AOGCC’s approval to continue WAG injection in CRU CD4-12 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 MIT of the inner annulus every two years to the greater of the maximum anticipated injection pressure or 0.25 x packer TVD, but not less than 1,500 psi; 4) CPAI shall limit the well’s inner annulus operating pressure to 2,400 psi during gas injection and 2,000 psi during water injection. Audible control room alarms shall be set at or below these limits; 5) CPAI shall limit the well’s outer annulus operating pressure to 1,000 psi. Audible control room alarms shall be set at or below these limits; 6) CPAI shall monitor the inner and outer annulus pressures in real time with its SCADA system; 7) CPAI shall maintain the injection line choke and surface safety valve (SSV) remote shut down capability. During gas injection, the IA protocols will include a drill site operator alarm set at 2,200 psi, and a high alarm set at 2,400 psi that will prompt the control room Board Operator to remotely shut in the choke or SSV; 8) CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 9) After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 10) The next required MIT is to be before or during the month of June 2023. 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 March 2, 2023. Brett W. Huber, Sr Jessie L. Chmielowski Chair, Commissioner Commissioner Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2023.03.02 11:12:16 -09'00' Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.03.02 11:21:52 -09'00' AIO 18D.005 Amended March 2, 2023 Page 3 of 3 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:Carlisle, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Area Injection Order 18D.005 amended (CRU) Date:Thursday, March 2, 2023 11:42:24 AM Attachments:aio18D.005 amended.pdf Docket Number: AIO-23-005 Request to Amend Area Injection Order 18D.005; Water Alternating Gas Injection Colville River Unit (CRU) CD4-12 (PTD 2100910), Alpine Oil Pool Samantha Carlisle AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: samantha.carlisle@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.carlisle%40alaska.gov Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 mailed 3/6/23 THE STATE ALASKA GOVERNOR MIKE DUNLEAVY Ms. Rachel Kautz Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 18D.006 Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-19-030 333 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 CD5-06 (PTD 2160770) to be online in water only injection service with a known inner annulus (IA) repressurization. Colville River Unit (CRU) CD5-06 (PTD 2160770) Colville River Field Alpine Oil Pool Dear Ms. Kautz: By letter dated September 28, 2019, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 11 of Area Injection Order (AIO) 18D.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 Inner Annulus (IA) repressurization to AOGCC on August 6, 2019 while the well was on miscible gas injection (MI). CPAI had just performed a passing state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on August 3, 2019 which indicated that CD5-06 exhibits at least two competent barriers to the release of well pressure. CPAI performed additional diagnostics including monitoring the well on MI where the repressurization was confirmed, requiring several bleeds. CPAI then WAG'ed the well from MI to water injection for an additional monitoring period. 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 18D.006 October 7, 2019 Page 2 of 2 AOGCC's approval to continue water injection only in CRU CD5-06 is conditioned upon the 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 2021. 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 7, 2019. ®re.y4 Price Jessie L. Chmielowski Chair, Commissioner Commissioner 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 afterwhich 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. PIL S1 ATF ,ALASKA (�(1%F6Ri`1()R NII(. HAE t. I IIUNU AV Ms. Rachel Kautz Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 18D.006 Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-19-030 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.olaska.gov Request for administrative approval to allow well CD5-06 (PTD 2160770) to be online in water only injection service with a known inner annulus (IA) repressurization. Colville River Unit (CRU) CD5-06 (PTD 2160770) Colville River Field Alpine Oil Pool Dear Ms. Kautz: By letter dated September 28, 2019, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 11 of Area Injection Order (AIO) 18D.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 Inner Annulus (IA) repressurization to AOGCC on August 6, 2019 while the well was on miscible gas injection (MI). CPAI had just performed a passing state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on August 3, 2019 which indicated that CD5-06 exhibits at least two competent barriers to the release of well pressure. CPAI performed additional diagnostics including monitoring the well on MI where the repressurization was confirmed, requiring several bleeds. CPAI then WAG'ed the well from MI to water injection for an additional monitoring period. 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 18D.006 October 7, 2019 Page 2 of 2 AOGCC's approval to continue water injection only in CRU CD5-06 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 2021. 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 7, 2019. 01LAryQ //signature on file// //signature on file// " Jeremy M. Price Jessie L. Chmielowski °'�H R °$ Chair, Commissioner Commissioner fe"gnnHo0 As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to ran is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. 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. P.O. Box 13557 Denver, CO 80201-3557 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 THE STA"I'E °fALASKA (A)%+RN0RMIKLUUN1I AVi Alaska Oil and Gas Conservation Commission 333 west Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.cogcc.aloskc.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 18D.004 CANCELLATION Mr. Travis Smith Well Integrity Engineer ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-21-002 Request to cancel Area Injection Order (AIO) 18D.004 Colville River Unit (CRU) CDS-316 (PTD 2170400) Colville River Field Alpine Oil Pool Dear Mr. Smith: By letter dated January 27, 2021, ConocoPhillips Alaska, Inc. (CPAI) requested cancellation of administrative approval (AA) AIO 18D.004. In accordance with Rule 11 of Area Injection Order (AIO) 18D.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request to cancel the AA. CPAI reported a potential tubing (T) by Inner Annulus (IA) pressure communication to AOGCC on October 27, 2018 while the well was injecting miscible gas. On December 10, 2018 AOGCC issued AIO 18D.004. AOGCC determined that water only injection could safely continue if CPAI complied with the restrictive conditions set out in AA All 18D.004. CPAI has repaired the well on August 23, 2020. Monitoring over 30 days of gas injection shows no indications of a TxIA pressure communication. AA AIO 18D.004 is no longer necessary to the operation of CDS-316 and is hereby CANCELLED. AIO 18D.004 Cancellation February 3, 2021 Page 2 of 2 DONE at Anchorage, Alaska and dated February 3, 2021. gglblly signed by Jeremy Dlgllaay signed by Daniel T. Jessie L. Jessie L signpdby Jessie02112.lowskl Jeremy M. Pdre M. Price case 2021.02.03 DaNeR.5eam0unt,lc Seamount,Jr.Detr.2021a2a3 Chmielowskioagzoz,.ozoa Ib.I83ad9'°0' 083653-09'°°' 08:59:56 -09W Jeremy M. Price Daniel T. Seamount, Jr. Jessie L. Chmielowski Chair, Commissioner Commissioner Commissioner As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration most set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Colombie, Jody J (CED) From: Colombie, Jody J (CED) <jody.colombie@alaska.gov> Sent: Wednesday, February 3, 2021 12:57 PM To: AOGCC Public Notices Subject: [AOGCC_Public_Notices] aiol8D.004 Attachments: aiol8D.004 cancel lation.pdf Categories: Yellow Category Re: Docket Number: AIO-21-002 Request to cancel Area Injection Order (AIO) 18D.004 Colville River Unit (CRU) CD5-316 (PTD 2170400) Colville River Field Alpine Oil Pool Jody J. Colombie AOGCC Special Assistant Alaska Oil and Gas Conservation Commission State of Alaska 333 West 7`" Avenue Anchorage, AK 99501 Phone Number : 907-793-1221 Email: jody.colombie@alaska.gov List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: ]ody.colombie@alaska.gov Unsubscribe at: http:Hlist.state.ak.us/mailman/options/aogcc_public_notices/]ody.colombie%40alaska.gov Karl K&K Gordon Severson Richard Wagner K&K Recycling Inc. 3201 Westmar Cir. P.O. Box 60868 Fairbanks,, AAK 99711 P.O. Box Anchorage, AK 99508-4336 Fairbanks, AK 99706 K George Vaught, Jr. Darwin Waldsmith P.O. Box 13557 P.O. Box 39309 Denver, CO 80201-3557 Ninilchik, AK 99639 l/ 1 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. 18D.006 AMENDED September 13, 2021 Mr. Travis Smith Well Intervention & Integrity Engineer ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-21-021 Request to Amend Area Injection Order 18D.006: Water Alternating Gas Injection Operations Colville River Unit (CRU) CD5-06 (PTD 2160770), Alpine Oil Pool Dear Mr. Smith: By letter dated August 17, 2021, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to amend Area Injection Order (AIO) 18D.006 to include water alternating gas (WAG) injection with a known inner annulus (IA) repressurization. In accordance with 20AAC 25.556(d)1, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS, subject to conditions, CPAI’s request to amend the administrative approval to continue WAG injection in the subject well. CPAI reported a potential IA repressurization to AOGCC on August 6, 2019, while the well was on miscible gas injection (MI). CPAI performed diagnostics and confirmed the IA repressurization was only present during gas injection. AOGCC issued AIO 18D.006 on October 7, 2019, restricting the well to water-only injection. CPAI has performed additional diagnostics including a passing state-witnessed mechanical integrity test (MIT) of the inner annulus (to a test pressure greater than the anticipated gas injection pressure of 3,900 psi) on August 23, 2021. CPAI has also performed a passing non-state witnessed MIT of the outer annulus on July 19, 2021. This indicates that CD5-06 exhibits at least two competent barriers to the release of well pressure. CPAI has installed an injection line choke and surface safety valve (SSV) on each of the CD5 wells. Both of these devices have remote shut down capability by the Alpine Board Operator. 1 The application asked for an administrative approval under Rule 11 of AIO 18E, which granted the AOGCC the authority to administratively amend the order. This rule was made obsolete on February 10, 2018, when 20 AAC 25.556(d) became effective and authorized the AOGCC to administratively amend any order it has issued. AIO 18D.006 Amended September 13, 2021 Page 2 of 3 Combining this with live transmitters on the inner and outer annulus and the alarm functions in the Supervisory Control and Data Acquisition (SCADA) system create robust layers of protection from an over-pressure event. These inner and outer annulus alarms and shut-in protocols combined with the planned inner and outer annulus operating pressure limits enable AOGCC to remove the original water-only restriction and re-authorize gas injection. AOGCC believes CPAI can safely manage the IA repressurization with periodic pressure bleeds by maintaining the inner annulus to a pressure not to exceed 2,400 psi when on gas injection and 2,000 psi when injecting water. Accordingly, the AOGCC believes that the well’s condition does not compromise overall well integrity so as to threaten human safety or the environment. AOGCC’s approval to continue WAG injection in CRU CD5-06 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 MIT of the inner annulus every two 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 inner annulus operating pressure to 2,400 psi when on gas injection and 2,000 psi when on water injection. Audible control room alarms shall be set at or below these limits; 5. CPAI shall limit the well’s outer annulus operating pressure to 1,000 psi. Audible control room alarms shall be set at or below these limits; 6. CPAI shall maintain the injection line choke and SSV remote shut down protocols. This will include a drill site operator outer annulus high alarm set at 1000 psi. During gas injection, the inner annulus protocols will include a drill site operator high alarm set at 2,200 psi, and a high high alarm set at 2,400 psi that will prompt the control room Board Operator (manned 24 hours a day) to remotely shut in the choke or SSV. 7. CPAI shall monitor the inner and outer annulus pressures in real time with its SCADA system; 8. CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 9. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 10. The next required MIT shall be completed before or during the month of August 2023. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent test schedule for pad testing. AIO 18D.006 Amended September 13, 2021 Page 3 of 3 DONE at Anchorage, Alaska and dated September 13, 2021. 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. INDEXES 17 P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 February 21, 2023 Commissioner Jessie Chmielowski Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Commissioner Chmielowski, ConocoPhillips Alaska, Inc. submits the attached application to amend administrative approval AIO18D.005 to allow CRU injection well CD4-12 (PTD 210-091) to allow water alternating gas (WAG) injection. The well currently has known tubing by inner annulus communication only while on gas injection. Please contact me at 907-265-6181 if you have any questions. Sincerely, Kate Dodson Well Integrity Specialist ConocoPhillips Alaska, Inc. By Samantha Carlisle at 8:06 am, Feb 22, 2023 Kathleen Dodson Digitally signed by Kathleen Dodson Date: 2023.02.21 16:47:15 -09'00' P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 Well Integrity Specialist 2/21/2023 1 Alpine Well CD4-12 (PTD 210-091) Technical Justification for Administrative Relief Request Purpose ConocoPhillips Alaska, Inc. requests AOGCC amend Administrative Relief Area Injection Order 18D.005, to allow water alternating gas (WAG) injection for Colville River Unit injection well CD4-12 (PTD 210-091). The well displays tubing by inner annulus (IA) communication only during gas injection (MI). Well History and Status Colville River Unit injector CD4-12 was reported to the Commission on March 24, 2019, for a suspect IA pressure increase while on miscible gas injection. AOGCC approved diagnostic monitor periods for both MI and water injection services, which confirmed the tubing to IA communication only existed during MI injection. Early in 2023, CPAI discovered a significant benefit to maintaining gas injection in to CD4-12. CPAI conducted diagnostics including SCLD, packoff tests and MITIA, and confirmed the well’s integrity. Barrier and Hazard Evaluation With only water injection, this well has all the barriers of a normal injection well. Tubing: The 4-1/2”, 12.6 lb/ft, L-80 grade tubing has integrity to the packer at 9834’ MD (7044' TVD) based on passing a MIT-IA to 4200 psi on 12/22/2022. Intermediate casing: The 7”, 26 lb/ft, L-80 grade intermediate casing has integrity to the packer at 9834’ MD (7044' TVD) based on the previously mentioned MIT-IA and TIO trends. Surface casing: The 9-5/8”, 40 lb/ft, L-80 grade surface casing has an internal yield pressure rating of 5750 psi. The surface casing has integrity based on TIO trends. Primary barrier: The primary barrier to prevent a release from the well and provide zonal isolation is the tubing and packer. Secondary barrier: The intermediate casing is the secondary barrier should the tubing fail. Tertiary barrier: The surface casing will act as a third barrier in the unlikely case that the first two normal barriers have failures. Monitoring: Each well is monitored daily for wellhead pressure changes. Should leaks develop in the completion 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. TIO trends are compiled, reviewed, and submitted to the AOGCC for review monthly. P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 Well Integrity Specialist 2/21/2023 2 Proposed Operating and Monitoring Plan 1. Well will be used for water alternating gas injection. 2. Perform a passing MITIA every 2-years to maximum anticipated injection pressure. 3. Allow operating IA pressure up to 2,400 psi during gas injection service and 2,000 psi during water injection service. The operating OA pressure is allowed up to 1,000 psi. 4. Pressure transmitters will be maintained on the IA and OA allowing real time monitoring and alarm notifications. 5. Submit monthly reports of daily tubing, IA, and OA pressures, injection volumes and pressure bleeds for all annuli. 6. Shut-in the well if diagnostic testing or injection rates and pressures indicate further problems with appropriate notification to the AOGCC. 7. Maintain the injection line choke and SSV remote shut down capability. During gas injection, the inner annulus protocols will include a drill site operator alarm set at 2,200 psi, and a high alarm set at 2,400 psi that will prompt the control room Board Operator to remotely shut in the choke or SSV. 8. MIT Anniversary date will continue to be the month of June to maintain the 2-year AOGCC witnessed testing with the UIC MIT permanent 4-year scheduled pad testing. CD4-12 90-Day Bleed History WELL DATE STR-PRES END-PRES DIF-PRES CASING CD4-12 2023-02-18 962 0 -962 OA Last Tag Annotation Depth (ftKB)End Date Wellbore Last Mod By Last Tag:CD4-12 lmosbor Last Rev Reason Annotation End Date Wellbore Last Mod By Rev Reason: Gyro Survey 3/27/2020 CD4-12 claytg Casing Strings Casing Description CONDUCTOR 24" Insulated OD (in) 16 ID (in) 15.25 Top (ftKB) 35.0 Set Depth (ftKB) 112.0 Set Depth (TVD)… 112.0 Wt/Len (l… 62.50 Grade H-40 Top Thread Welded Casing Description SURFACE OD (in) 9 5/8 ID (in) 8.83 Top (ftKB) 34.7 Set Depth (ftKB) 2,910.5 Set Depth (TVD)… 2,395.1 Wt/Len (l… 40.00 Grade L-80 Top Thread IBT Casing Description INTERMEDIATE OD (in) 7 ID (in) 6.28 Top (ftKB) 34.5 Set Depth (ftKB) 11,497.0 Set Depth (TVD)… 7,383.5 Wt/Len (l… 26.00 Grade L-80 Top Thread BTCM Casing Description OPEN HOLE OD (in) 6.151 ID (in)Top (ftKB) 11,497.0 Set Depth (ftKB) 16,351.0 Set Depth (TVD)…Wt/Len (l…Grade Top Thread Tubing Strings Tubing Description TUBING String Ma… 4 1/2 ID (in) 3.96 Top (ftKB) 31.9 Set Depth (ft… 9,980.6 Set Depth (TVD) (… 7,096.7 Wt (lb/ft) 12.60 Grade L-80 Top Connection IBT-M Completion Details Top (ftKB) Top (TVD) (ftKB) Top Incl (°)Item Des Com Nominal ID (in) 31.931.90.00 HANGER FMC 11" x 4 1/2" TUBING HANGER 3.958 2,177.21,980.7 50.29 NIPPLE Camco BAL-O LANDING NIPPLE w/ DB PROFILE 3.813 9,834.1 7,043.7 67.90 PACKER BAKER PREMIER PACKER 3.875 9,894.4 7,066.0 68.56 NIPPLE HES 'XN' NIPPLE NO GO 3.725 9,979.2 7,096.3 69.91 WLEG WIRELINE ENTRY GUIDE (5.25" OD - 4" ID)4.000 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB) Top Incl (°)Des Com Run Date ID (in)SN 2,177.2 1,980.7 50.29 INJ VALVE 3.81" DB LOCK,SPACER PIPE, 4.5" A-1 INJ VALVE (SN:HSS165, OAL=79") 3/27/2020 1.250 Mandrel Inserts St ati on N o/Top (ftKB) Top (TVD) (ftKB)Make Model OD (in)Serv Valve Type Latch Type Port Size (in) TRO Run (psi)Run Date Com 1 7,458.2 5,577.8CAMCO KBG-2 1 GAS LIFT DMY BK-50.000 0.012/8/2010 2 9,721.1 6,999.9 CAMCO KBG-2 1 GAS LIFT DMY BK 0.000 0.0 12/10/2010 Notes: General & Safety End Date Annotation 5/28/2019 NOTE: Waivered for water-only injection due to TxIA during gas injection 9/8/2010 NOTE: VIEW SCHEMATIC Alaska Schematic9.0 HORIZONTAL, CD4-12, 5/29/2020 11:12:25 AM Vertical schematic (actual) OPEN HOLE; 11,497.0-16,351.0 INTERMEDIATE; 34.5-11,497.0 WLEG; 9,979.2 NIPPLE; 9,894.4 PACKER; 9,834.1 GAS LIFT; 9,721.1 Intermediate Casing Cement; 7,825.0 ftKB GAS LIFT; 7,458.2 Intermediate Casing; 4,855.0 ftKB SURFACE; 34.7-2,910.5 INJ VALVE; 2,177.2 NIPPLE; 2,177.2 CONDUCTOR 24" Insulated; 35.0-112.0 HANGER; 31.9 WNS INJ KB-Grd (ft)Rig Release Date 4/3/2002 CD4-12 ... TD Act Btm (ftKB) 16,004.0 Well Attributes Field Name ALPINE Wellbore API/UWI 501032041401 Wellbore Status INJ Max Angle & MD Incl (°) 91.73 MD (ftKB) 13,296.53 WELLNAME WELLBORE Annotation Last WO: End DateH2S (ppm)DateComment SSSV: NIPPLE Submit to: OOPERATOR: FFIELD / UNIT / PAD: DDATE: OOPERATOR REP: AAOGCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 210091 Type Inj W Tubing 2445 2457 2456 2456 Type Test P Packer TVD 7044 BBL Pump 4.8 IA 693 4200 4150 4140 Interval O Test psi 1761 BBL Return OA 467 490 490 490 Result P 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 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 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 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 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 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 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 TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Notes: ConocoPhillips Alaska Inc, Alpine / CRU / CD4 Pad Arend 12/22/22 Notes:Non-witnessed diagnostic MITIA Notes: Notes: Notes: CD4-12 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MMechani cal Integrity Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes: Notes: Notes: Form 10-426 (Revised 01/2017)CD4-12 10-426 22Dec22.xlsx 16 By Grace Salazar at 1:14 pm, Aug 17, 2021 P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 1 Colville River Unit Well CD5-06 (PTD 216-077-0) Technical Justification for Administrative Relief Request Purpose ConocoPhillips Alaska, Inc. (CPAI) requests that the AOGCC approve this Administrative Approval request as per AIO 18E, Rule 11, to allow water alternating gas (WAG) injection for Colville River Unit WAG injector CD5-06 (PTD 216-077-0). The well displays tubing by inner annulus communication only during gas injection. Well History and Status Colville River Unit well CD5-06 was completed in August 2016. CD5-06 was initially reported to the Commission on August 6, 2019 for a suspect inner annulus pressure increase while on MI injection. The report was days after the injector passed an inspector-witnessed MIT-IA performed on August 3, 2019 (MIT-IA results are attached). CPAI communicated a plan to the AOGCC that included intent to observe the well on MI injection, and if IA pressurization continued, then monitor the well during water injection to confirm if the pressurization occurred during water injection. The MI monitor period was discontinued early because the IA pressurization continued suspiciously after bleeds. Water injection was then commenced. No suspect IA pressurization was observed during the water injection monitor period. CPAI has developed criteria under which it believes a gas injection well may operate safely with TxIA communication. That criteria includes the well having casing rated high enough to support MAIP of gas injection should a barrier fail, passing an MITIA to MAIP of gas injection, passing a MITOA or SCLD, and passing an IA DDT on water injection. During gas injection service the IA pressure must maintain below the MAOP of 2400 psi. In addition, pressure transmitters will be maintained on the IA and OA allowing real time monitoring and alarm notifications. CPAI believes that CD5-06’s current condition along with the well testing and operating criteria above will allow the well to be operated safely without threatening human safety or the environment. Therefore, CPAI request Administrative Approval that will allow CD5-06 to continue WAG injection with known TxIA communication. Barrier and Hazard Evaluation Barriers in place are sufficient to allow safe operation with water alternating gas injection service. Tubing: The 4-1/2”, 12.6 lb/ft, L-80 tubing has integrity to the Baker Premier production packer at 8,671’ MD (7,308’ TVD) based on the passing MITIA to 4,200 psi on July 16, 2021 and TIO trends. There is known TxIA communication while on gas injection based on TIO trend data. P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 2 Production casing: The 7-5/8”, 29.7 lb/ft, L-80 Tie back casing and Intermediate liner have integrity to the Baker Premier production packer at 8,671’ MD (7,308’ TVD) based on the aforementioned passing MITIA and TIO trends. Surface casing: The 10-3/4”, 45.5 lb/ft, L-80 surface casing has an internal yield pressure rating of 5,210 psi. The surface casing has integrity based on a passing SCLD / gas MITOA to 1,200 psi on July 19, 2021 and TIO trends. Primary barrier: The primary barrier during water injection to prevent a release from the well and provide zonal isolation is the tubing and packer. The primary barrier during gas injection to prevent a release from the well and provide zonal isolation is the production casing. The tubing and packer also act as a limited barrier, so that the pressure build-up is manageable below 2,400 psi. Secondary barrier: The production casing is the secondary barrier during water injection, should the tubing fail. The surface casing is the secondary barrier during gas injection, should the production casing fail. Tertiary barrier: The surface casing will act as a tertiary barrier during water injection, in the unlikely case that the first two normal barriers have failures. Monitoring: This well will be monitored real time for wellhead pressure changes. Any pressure trends that indicate further annular communication require investigation, Commission notification, and corrective action, up to and including a shut-in of the well. TIO trends are compiled, reviewed, and submitted to the AOGCC for review on a monthly basis. Proposed Operating and Monitoring Plan 1. Well will be used for water alternating gas injection; 2. Perform a passing MITIA every 2-years to maximum anticipated injection pressure; 3. Allow operating IA pressure up to 2,400 psi during gas injection service and 2,000 psi during water injection service; operating OA pressure up to 1,000 psi; 4. Pressure transmitters will be maintained on the IA and OA allowing real time monitoring and alarm notifications; 5. Submit monthly reports of daily tubing, IA, and OA pressures, injection volumes and pressure bleeds for all annuli; 6. Shut-in the well should diagnostic testing or injection rates and pressures indicate further problems with appropriate notification to the AOGCC; 7. MIT Anniversary date to be set the month of July 2020 to align the 2-year AOGCC witnessed testing with the UIC MIT permanent 4-year scheduled pad testing; Annular Communication Surveillance 19-May-2021Well Name:CD5-06 Start Date:19-May-2021 17-Aug-2021Days:90 End Date:17-Aug-2021 50 60 70 80 90 100 110 120 130 140 150 0 500 1000 1500 2000 2500 3000 19-May-2122-May-2125-May-2128-May-2131-May-213-Jun-216-Jun-219-Jun-2112-Jun-2115-Jun-2118-Jun-2121-Jun-2124-Jun-2127-Jun-2130-Jun-213-Jul-216-Jul-219-Jul-2112-Jul-2115-Jul-2118-Jul-2121-Jul-2124-Jul-2127-Jul-2130-Jul-212-Aug-215-Aug-218-Aug-2111-Aug-2114-Aug-2117-Aug-21Temperature (degF)Pressure (PSI)Pressure Summary WHP IAP OAP WHT 0 1000 2000 3000 4000 5000 6000 7000 19-May-2122-May-2125-May-2128-May-2131-May-213-Jun-216-Jun-219-Jun-2112-Jun-2115-Jun-2118-Jun-2121-Jun-2124-Jun-2127-Jun-2130-Jun-213-Jul-216-Jul-219-Jul-2112-Jul-2115-Jul-2118-Jul-2121-Jul-2124-Jul-2127-Jul-2130-Jul-212-Aug-215-Aug-218-Aug-2111-Aug-2114-Aug-2117-Aug-21Injection Rate (BPD or MSCFD)Injection Rate Summary DGI MGI PWI SWI BLPD Last Tag Annotation Depth (ftKB) End Date Wellbore Last Mod By Last Tag: CD5-06 lehallf Last Rev Reason Annotation End Date Wellbore Last Mod By Rev Reason: Pull SPG, Set A-1 CD5-06 boehmbh Casing Strings Casing Description CONDUCTOR OD (in) 20 ID (in) 19.12 Top (ftKB) 36.5 Set Depth (ftKB) 115.0 Set Depth (TVD) … 115.0 Wt/Len (l… 94.00 Grade B Top Thread WELDED Casing Description SURFACE OD (in) 10 3/4 ID (in) 9.95 Top (ftKB) 36.7 Set Depth (ftKB) 2,293.3 Set Depth (TVD) … 2,189.1 Wt/Len (l… 45.50 Grade L-80 Top Thread Hyd 563 Casing Description INTERMEDIATE OD (in) 7 5/8 ID (in) 6.88 Top (ftKB) 34.3 Set Depth (ftKB) 9,611.8 Set Depth (TVD) … 7,464.7 Wt/Len (l… 29.70 Grade L80 Top Thread BTCM Casing Description WINDOW L1 OD (in) 7 5/8 ID (in) 6.88 Top (ftKB) 9,378.0 Set Depth (ftKB) 9,391.0 Set Depth (TVD) … 7,446.1 Wt/Len (l…Grade Top Thread Casing Description OPEN HOLE OD (in) 6 3/4 ID (in) Top (ftKB) 10,286.0 Set Depth (ftKB) 18,057.0 Set Depth (TVD) …Wt/Len (l…Grade Top Thread Casing Description LINER ALP 'A' OD (in) 4 1/2 ID (in) 3.96 Top (ftKB) 9,440.6 Set Depth (ftKB) 10,285.8 Set Depth (TVD) … 7,534.2 Wt/Len (l… 12.60 Grade L-80 Top Thread TXP Liner Details Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des Com Nominal ID (in) 9,440.6 7,451.0 84.55 PACKER Liner Top Packer,HRDE ZXP, w/10' Seal Bore Extension 5.750 9,460.5 7,452.9 84.72 NIPPLE RS Nipple, 5-1/2", Hyd563 4.870 9,463.4 7,453.1 84.74 HANGER Liner Hanger,DG FL pinned 2500 psi 4.830 9,473.1 7,454.0 84.82 SBR Seal Bore Extension, 190-47,5-1/2" Hyd563 4.750 9,513.8 7,457.6 85.17 NIPPLE Landing Nipple,4 1/2",DB-6,3.563",IBTM 3.563 9,525.8 7,458.6 85.32 TUBING Tubing,4 1/2",12.6#,L80,TXP 3.958 Tubing Strings Tubing Description TUBING String Ma… 4 1/2 ID (in) 3.96 Top (ftKB) 31.3 Set Depth (ft… 9,492.2 Set Depth (TVD) (… 7,455.7 Wt (lb/ft) 12.60 Grade L-80 Top Connection TXP Completion Details Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des Com Nominal ID (in) 31.3 31.3 0.00 HANGER FMC 4-1/2" Tubing Hanger TXP 3.969 2,002.1 1,937.1 26.95 NIPPLE Landing Nipple,4 1/2",DB,3.875",Hyd563 3.875 8,612.5 7,286.9 67.69 NIPPLE Landing Nipple,4 1/2",DB-6,3.813",TXP 3.813 8,670.7 7,308.1 69.58 PACKER Baker Premier Production Packer, 4 1/2" X 7 5/8" 29#, TC-II 3.880 8,793.5 7,348.6 72.40 SLEEVE CMU Sliding Sleeve,CMU,4 1/2",DB 3.75" IBTM, Closed 3.750 9,450.4 7,451.9 84.63 LOCATOR Baker Mechanical Locator 3.870 9,451.9 7,452.1 84.64 SEAL ASSY Baker GBH-22 locating Seal Assembly 3.870 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Des Com Run Date ID (in) SN 8,612.0 7,286.7 67.67 INJ VALVE 4.5" A-1 INJ VALVE (HSS-157) ON 3.81" DB LOCK 11/2/2019 1.250 Mandrel Inserts St ati on N o/Top (ftKB) Top (TVD) (ftKB) Make Model OD (in) Serv Valve Type Latch Type Port Size (in) TRO Run (psi) Run Date Com 1 8,584.0 7,275.9 Camco KBMG 1 GAS LIFT DMY BK 0.000 0.0 8/21/2016 2 8,699.1 7,317.9 Camco KBMG 1 INJ DMY BK 0.000 0.0 11/4/2019 3 8,766.4 7,340.1 Camco KBMG 1 INJ DMY INT 0.000 0.0 10/2/2019 Notes: General & Safety End Date Annotation 10/19/2019 NOTE: Waivered for water-only injection due to TxIA during gas injection CD5-06, 5/30/2020 9:43:32 AM Vertical schematic (actual) OPEN HOLE; 10,286.0-18,057.0 LINER ALP 'A'; 9,440.6-10,285.8 INTERMEDIATE; 34.3-9,611.8 SEAL ASSY; 9,451.9 LOCATOR; 9,450.4 WINDOW L1; 9,378.0-9,391.0 SLEEVE CMU; 8,793.5 INJ MANDREL; 8,766.4 INJ MANDREL; 8,699.1 PACKER; 8,670.7 INJ VALVE; 8,612.0 NIPPLE; 8,612.4 GAS LIFT; 8,584.0 SURFACE; 36.7-2,293.3 NIPPLE; 2,002.1 CONDUCTOR; 36.5-115.0 HANGER; 31.3 WNS INJ KB-Grd (ft) 36.50 Rig Release Date 8/11/2016 CD5-06 ... TD Act Btm (ftKB) 18,057.0 Well Attributes Field Name ALPINE Wellbore API/UWI 501032074400 Wellbore Status INJ Max Angle & MD Incl (°) 90.05 MD (ftKB) 12,274.60 WELLNAME WELLBORECD5-06 Annotation Last WO: End DateH2S (ppm) DateComment SSSV: NIPPLE Submit to: OPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2160770 Type Inj W Tubing 2450 2450 2450 2450 Type Test P Packer TVD 7308 BBL Pump IA 690 4200 4145 4130 Interval O Test psi 3900 BBL Return OA 12 26 25 25 Result P 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 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 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 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 TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes:Diagnostic MIT-IA for Administrative Approval proposal. Notes: CD5-06 Notes: Notes: Notes: ConocoPhillips Alaska Inc, ALPINE / CRU / CD5 PAD Van Camp 07/16/21 Form 10-426 (Revised 01/2017)MIT CRU CD5-06 07-16-21.xlsx ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 January 27, 2021 Commissioner Jessie Chmielowski Alaska Oil and Gas Conservation Commission 333 West 71h Avenue, Suite 100 Anchorage, AK 99501 Re: Request to Cancel Area Injection Order (AIO) 18D.004 for Colville River Unit (CRU) CD5-316 (PTD 217-040-0) Dear Commissioner Chmielowski: ConocoPhillips requests cancellation of Administrative Approval AID 18D.004. The approval was originally issued December 10, 2018 to allow continued water -only injection into CRU CD5-316 (PTD 217-040-0) due to tubing by inner annulus communication on miscible gas injection. On August 23, 2020, a dummy valve in the downhole circulation mandrel was replaced with a high-sealibility model. With AOGCC approval, the well underwent a 30 -day monitoring period of miscible gas injection concluding January 20, 2021. This indicated the well does not exhibit abnormal annular pressure behavior while on miscible gas injection. This request is to cancel the Administrative Approval and return the well back to its normal injection operation. Please contact me at Travis.T.Smith@conocophillips.com or 670-4014 if you have any questions. Sincerely, �4'k Travis Smith Well Integrity Engineer ConocoPhillips Alaska, Inc. WNS INJ WELLNAME CD5-316 WELLBORE CDS-316 ConocoPhillips Wall AtWbutes Ford X.me AlaSka.11 n: Max Angle & MD Welleon RPYUWI We1RDn 3Yeu Mwll') MOIRNBI 1 9329 20.148 TD M6enlnna) 31.198.0 cpmmeN Hxs(ppn) Don Annw.u4n Ena mu rcaGmml alp RglWW Deta S66V: NIPPLE Lan WO: 36.44 &262011 croolAerexozo4'.ls'..p I Last Tag VeNalaMemel'c (xlwa AMpralbn Deplepaile End Doe .."bore LIoam sy N.AIMM". Last Tag: ippmver Last Rev Reason nnnNBllon pop Miceemre Mad ey R. R Reason: Swab Dummy Valve,sall lnl Vlv In2.252019 1C053 'v Spe Casing Strings capes Descnpuon OD let lolls) Topryole) SOM,oenrcal an Depn MDI... Witi N. w.a. Tap Toned CONDUCTOR 20 19.12 365 115.5 115.5 78.0 B Welded CulnO Doompeon op pin M(M) Top(Nle) WDepMsurlu Sat Dera(IVDI... Mai S. Grade Top Rrmd SURFACE 133/8 12.42 MS 2,359.8 2,176.3 611x0 L-80 HSS3 CMM, Deoulpeon open ID (N) TWMKB) an Depth IWO) WDepn (TVD)... Millen B.. Gredo Top Teed CCNDllpioq:Wsuss IWERMEDIATE91 95/8 681 1,981.1 13,838.8 6,066.4 40.00 LA9 BTCM ...""."sties open) 10 an Tippets) SH Dinah BXIB) Set Depn Mel"' MI-or 11... Grade Top mood INTERMEDIAMOTie 7 6.28 33.8 13,689.3 amps 2600 LA0 BTCM �. DWrq ouMpeen op Bnl ID (in) Top (Mal Sol Depn (me) art Dep", fe`1I... WIM1an P... Grade Topes INTERMEDIATEW 7 6.28 13.681.6 19333.0 1.445.7 26.00 1.80 H563 MxPP .2; 03,B INI VAIVE:2.Nse Ci. LINER IIs Drops.- open) 412 ID (in) Top ("Nom apt peWe 11111") 8e4 DepM(rVp)... WD4en P... ands 3.96 19,169b 27,778.0 1,470.3 12.60 LA0 Top Tnrxd TW-M Liner Details xwNNl W ToP(I Tap Me)mrca) Top Incl l•I nem M.Lam rani WRFACE: Sib-2.115111119,169.8 1,436.4 87.095et1W Sleeve ILW Seeing sleeve w/5•ID 19,185.9 1,439.2 87.10 PACKER 4-12'x T 2W HRD-EZ Liner Tap Paulow 3.815' 3.815 DAauF A M.T Seale.. 19,196.4 7,4398 87.11 HANGER 0.1/2"x Y Flex-Loel, Liner Manger 3.959 19,206.3 1,440.3 87.12 XO Reducing Crossover 8unrolp d I?-4 HW 521 pair x4-17 4.000 (Casino) 1260 TXP pin mmERrnEDwTEar.e a: Tubing Strings Tueurp De.cnpnan wRlp Ms._mPn) rIP(nxeI sM apse (n..W Depe (�D)1...mpirol anne rapconnecuon a.o-t>.Wes 4.5 NYD563 41Q 3.96 31.4 19.181.3 7,439.0 12W40 H663 Compine Completion Details Top(W[e Tooled xom- INTEgMEWiEN:1,WT1- T,(..p) pi q.m M. Com )DIM) 13111,s 31.0 1.4 .10 HANGER TMC 0.71TTu&-MHaTear C-Il Top x Hydril 58J Bonom 3880 2.203.6 2,059.8 40.35 X-NIPPLE eLPPLE,LANOINGA I?,X,3.813", NYOS6J 3.813 14SM 6,30.1 70.57 SLIDING SLV SLEEVE.S1.I0ING.4 12',CMD, BAKER,3.813' X-HY06B3 3.813 SUMNG Wv; µinn CMD CLOSE02R52019 xNN1PpLF Mena 14.6P.8 6,385.3 71.21 XNNIPPLE NiPPLE,LANOING,41?3.813• M, 3,725 19,166.4 1,438.2 87.09 LOCATOR LOCATORSUBWI2.86SPACEOUT 3.93D LOOAT00,1e,10e 19,166.9 1,438.3 81.09 SEAL ASSY SEALASSEMBLY 3.930 Other In Hole (Whellne retrievable plugs, valves, pumps, fish, etc.) eEU Aasv:lv.IM.e Top Tap (no) Top NG PIIIBI (.2X81 1'1 Deo= Com Run Dela ID(In) SX 2,203.6 2,OSB.B 40 INJ VALVE 3.8r MCX INJ VALVE w/1.S ORIFICE 824.2020 1.500 Mandrel Inserts S, IT H Top MD) NHo Yoe PMShe TRO Rw To Inner Iona) M.ee MM.I aD(Inl aM'/ Type ) (pMl aW DM Cde 1xTERL1EWTE.x', 1d,a1h ewo t 3,381.7 2,n3.1 SLB K 9 1 G4SurT OMT BTM fl232020 Notes: General & Safety Fropote Annoneon due to Txi A do 9as LINER', I.J. a3T.M. Annular Communication Surveillance Well Name: CD5-316 Start Date: 30 -Oct -2020 Days: 90 End Date: 28 -Jan -2021 Pressure Summary 4500 150 4000 140 3500 130 120 3000 J/ 110 2500 v v � 100 � 2000 0 v go a 1500 H I 80 � 1000 70 500 60 0 50 0 N 0 N 0 N 0 N 0 N 0 N 0 N 0 N 0 N 0 N 0 N 0 0 0 0 0 0 0 0 0 0—-- N N N N N N N N N N N N N N N N N N N N U >> 0 0 > 0 > 0 > 0 > 0 > 0 > 0 > 0 > o U U U U U U U C C C 0 m m w m m v w v w m m m C C C C C C m m m m M M C M Z Z ZZ Z Z Z Z Z 2 0 1?0 0 C?0 9 0 9 0 7 7 O N N CO rl V h O M l0 Ol N 111 W N V h O M l0 OI rl O I� O ti tD M N vl W M rl rl rl N N N N N ti N N N N N N N N —WHP —IAP —OAP WHT Injection Rate Summary 6000 5000 0 u ? 4000 p ` V o A O m 3000 v m 0 2000 v = 1000 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N > O > O > O > O > O > O > O > O > O > O U U UU U V U V V C C N N N N m m N v v N C C C C C C m m m m m m C m Z Z Z Z Z Z Z Z Z Z ^ 47 7 7 O M N Vl M N ti O M l0 Ol N VA W a O M 6 Ol N N N N N N rl N N N N ti fl fl N N N N —DGI MGI —PWI SWI —BLPD 14 ConocoPhillips Alaska F.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 September 28, 2019 Commissioner Chmielowski Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Dear Commissioner, ISEP .`_ 0i alit ConocoPhillips Alaska, Inc. presents the attached proposal per AIO 18D, Rule 11, to apply for administrative approval to allow injection well CRU CD5-06 (PTD 216-077) to remain in water only injection service. The well was recently determined to show suspect IA pressurization only while on gas/MI injection. If you need additional information, please contact us at 659-7126. Sincerely, ) ) A: �/� � 'rcw Rachel Kautz Well Integrity ConocoPhillips Alaska, Inc. ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 Alpine Injector CRU CD5-06 (PTD 216-077) Technical Justification for Administrative Relief Request Purpose ConocoPhillips Alaska, Inc. (CPAI) proposes that the AOGCC approve this administrative relief request as per Area Injection Order 18D, Rule 11, to continue water only injection for Colville River Unit injection well C135-06 (PTD 216-077). The well displays suspicious IA pressurization only during gas/miscible injectant (MI) injection. Well History and Status Colville River Unit well CD5-06 was completed in August 2016. CD5-06 was initially reported to the Commission on August 6, 2019 for a suspect inner annulus pressure increase while on MI injection. The report was days after the injector passed an inspector -witnessed MIT -IA performed on August 3, 2019 (MIT -IA results are attached). CPAI communicated a plan to the AOGCC that included intent to observe the well on MI injection, and if IA pressurization continued, then monitor the well during water injection to confirm if the pressurization occurred during water injection. The MI monitor period was discontinued early because the IA pressurization continued suspiciously after bleeds. Water injection was then commenced. No suspect IA pressurization was observed during the water injection monitor period. Further investigation of the IA pressurization seen only during gas/MI injection service may be pursued in future. However, as a diagnostic path forward will take time to develop, CPAI is currently requesting an Administrative Approval (AA) to allow continued water injection. Barrier and Hazard Evaluation Tubing: The 4-1/2", 12.6 lb/ft, L-80 grade tubing has integrity to the packer at 8671' MD (7308' TVD), based on passing a MIT -IA to 2700 psi on 8/3/19 and water injection TIO trends. Intermediate casing: The 7-5/8", 29.7 lb/ft, L-80 grade casing has integrity to the packer at 8671' MD (7308' TVD), based on the aforementioned MIT -IA and TIO trends. Primary barrier: The primary barrier to prevent a release from the well and provide zonal isolation during water injection is the tubing and packer. Secondary barrier: The intermediate casing is the secondary barrier should the tubing fail. Monitoring: Each well is monitored daily for wellhead pressure changes. Should leaks develop in the completion it will be noted during the daily monitoring process. Any pressure trends that indicate annular communication requires investigation, Commission notification, and corrective action, up to and including a shut-in of the well. TIO trends are compiled, reviewed, and submitted to the AOGCC for review on a monthly basis. CPAI Well Integrity 9/28/2019 i ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 Proposed Operating and Monitoring Plan 1. WAG well to 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 and operating OA pressure up to 1000 psi; 4. Submit monthly reports of daily tubing & IA 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 for the AOGCC witnessed testing to be set for the month of August 2019 (last AOGCC witnessed test was August 3, 2019) to align with the UIC MIT permanent pad testing schedule. CPAI Well Integrity 9/28/2019 2 WNS INJ WELLNAME CD5-06 WELLBORE C05-06 ConoeoPhllilps WeII AHrlbutes MaKAnglo MD TO Ala6k �. hi^ FIeMNamp PINE We1168M1APNIWI Wellbory SMNa I[I I.1 RIF, 1 ]4400 I 0.05 12,274.W to BIm gtKBl 18,05].0 concee NIPPLE Icti m1 D. Anancep. Entl Oate KE�aM In) Last WO: 36.50 Ng Rel. pate 81112018 COSLB, flR]I30191051:t0 AM Last Tag Ve,timl xl, k(acluell last Tag' MnoMllon peplk (KKB) Entl pale WellbOM1 CD5-05 Leat Motl By Iaballf ILANGER: aX3- Last Rev Reason g Rev Reason: PULLSET PLUG Annolanon A-11NJ VALVE, SET PLUG, GLV C/O, PULL EnEpate 523201] Wellbore CD5-06 last Motl By pp.. Casing Strings B� N Caamp peammi.. CONDUCTOR Oppn) mpn) Top (NKBI an Depth JAKE) sM pepnlTvp)... vnrten p... Gmtle 20 19.12 36.5 115.0 115,4 94.00 B Top Tbreae WELDED Caeing Dnctlptlon SURFACE OD RnI 10 (Int TOPMKB) InpepNQtl(BI Set Depth WDLen 9... Draae 10314 9.95 36.7 2,293.3 2,189.1 45.50 L-80 Top TNeaE HYtl 563 G.M...ec'.. INTERMEDIATE OD(In) ID(In) Top 1AKB1 get Depth JAKE) gel Depth MD)... WALK. 6.., Gmtle 7518 6.88 34.3 9,611.8 37,4M.7 29.]0 L80 Tap ThrtW BTCM CONWCTOfl: %.St',50 Chun, peeerlI WINDOWL1 DO (In) he 6n1 Top(AKB) Get DeplhgI Bee DepO (NDL.. WtlLen (L,. Gra4e 75/8 6.88 9,378.0 9,391.0 ],446.1 Top Thnetl CUNp Dince,lon OPEN HOLE OD9n) ID (I Top WED Be D...h1AKB) SM Depth lTVe)... YMen 11.,. Gmtle 63/4 1%286.0 10,05].0 Tap ThrtaC XO-THREAD;1,992.0 coling peaorlptlon LINER ALP 'A' Oti In (in) Top(ryKB) Bel pepM (flKB) Gee Depmlrvpl... waL.n 9... Grade 412 3.9fi 9,440.6 10,285.8 ],534.2 12.W L-80 Top Threatl TXP .-TCREAM2.0i er Details To rtKB TOP(TVD)IflKe Ta Incl ' bem Oea Top 1 1 P 11 Com Nominal iD (in) 9,440.6 7,451.0 84.55 PACKER Liner Top PECkel,HRDEZXP,W/10'Seal Bare 5.75C Extension 9,481.6 7,452.9 84.72 NIPPLE RS Nipple, 5-12', Hytl5M 4.870 9.4634 7,453.1 84,74 HANGER Liner Hao9BADG FL pinnetl 2500 ps14.830 aVRFACE; BA]2,2W ]- 9,473.1 7,454.0 84.82 SBR Seal Bore Extension,190-07,5-1/2 Hytl563 9,513.8 7.457.6 85.17 NIPPLE Lantling Nipple,412",DBE,3.563",IBTM 3.Sfi3 9,525.8 7,458.6 85.32 TUBING Tubing,412",12.fik,L60,iXP 3.958 Tubing Strings Tubing Description TUBING string Ma... ID lin) Top (XKB) Gel peplh lA.. Get Depth ITVDI6.. WIJIhM) Gretle Top 412 3.96 31.3 9,492.2 J,455> 12.fi0 L-80 TXP Conneglon GAsuFT:KBan Completion Details vAVE; e,ema Top Two) Top (Web (flxE) Top Incl 19 ft.. Des Co. Naminal ID On) 31.3 31.3 0.00 HANGER 1MC4-112" Tubing Holger TXP 3.969 2,002.1 1,937.1 2695 NIPPLE Lantling Nipple,4 IIZ.DB,3875',HyU563 3.875 8,612.5 7,286.9 67.69 NIPPLE Lantling Nipple,412",OB45,3.813",TXP 1 3.813 8,670.7 7,308.1 69.58 PACKER Baker Premier Pr....Oon PatFal,412'X 7518. 29N. TC -11 3.880 8,793.5 ],348.6 72.40 SLEEVE CMU Slitlin9 Sleeve,CMUp 12•,p83.75"IBTM. Closetl 3.750 XO THREADs:O,moe 9,450.4 ],451.9 84.fi3 LOCATOR 0akerM¢haniwlLacCi 3,870 PACKER, 0,5707 9,451.9 37,452.1 84.64 SEALASBY I Baker GBH-221ocating Seal Assembly 3.870 xp-THREADS; S,W9.2 XO -THREADS e...Ba Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (TVo) Tov and .Aa L1Fr; 0, 0W., XD-THR., e.7a5.a Top (AKB) (.K.) 1.1 pea COm ftun Onto 1. (in, 8,612.0 7,286.7 61, Al INJ VALVE (SN: HYS-444)ON 3.81"Be LOCK TO 52112017 1.250 DB NIP XD-THRAAos:e.]Saa 9,894.9 1 7,493.8 81.68 1Packer 4.5'x5.75" OD FreecaP 11 Watereniv010tl aay 7272016 4.500 DAa11Fr:6,]pe,o Mandrel Inserts XO-THREAOS:87737 Bt all M THREAI#:A]aJ/ n EEVECIA;.793.5 XO-T1gFAC0; e,R].9 on Top(ND) Velve bleb POAGIae TRORun N Top IAKB) (ft B) Make Model Oli sary Type Type (Int (pal) Run Com 1 8,584.0 7,275.8 Camw KBMG 1 G4BLIFT .MY BEN 0.000 0.0 fl21128 ',the 2 8.699.1 7,31).9 CemcO KBMG 1 G US T HFCV BEK 0.000 0.0 5121201] 3 8,761 7,340.1 Camw KBMG 1 GAB LIFT HFCV BEK 0.000 0.0 52112017 Notes: General 8 Safety End DaM Anndnnon NOTE: WINWW LI: 9.]i0.0.9,2910 XO-TNREADS', gMa.O LOUTOR RAMa 0 SEAL ASSY; 9,451.9 IMERMEONTE: aa.a9.611.8 Pvkar9.gRa URERAL11':9,MD.SIA.H R OPEN -E; 10,25L. IAARA • ••1 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: iininegg(Eiialaska.govAOGCCIno t fg� k phoebe. brooksgnalaska.cov OPERATOR: ConocoPhillips Alaska Inc, FIELD/UNIT/PAD: Alpine / CRU /CD5 Pad DATE: 08/03/19 OPERATOR REP: Van Camp/ Weimer AOGCC REP: Jeff Jones Ch ris.wallaceaalaska gov Well CDS-01 INTERVAL Codes Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min, 4=Four Year Cycle F=Fail PTD 2160220 Type Inj F G Tubing 3903 3901 3905 3905 N = Not Injecting Type Test P Packer TVD 7291 88L Pump 1.1 IA 1710 2410 2370 2370 Interval 4 Test psi 1823 BBL Return 1.1 OA 350 400 400 400 Result P Notes: Well CD5-02A Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2160680 Type Inj G Tubing 3157 3159 3160 3158 Type Test P Packer TVD 7199 BBL Pump 2.2 IA 930 2100 2080 2075 Interval 4 Test psi 1800 BBL Return 2.2 OA 450 575 575 575 Result P Notes: Well CD5-06 Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2160770 Type Inj G Tubing 3831 3831 3830 3827Type as P Packer TVD 7308 BBL Pump 1.0 IA 1910 2700 2660 2650 Interval 4 Test psi 1827 BBL Return 1.0 OA 700 700 700 700 Result P Notes: Well CD5-08 Pressures: Pretest Initial 15 Min. 30 Min. 45 Min, 60 Min. PTD 2160510 Type Inj W Tubing 2293 2294 2294 :: 3 Type Test P Packer TVC 7344 BBL Pump 2.8 IA 910 3010 2960 2960 Interval 4 Test psi 1836 BBL Return 2.8 OA 475 550 550 550 Result P 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: TYPE INJ Codes TYPE TEST Cotles INTERVAL Codes Result Codes W=Water P=Pressure Test 1=lnital Test P=Pace G=Gas O= Other(Eeschbe in Notes) 4=Four Year Cycle F=Fail S=Slurry V= Required by Vanance 1=Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Form 10-426 (Revised 01/2017) MIT CRU CDs PAD 08-03-1sx1sx 13 ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 May 6, 2019 AOGCC Commissioners Alaska Oil & Gas Conservation Commission 333 West 7h Avenue, Suite 100 Anchorage, AK 99501 r �' �R1. ECENE MAY 0 8 2019 Dear Commissioner: J C ConocoPhillips Alaska, Inc. presents the attached proposal per AIO j8C�Rule 11, to apply for administrative approval to allow CRU injection well CD4 -12 (PTD 210-091) to continue water only injection service. The well is permitted as a WAG injector, but currently exhibits tubing by inner annulus communication only during miscible injection. If you need additional information, please contact Sara Carlisle or me at 659-7126. Sincerely, dallelz� Rachel Kautz Well Integrity Supervisor ConocoPhillips Alaska, Inc. ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 Alpine Well CD4 -12 (PTD 210-091) Technical Justification for Administrative Relief Request Purpose 'qpd G ConocoPhillips Alaska, Inc. proposes that the AOGCC approve this administrative relief request as per Area Injection Order ]8C, Rule 11, to continue water only injection for Colville River Unit injector CD4 -12 (PTD 210-091). The well displays tubing by inner annulus (IA) communication only during miscible gas injection (MI). Well History and Status Colville River Unit injector CD4 -12 was reported to the Commission on March 24, 2019 for a suspect IA pressure increase while on miscible gas injection. A passing MIT -IA was performed on March 30, 2019 (see attached 10-426). AOGCC approved diagnostic monitor periods for both MI and water injection services, which confirmed the tubing to IA communication only existed during MI injection. ConocoPhillips requests an administrative approval (AA) to allow for continued injection of water only into CD4 -12. Barrier and Hazard Evaluation With only water injection, this well has all the barriers of a normal injection well. Tubing. The 4-1/2", 12.61b/ft, L-80 grade tubing has integrity to the packer at 9834' MD (7044' TVD) based on passing a MIT -IA to 3300 psi on 3/30/2019 and TIO trends. Intermediate casing: The 7", 261b/ft, L-80 grade intermediate casing has integrity to the packer at 9834' MD (7044' TVD) based on the previously mentioned MIT -IA and TIO trends. Surface casing: The 9-5/8", 401b/ft, L-80 grade surface casing has an internal yield pressure rating of 5750 psi. The surface casing has integrity based on TIO trends. Primary barrier: The primary barrier to prevent a release from the well and provide zonal isolation is the tubing and packer. Secondary barrier: The intermediate casing is the secondary barrier should the tubing fail. Tertiary barrier: The surface casing will act as a third barrier in the unlikely case that the first two normal barriers have failures. Monitoring: Each well is monitored daily for wellhead pressure changes. Should leaks develop in the completion 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. TIO trends are compiled, reviewed, and submitted to the AOGCC for review on a monthly basis. Well Integrity Supervisor 5/6/2019 j ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 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 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 on as the month of June 2019 (last AOGCC witnessed test was June 12, 2015) to align the AOGCC witnessed testing with the UIC MIT permanent 4 -year scheduled pad testing. Well Integrity Supervisor 5/6/2019 2 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: iim.reaa(Walaska.aov: AOGCC.lnsoectors(oialaska.00v phoebe. brooksuRalaska.gov OPERATOR: ConocoPhillips Alaska FIELD / UNIT / PAD: CRU/Alpine/CD4 DATE: 03/30/19 OPERATOR REP: VanCamp AOGCC REP: O= Other(Eescnbe in Notes) chrismallacelaalaskiii Well CD4 -12 Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. O= Other(Eescnbe in Notes) 4=Four Year Cycle PTD 210-091 Typelnj G Tubing 3865 3847 3847 3849 O = Other (describe in notes) Type Test P Packer TVD 7044 BBL Pump IA 10 3300 3250 3250 Interval O Test psi 1761 BBL Return OA 436 1 457 457 457 Result P Notes: Diagnostic MITIA 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 I 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 INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W=Water P=Pressure Test 1=Initial Test P=Pass G=Gas O= Other(Eescnbe in Notes) 4=Four Year Cycle F=Fel 8=Slurry V= Required by Vanance 1=Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Form 10-426 (Revised 01/2017) CN -12 Diagnostic MITA 3-30-19.xlax WNS INJ ConocoPhiilips lWell Attributes Max Angle&MD CD4-12 TD Alaska, Inc. WeII .RPWWI FXI. Xeme 501032041401 ALPINE WeIIIwrc Slalua nel l') ND IXKBI MI Bim (XKB) IN91.73 13,295.53 113,004.0 Cwnmenl Xt51PYn) C. ph—p—EM DLe KBSrdpQ Mg"me DM =SSV: NIPPLE Last WO: 4921112 HORaonlu.cD4tx,7mweltpe4e AN Last Tag MngMbn LaATag: OeNIK MIN EMMe Lem Moa By Il1I0500! Last Rev Reason ATOPPRIen Fna DNe Last moe ay Rev Reason 'PULLED/SETA-11NJ VLV 292018 pMoven Casing Strings HPNGER,T5� 11 Ce p!Deeenglen oD gni iD(in) CONDUCTOR,;' 16 15,250 Topinrc8) Set Depth(Not) sI Depin R'VDI_ WVLan6_Cbae TOP Thread 35.0 112.0 112.0 6250 H< Welded InsuWleO C., De%rIMI.. 0011n1 ID(In) TOP IXKBI set Depth MR) aN D,eP nuDT.. WYLen ll_. Oraae TOP Threna j SURFACE 95/8 &1335 34.7 291015 2,395.1 40.00 L410 W .I Ceel"I M.. 00(1n) IO lin) Top IXKBI $n DeMh MIN Set Depth HVIR- WIILan P... .. TOPTIltm INTERMEDIATE 7 6.276 34.5 11,4970 7,383.5 25.00 L-80 BTCM CMn90e6CXpnen OD(in) IO (In) 1.111X(8) Set Depth Me) Set Deph(TV03.. WNLen IC. Druce TOP HIN,N OPEN HOLE 5.151 11,4970 16,351.0 Tubing Strings Tharp Oeeanpimn BirinPNa...ID Pn1 rep lnrce) 9ei D.Pm m.. BN oepInIT911... 50111th;; .rade TUPenn .,— TUBING 41rz 3.956 31 9 9.980.6 ),096.) 12.80 LEO 191-M Completion Details CONDUCTOR 3e'NaWba: )561RA TOP PVD) TOP IwI Tep(nKB) Nus) 17 INm Dea CO. Nominal IO pn) 31.9 31.9 0.00 HANGER FMC 11x4 ITTUBINGHANGER 3.958 2,177.2 1,980.7 50.29 NIPPLE C.rT. HA .0 LANDING NIPPLE wl DB PROFILE 3.813 9.834.1 7,043.7 67.90 PACKER BAKER PREMIER PACKER 3.875 Ml OXW:2.11L2 NIpRE, 21]]] 98944 7,066.0 68.56 NIPPLE HES'XNNIPPLE NO GO 3.725 9,9792 7,096.3 69.91 WLEG WIRELINEENTRYGUIOE(525-OD-4-10) 4.000 Omer In Hole Wireline retrievable plugs, valves, pumps, fish, etc.) TOP T,F'r TOP (NKBI NK0) Des Com Run Dak ID 11n1 2.177.2 1.980) 50291NJ VALVE 3.51-DBLOCK,SPACERPIPEA41=NIHACS-0028) 212018 I Mandrel Inserts th NU On 1I TeP501B) TOP MMe YaaN OD In 1 ) Wile yr, Valve Type PDX ), TYPe lype Port TROIRun Run bile Co m suRFACE:HA2A10.5— 1 7,458.2 5,577.8 CAMCO KBG2 1 GAS LIFT DMV P. 1. 0.0 1.To 2 9,111.1 6,999.9 CAM00 KBG2 1 GAS LIFT DMV BK 1. 00 11102010 Notes: General & Safety Ene Dae MnONllon 9/812010 NOTE: VIEW SCHEMATIC AIeaIO SPJNmati S.O DAe LIFT:1,e5a3 GASUPTST721.1 NIPPLE 9.0el e TILEG', 9.9712 INTERMEOMTF NS11HB10� •'• OPENHOLE.11ART(T19]51.0— Name: I CDI-12 Date: 5-Feb2019 99 Dare: 6-Mat-2019 9efi h Annular Communication Surveillance e5M � a000 1Ao 310 130 3oW no 25. 110 a00 c SO ssw 90 1000 20 Soo a0 0 So 9 a S � 3 9 9 9 ^ ^a}, • � —Ww —W —OAP —WM Annular Communication Surveillance 4000 'M ^ �I O 2500 f 2000 O m 1500 1000 500 II 0 9 A 9 9 9 9 9 °I ttf9� kk —DGI —WI —PM SWI —91PD tlER 12 ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 December 2, 2018 Commissioner French Alaska Oil & Gas Conservation Commission 333 West 7" Avenue, Suite 100 Anchorage, AK 99501 Dear Mr. French fVPL D DEC 0 5 In A0U%CC ConocoPhillips Alaska, Inc. presents the attached proposal per AIO 18D, Rule 11, to apply for administrative approval to allow injection well CRU CD5-316 (PTD 217-040) to remain in water only injection service. Currently the well has known tubing by inner annulus communication only while on miscible injection. If you need additional information, please contact us at your convenience. Sincerely, Smv'� 0"Sw Sara Carlisle Well Integrity Supervisor ConocoPhillips Alaska, Inc. 907-659-7126 ORIGINAL ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 Alpine Well CD5-316 (PTD 217-040) Technical Justification for Administrative Relief Request Purpose ConocoPhillips Alaska, Inc. proposes that the AOGCC approve this administrative relief request as per Area Injection Order 18D, Rule 11, to continue water only injection for Colville River Unit injection well CD5-316 (PTD 217-040). The well displays tubing by inner annulus communication only during miscible gas injection (MI). Well History and Status Colville River Unit well CD5-316 was completed in September 2017. CD5-316 was initially reported to the Commission on March 8, 2018 for a suspect inner annulus pressure increase while on miscible gas injection, however, the IA pressure appeared to be normal during a diagnostic monitor and the well was returned to normal WAG injection status. The injector was reported again on October 27, 2018 when the suspect IA behavior reappeared during MI injection. Passing diagnostic tests including wellhead packoff tests and a MIT -IA were performed October 29, 2018 (MIT -IA results are attached). An AOGCC approved diagnostic monitor period on MI commenced; However, the MI monitor period was discontinued early because the IA pressure build-up rate during the monitor required at least two bleeds per week to maintain the IA pressure below the Do Not Exceed pressure threshold. A new plan was communicated to the Commission to switch to a water injection monitor period instead. Water injection was commenced and no TxIA communication was observed during the water injection monitor period. Therefore, ConocoPhillips requests an Administrative Approval (AA) which will allow for continued water only injection. Barrier and Hazard Evaluation Tubing: The 4-1/2", 12.6 lb/ft, L-80 grade tubing has integrity to the seal assembly at 19,167' MD (7438' TVD), based on passing a MIT -IA to 3000 psi on 10/29/18 and TIO trends. Intermediate casing #2: The 7", 26 lb/ft, L-80 grade casing has integrity to the seal assembly at 19,167' MD (7438' TVD), based on the passing MIT -IA aforementioned and TIO trends. Primary barrier: The primary barrier to prevent a release from the well and provide zonal isolation during water injection is the tubing and seal assembly. Secondary barrier: The Intermediate Casing #2 is the secondary barrier should the tubing fail. Monitoring: Each well is monitored daily for wellhead pressure changes. Should leaks develop in the completion it will be noted during the daily monitoring process. Any pressure trends that Well Integrity Supervisor 12/2/2018 V: ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 indicate annular communication require investigation, Commission notification, and corrective action, up to and including a shut-in of the well. TIO trends are compiled, reviewed, and submitted to the AOGCC for review 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 and operating OA pressure up to 1000 psi; 4. Submit monthly reports of daily tubing & IA 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 on the August 30, 2019 (last AOGCC witnessed test was October 25, 2017) to align the AOGCC witnessed testing with the UIC MIT permanent 4 -year scheduled pad testing. Well Integrity Supervisor 12/2/2018 TIO Plot: CD5-316 8308 J c 3 aJ fi roo i C � 9118818 8181x818 R'15a819 B/OlN le 92d'3818 1858813 IBII JRe1B 18202816 IeR]a810 1t131I816 SOOJ 5000 13. s ,o Bi6o � 1mo 16>0 10>e B 0 ollrz8le owol. 81.1. eaxaom MMOIB 1olMole +x168018 10RMo16 IwIn 1. 11.ol. IA Presslxe Bleed Evens We111D oMnme el.etl _ sM1 TaPm.unw EnM..Prt..0 leu 1A deM A—`o P Uctlm Petlely DBnnle cCe31e w+/.Ie n:vsl AM z]W 02] 1e8] cos cP3J16 +wwo Ba 18:6D PM 1. ]M 1. wus cM31fi 1Q9aDiB B. so PM 29U 815 ti AS WNS C85 OA Pleos.. Blood Events Wa11. DMeTnle. • 6x.11111.8 ..... DA Ending Pressure DP GA 81. A—.. Pm ..co,, D ..rills lie CW316 S'I V.te ]31:51 PM 1 na 313 euc�6 cD5 10oe cobl by 16W ''l Icawu, avmeM •• �AgIG..I^MLm R... 4 �A'Blcs_Pcean R.. olio •ApIlMMr l�Rrlim x�a _ A�IWvmr.lnpylbn Rela) ?'SBM Y do nvplGn.I nlealen Peyl o @a L Q 111102018 11ry ]a MB 111301x010 1211 Ro10 . w Icdumn wnle.) (C •Are(%"e T.- P.—) • AwM Pre.wel ft(OAR .) • "(ptie4 Resare) ® Avx1ow..diemP.r.arcl Y d 0 ++nMme 11117.1. Ila Mi$ I..,. AIMP WNS INJ CD5-316 Conocoph(llIps Well Attributes Max Angle & MD TO AlasK8, Inc. W<Ilpo,e APUUWI FIeMNLme 5010320]5000 NANUDKUPARUK Wellbore 9lLue INJ ncl l'1 mDlnx2 Ae Mm(0.7 93.29 20.Id8.66 2],]98.0 Cpmmenl N2S(ppm) Dale 9SSV: NIPPLE Annolanon EniDne LR#WO'. XBL,C ph N9 RdeW Ode 3646 9262D1] .' CDSslpnu sDI73Y5a0Pm [e oma e[ Wep Mnonllan DepIM1(FNB) -:1 -'o -on LTIMW By on. M! 1 RDV Reason: NEWWELL, GLVCM SETINJ pproven UM2762017 NUIGER:aIA VALVE _.. __...____ .._...._. .-tFslng ngs Cooing DeerlPllon 00 /lnl IDDnI Too indnB) BN OepX, IXNBI Bel 0epm 1TV01... WTJLon S... 0[Ne Top TFIN4 ...._ .. ... _..._..._..�.. .....�.-.... ...... CONDUCTOR ZO IRIM 36.5 115.5 115.5 78.60 B Welded CaLq D"'nonon 00 (in) IDpn) TapMan SdB1 Sdph"(sw NipanNIL.. WOUnIL,. 0. Tap TK.SURFACE 13318 12415 35.5 21369.8 2,176.3 68.00180 14563 CW,p Oss.,i MR.) IDllnl Tap MKB) "Mon,(WB) SM pepF(MI)... VNLs IL.. GI'aae T4PThm6 INTERMEDIATER! 9548 8.960 1,987.1 MAMA 8,068.4 40.00 LW BTCM Coon, Dewnpoon oopn) IDD.) Topmon" Bel Dep'MKB) -Nish DVD)._ WIILen II...... Top Thn. INTERMEDIATEI021nM 7 6.276 33.6 13,689.3 6.020.9 26.00LW BTCM beck. CONDUCTOR;YS1155 CpIn90e-pilon (I -ft) ID (In) TPoMNB) 9e1 Dep[M1 (XXB) M NM (M),-MTILen 6... solo Top Thntl INTERMEDIATE42 7 6.276 13.681.6 19.3330 7'*457 28.00LW H563 Ceeln9 Demmplon DD (in, MPn) Top II 6d 0eIn 76X81 Sn DepN IM],., WV Len ll... Gnae Top TM1rctl LINER 412 3.956 19,169.8 2],778.0 7,470.3 1260 LW TXP-M Liner Details NemIwI1D INJECTION NV: 2...Top (XNM Top ITVD)MXBI Tap Incl l') Fein Dn Cam 6n1 19.169. 7'*38.4 87.08 ""SKI 580'SeM'slsove WJS•ID 500 19,185.9 639.2 87.10 PACKER 0.12'x T 268 III ZXP Lin. Top Packer &875' 385 seal Bme SURFACE: 35&2x69.8 I 19.1960 7.d39.8 87,11 HANGER 412'x7'1`1 4.suk LWelhsnUoF .950 19,206.3 7040.3 8].12 XO Red=', Crwaover Bushing 4-1?Ld0 Hyd 5216M7% 4.000 (Cooing) 12.69 TXP pin GABUFT:3,ve2 Tubing Strings Tuioing Ro,ru.n Woo Na.. 1011'1 Tep(ftK Set CeplM1 (R.. Sal Cepin llVD1 (... WI(IbMll G[Me Top Connaelion 4.5HW563 410 3.958 310 19,181.3 7.439.0 12.60 Ld0 14563 Completion Completion Details INTERMEMWES2Tlelous NPTIMM 33&136693 TopMFe) T"ITVDIMKB Tap Incl ET (in) 31.4 31.4 0.00 HANGER FMC0.if Tub11NHMIgerTC.I1Topx Hyddi563BoMxn &BW C.FON: I3.711200K9 2,203& 2,059.8 40.36 NIPPLE NIPPLE.LANDINGA 12',X,3.813•, HYD563 3.813 IxTERMEDIATEsl: L6eT I. 13LL e 146222 6,37.0 70.57 SLIDING SLV 9LEEVE.SLNJING'*N2,CMD.6AKEH,&813'X. 3.813 Hwsz4 5UDIN6#.v. 116233 14,877.8 6.355.2 71.21 NIPPLE NIPPLE.LANDING,412'.3.81WM. 3725 09YD563 WXF RHC PWg BODY InodlleO Pure09J3GR017) 19,166A 7,4382 8].09 LOCATOR LOCATOR SUB WJ 2.86 SPACEOUT 3930 19.165.9 7.438.3 87.09 SEAL ASSY SEALASSEMBLY 3.930 LDCATOe191No SELL Ibex; 18,108.9 Other In Hole (Wireta)line retrievable plugs, valves, pumps, fish e T D) TopIncl Top MKBI M1KB 1.1 pea Com Run Die IDllnl 2203.0 4059.3 W.951NJECTION INJ. VALVE(MCXJ inXNIPPLE ON 3.8P%LOCK 1W1B20O 1JW V V (3) Mandrel Inserts M en N TOPDVDI Vdw LY[n PM 91n TRORan Top1nK0) IFKBI M4< Maael ODllnl 9ery Typ Typ R.) (pal Run MM Com INTERMEDIATE e2'. 13.014 3,399.] 2,7733 L. KBG2- 1 GAS LIFT DMY 9 0.000 0.0 IDJI&2017 9"30 9 Notes: General & Safety En909e AnnMnbn 92&201 OTE: MNER:1B1696P.Tiae STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: iim.reaa0alaska.aov: AOGCC.Insoeclors(rDalaskaOov: ohoebe.brooksGDalaska.aov OPERATOR: ConocoPhillips Alaska Inc, FIELD/UNIT/PAD: - Alpine / CRU /CD5 Pad DATE: 10/29/18 OPERATOR REP: Duffy AOGCC REP: O= Other (describe In Notes) chrismallaceCotalaska.00v Well CDS-316 Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. O= Other (describe In Notes) 4=Four Year Cycle PTD 217-040 Type Inj G Tubing 3874 3875 3875 3875 O = Other (describe In notes) Type Test P Packer TVD 7438 BEL Pump 4.6 IA 725 3000 2970 2970 Interval O Test psi 1860 BBL Return OA 455 536 538 538 Result P Notes: Diagnostic MITIA to confirm casing integrity Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBLPump 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 1313L 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 BBLPump 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 = 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) CD5316 Diagnostic MITIA 10-29-18.xlsx 11 ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 October 29, 2018 Commissioner Hollis S. French Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Dear Mr. French: RECEIVED OCT 10 2018 AOGCC ConocoPhillips Alaska, Inc. presents the attached proposal per AIO 18, Rule 9, to apply for administrative approval to allow CRU injection well CD2 -02 (PTD 205-109) to remain in water only injection service. Currently the well has known tubing by inner annulus communication only while on miscible gas injection. If you need additional information, please contact us at your convenience. Sincerely, Rachel Kautz Well Integrity Supervisor, ConocoPhillips Alaska, Inc. (907)659-7126 OR IjINAL ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 Alpine Well CD2 -02 (PTD 205-109) Technical Justification for Administrative Relief Request Purpose ConocoPhillips Alaska, Inc. proposes that the AOGCC approve this administrative relief request as per Area Injection Order 18, Rule 9, to continue water only injection for Colville River Unit injection well CD2 -02 (PTD 205-109). The well displays tubing by inner annulus communication only while the well is on miscible gas injection. Well History and Status Colville River Unit WAG injector CD2 -02 was reported to the Commission on June 26, 2018 for a suspect inner annulus pressure increase while on miscible gas injection. Passing diagnostic tests, including a witnessed MIT -IA, were performed on June 27, 2018 (10-426 attached). An AOGCC approved monitor period on water injection took place following the diagnostic tests. During the water injection monitor period, no TxIA communication was observed. Following the water injection monitor, the well was put in MI injection service for an approved monitor period to investigate if the pressurization was linked to MI injection service. In October 2018, it was confirmed that the previously observed IA pressurization resulted from TxIA communication during MI injection. ConocoPhillips intends to pursue repairs if tubing by inner annulus communication develops while on water injection, however, at this point the well exhibits no indications of tubing by inner annulus communication while on water injection. 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 4 ''/2", 12.6 lb/ft, L-80 tubing has integrity to liquid to the packer at 15,415' MD (7106' TVD), based on the passing MIT -IA and TIO trends. Intermediate casing: The 7", 26.0 lb/ft, L-80 intermediate casing has integrity to the packer at 15,415' MD (7106' TVD), based on the aforementioned MIT -IA and TIO trends. Surface casing: The 9 5/8", 36 lb/ft, J-55 surface casing set at 3856' MD (2381' TVD) has an internal yield pressure rating of 3520 psi. The surface casing has integrity based on TIO trends. Primary barrier: The primary barrier to prevent a release from the well and provide zonal isolation is the tubing and packer. Secondary barrier: The intermediate casing is the secondary barrier should the tubing fail. Well Integrity Supervisor 10/29/2018 ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 Monitoring: Each well is monitored daily for wellhead pressure changes. Should leaks develop in the completion 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. TIO trends are compiled, reviewed, and submitted to the AOGCC for review 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 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 for the month of June 2018 (last AOGCC witnessed test: June 27, 2018) to align the AOGCC witnessed testing with the UIC MIT permanent 4 -year scheduled pad testing. Well Integrity Supervisor 10/29/2018 ✓ WNS INJ CD2 -02 COIIOCOrI lllll�i$ ALWI111c. Well Attributes Angle 8 MD TD -----12,x Elora rvame WNIEore PPuu WI .11.resL,me rj MD (nne) or T`l<e) ALPINE 501032051300 [NJ J6 21,129)6 21,1)8.0 Comment Hi8 (ppm) Oale Mnobtlon longues, KBGM IN Reg Release Oah SSSV: WRUP last W0: 43.81 024/2005 CG2-0i. biVAta]EQi AM Last Tag VenlNxMmalklavical) Annoiatlwl Ena Dah DepN m..)IJa[got BY last Tag: 12/122005 76.009.0 WV5.3 Conversion _..... ._ Lasl Rev Reason HANGER. `DNP -TDR. n]avaD —v 2'J31 NIPPLE 2,"' I auNFACE:3R9J.Lsa3� GAS UEE 15.3014 PACKER, 15 <te9 MPPLF, 15.6]fi.1 WIfG 1549] t 1111 WEN HOLE 16.019.631,1R.0 -r 1111 Annotation Ena DaM I,astMW By ReV Reason: Circ On IA for SWMIT ;2;2018 raineg Casing Strings easing DesmvDon oD(Inl ID gn) Top 1x691 set➢epin (rticel sa Dep to R II(S,. vALm (L.. Gr ate Top Tdrean CONDUCTOR 16 1506 37.0 114,0 114.0 62.50 H-40 WELDED casing DBacnpilon OD pin, ID Big TopinKal set Depths t aN DeploMITI,- W1Len g_ Grade Top Toreaa SURFACE 9518 892 369 3°856.3 2,380.9 36,00 1 BTC easing Descdptlon OD fn) IDpn) Top(nKB) get Depto(SKal set Dersh j... WLLen g... GSNe Top TMeaa PRODUCTION ) 628 34J 16,048.6 ]$59.8 26.00 L-80 STCM Casing Descdptlon OD (Int 10 (ln Top lnNa) Scl Deplo (nKaj aN 0e'U IN0).., WIILen I...G de iop TMeaa OPEN HOLE 61/B i6,Od8.0 21,1]80 Tubing Strings Tool n g 0escrlplion Slring Ma... ID (Inj Tap ItM6) sm 0evtn la. set Deplo (rvD)(... wt ll✓n Grape iop Connection TUBING396 32.8 i5.d866 ),134.5 12.60 L-09 IBTM Completion OetalIs Top(TVD) Top Incl Namina1 Top(nKDI R., °) Item Oes Com 10(1x) 32.8 32.8 0.20 HANGER FMC TUBING HANGER 4.500 2321.] 1]56.3 65.35 NIPPLE CAMCO OR NIPPLE 3.812 15,414.9 ],105.) San PACKER BAKER PREMIER PACKER 3.075 15476.1 ),129.8 67.39 NIPPLE HES KN NIPPLE 3725 1540].1 ],134.0 fi7.66 ;LEG WIRELINE GUIDE 3.875 Other In Hole (Wlregne retrievable plugs, valves, pumps, fish, etc.) Top r) Top HiKal (nNB) Tep lnct rl Des Cmm pun Date ID(in) 2,321] 1,]56.2 65.35 SSSV 3.81"A-11NJVLV(5/N:HR&3W/1.25'ORIFICE) 6/2;2010 1.250 Frac Summary ammah Paoppanl DeslgnMPe) Proppanun Pormnwn SIN sip/ sun Dsre Top Depin MKB) St. (mca) Lmkb FlulasysMm van mean (Ed) vol awrry(ee6 Mandmi Inserts at ti onToo MR) N To(XKB) (rtNBI Make Moatl OO QnI ..pa NIVe laho Type Pott$lic gn) TRB Run (p.) pun Dao Com 15.301.4 ],060.9 CAMCO KBG-2 1 GAS LIFT DMY BK 0.000 0.0 6232016 Notes: Generale Safety Ena Oalc Annoletbn Bl2/2005 NOTE: TREE; FMC 4-1116'SK-TREECAPCONNECTION: TOTIS ;24/2010 NOTE: VIEW SCHEMATIC WAMske SD9IRSAI .0 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: lim.reog0alaskanov AOGCC.Insoectors(a)alaskaaov phoebe. brooksaDalaska.aov OPERATOR: ConowPhillips Alaska Inc FIELD / UNIT / PAD: Alpine / CRU / CD2 Pad DATE: 06/27/18 OPERATOR REP: Beck/Miller AOGCC REP: Adam Fan chris.wallace/o-lalaska aov Well CD2 -02 Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. O= Other (describe in Notes) PTD 2051090 Type Inj W Tubing 2100 2100 2100 2100 O = Other (describe in notes) Type Test P Packer ND 7106 BBL Pump 4.0 IA 380 3000 2985 2985 Interval 4 Test psi 1777 BBL Return 4.0 OA 875 925 925 925 Result P Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD;Typa Tubing Type Test Packer NDp IA Interval Test psirn OA Result Notes: wellPressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Tubing Type Test Packer NDp IA Interval Test psirn OA Result Notes: wellPressures: Pretest Initial 15 Min. 30 Min, 45 Min. 60 Min. PTDTubing 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 BBLPump IA Interval Test psi BBL Return OA Result Notes: TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Cotles W=Water P=Pressure Test I=Initial Test P =Pass G=Gas O= Other (describe in Notes) 4=Four Year Cycle F=Fail 5 = Sluny V = Requlree by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Form 10-426 (Revised 01/2017) MIT CRU CD242 06.27-I8 xles Elate: 35 -am -2018 sa late: 29 -Oct -2015 Peheeh Annular Communication Surveillance 4500 8800 35W 3ovo 1508 zaao 1500 100 sm a —Wro —lar —onc —wlrt Annular Communication Surveillance 3500 3000 2S. 20aa F ON v00a Sao 0 —DGI —MGI —PW SWI —ALPO — --- OUTER 10 ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 February 28, 2018 Commissioner Hollis S. French Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 �LREIVE® MAR 0 2 2018 AOGVC Re: Request to Cancel Area Injection Order (AIO) 18D.001 for Colville River Unit (CRU) CD2 -73 (PTD 208-196) Dear Commissioner French: ConocoPhillips requests cancellation of Administrative Approval AIO 18D.001. The approval was originally issued August 31, 2017 to allow continued water -only injection into CRU CD2 -73 (PTD 208-196) with a known surface casing leak to atmosphere. In February 2018, a surface casing sleeve was welded over the leak to repair the communication, and subsequent diagnostics confirm surface casing integrity is restored. This request is to cancel the Administrative Approval and return the well back to normal injection operation. Please call Rachel Kautz or myself at 659-7126 if you have any questions. Sincerely, C;;le- r vTravis Smith / Rachel Kautz Well Integrity Supervisor ConocoPhillips Alaska, Inc. -J: Wallace, Chris D (DOA) From: NSK Well Integrity Supv CPF3 and WNS <n2549@conocophillips.com> Sent: Tuesday, December 19, 2017 11:47 AM To: Wallace, Chris D (DOA) Cc: Senden, R. Tyler Subject: CRU CD2 -30 (PTD 203-135) Rescinding AA Request Attachments: CRU CD2 -30 TIO Plot 90 -day 12-19-17.docx Chris, An Administrative Approval (AA) request application was recently sent for CRU CD2 -30 (PTD 203-135) at the conclusion of a water injection monitor period. The IA pressure remained stable during the monitor (that ended on Sunday 12-17- 17), however, the IA pressure was found at 2000 psi last night and subsequently bled. CPAI wishes to rescind the AA application recently sent for CD2 -30 and instead continue with an additional 30 -day monitor on water injection in light of the recent pressure anomaly. Based on the outcome of the new water injection monitor period, the appropriate paperwork and/or notifications will be submitted as necessary. Attached is a 90 -day TIO plot. Please let us know if you have any questions or disagree with this plan. Regards, Rachel Kautz/Travis Smith Well Integrity Supervisor, ConocoPhillips Alaska Inc. Office: 907-659-7126 Cell: 907-943-0450 F m: NSK Well Integrity 5upv CPF3 and WNS Sen . unday, December 17, 2017 1244 PM To: Wal Chris D (DOA) <chris.wallace@alaska.gov> Cc: Senden, R. er <R.Tyler.Senden@conocophillips.com> Subject: CRU CD2 -3 TD 203-135) AA Request for Water -Only Injection Chris, Injector CRU CD2 -30 (PTD 203-135) is at the a of its 30 -day water injection monitor period. The well showed stable pressure trends during the monitor period confirms integrity during water injection. Attached please find a digital copy of the request for Administrative Approval (AA) to 31few CD2 -30 to continue water -only injection. Two hard copies have been put in the mail. CPAI intends to leave the well on w r injection while the AA application is being processed. Please let us know if you have any questions or disagree ' h this plan. Regards, Rachel Kautz/Travis Smith Well Integrity Supervisor, ConocoPhillips Alaska Inc. Office: 907-659-7126 Cell:907-943-0450 Well Name: CD230 Start Dale: 20 -Sep -2017 Days: 90 End Dale: 19 -Dec -2017 Bleed Data Refresh CD2 -30 12/19/17 2000 1700 300 INNER PWI ,4nnulef Communication Surveillance CD2 -30 11/18/17 999 600 399 OUTER PWI 4500 ISO CD2 -30 11/4/17 1 600 -599 INNER PWI 4000 140 CD2 -30 10/4/17 2160 960 1200 INNER PWI 3`500 130 CD2 -30 10/1/17 2300 1400 900 INNER PWI 3000 - 120 CD2 -30 9/28/17 2100 1450 650 INNER PWI 2500 _ 110 CD2 -30 9/26/17 2100 1600 500 INNER PWI 2000 100 m 90 CD2 -30 9/24/17 1450 1050 400 WNER PWI 1500 so CD2 -30 9/24/17 1800 1050 750 INNER PWI 1000 70 CD2 -30 9/23/17 2150 1100 1050 INNER PWI 500 60 0 50 w w n w v V yy r r i i b O O yy� i i Z Z. Z y o n N a ^� M m M N —WHP —IAP —OAP —WHT Injection/Production 8000 7000 i 6000 m 5000 C 4000 V 3000 N f 2000 1000 0 a N O yy yy pAyY V Y Z Z Z Z O D N N w w JM1 p M A N Ch ,p —DG1 —MGI —PWI —SWI —REPO 0 Wallace, Chris D (DOA) From: NSK Well Integrity Supv CPF3 and WNS <n2549@conocophillips.com> Sent: Sunday, December 17, 2017 12:44 PM To: Wallace, Chris D (DOA) Cc: Senden, R. Tyler Subject: CRU CD2 -30 (PTD 203-135) AA Request for Water -Only Injection Attachments: CRU CD2 -30 AA Request 12-17-17.pdf,, CD2 -30 Diagnostic MIT 10-25-17.xlsx Chris, Injector CRU CD2 -30 (PTD 203-135) is at the end of its 30 -day water injection monitor period. The well showed stable pressure trends during the monitor period confirming integrity during water injection. Attached please find a digital copy of the request for Administrative Approval (AA) to allow CD2 -30 to continue water -only injection. Two hard copies have been put in the mail. CPAI intends to leave the well on water injection while the AA application is being processed. Please let us know if you have any questions or disagree with this plan. Regards, Rachel Kautz/Travis Smith Well Integrity Supervisor, ConocoPhillips Alaska Inc. Office: 907-659-7126 Cell: 907-943-0450 18 -Sep -2017 90 Annular Communication Surveillance 4500 002-30 140 002.30 130 COZ-30 120110 Cpl -90 4000 100 m 002.30 90 00290 90 CO2.30 3500 z is w d N 4 3000 h 2500 2000 1500 1000 500 0 ^ ^n w w £ x 4 z a m � 16 M z N r4 N o w —WHP —IAP —OAP —WHT Injection/Production BODO 7000 0 6000 m 5000 64000 LL N 3000 2000 1090 0 N u c z p o x x S w N p N M n �0G1 —MGI —PWI CO2 -30 CO2 -30-30 150 002-30 140 002.30 130 COZ-30 120110 Cpl -90 100 m 002.30 90 00290 90 CO2.30 70 60 50 ^ ^ ^ ^ ^ o i i i z is w d N 4 w SWI —BLPD 1 399 GIVER i -599 INNER 17 22W 960 1200 17 2300 1400 90D 2100 2100 INNER PWI INNER PWI INNER PWI INNER PWI INNER PWI-�- 1050 INNER PW 11 ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 December 17, 2017 Commissioner Hollis S. French Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Dear Commissioner French, ConocoPhillips Alaska, Inc. presents the attached proposal per AIO 18D, Rule 11, to request administrative approval to allow well CD2 -30 (PTD# 203-135) to be online in water -only injection service. Currently, the well displays TxIA communication only while injecting gas. If you need additional information, please contact Travis Smith or myself at 659-7126. Sincerely, Rachel Kautz Well Integrity Supervisor ConocoPhillips Alaska, Inc. ConocoPhillips Alaska, Inc. Alpine Well CD2 -30 (PTD# 203-135) Technical Justification for Administrative Relief Request Purpose ConocoPhillips Alaska, Inc., proposes that the AOGCC approve this Administrative Relief request for Alpine injection well CD2 -30, as per Area Injection Order 18D, Rule 11, to allow water -only injection due to known tubing by inner annulus communication during gas injection service. Well History and Status Colville River Unit well CD2 -30 (PTD# 203-135) was drilled and completed in 2003 as a service well for WAG injection. CD2 -30 was reported to the Commission on June 27, 2014 for suspect inner annulus (IA) pressure increase during injection after a packer resin repair attempt. Subsequent diagnostics and AOGCC approved monitor periods have suggested TxIA communication during injection that could not be identified by logging technology available. In October 2016, CPAI requested permission to inject into the well temporarily to re -attempt the acoustic leak detect log during water and gas injection. Again, no leak was detected by the log, however, during the water injection monitor period prior to the logging there was also no indications of TXIA communication. An additional AOGCC approved monitor period on water injection and then gas injection was performed to confirm if TxIA communication was still present. The communication appeared no longer present, so the well was returned to normal injection service. The well was reported on September 26, 2017 for suspicious IA behavior during gas injection. The well was WAG'd to water for an approved monitor period to confirm integrity on water injection. The IA pressure was initially unstable and operations had difficulty maintaining pressure, noting considerable gas in the IA. After new fluids were circulated into the IA, diagnostics were performed on October 25, 2017 (including a passing MITIA to 3000 psi) to confirm integrity to liquid. The water injection monitor was then restarted and no indications of IA pressurization appeared throughout the monitor. ConocoPhillips now requests an administrative approval (AA) to allow continued water -only injection into CD2 -30 due to known tubing by IA communication while on gas injection. Barrier and Hazard Evaluation Tubing: The 4-1/2", 12.6 lb/ft, L-80 grade tubing has integrity to the packer at 10,861' RKB based on a passing MITIA to 3000 psi performed on October 25, 2017, and a 30 -day monitor period on water injection. Production casing: The 7", 26 lb/ft, L-80 grade production casing has integrity to the packer at 10,861' RKB based on the previously mentioned MITIA and monitor period. Surface casing: The well is completed with 9-5/8", 36 lb/ft, J-55 grade surface casing with an internal yield pressure rating of 3520 psi. The surface casing is set at 3006' MD (2380' TVD). The surface casing displays pressure integrity based on TIO trends. CPAI Well Integrity Supervisor 12/17/2017 Primary barrier: The primary barrier to prevent a release from the well and provide zonal isolation during water injection is the tubing and packer. Secondary barrier: The production casing is the secondary banner should the tubing or packer fail. Monitoring: Each well is monitored daily for wellhead pressure changes. Should leaks develop in the completion 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. TIO trends are compiled, reviewed, and submitted to the AOGCC for review on a monthly basis. Approved Operating and Monitoring Plan 1. The 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 and allow operating OA pressure up to 1000 psi; 4. Submit monthly reports of daily tubing & IA 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 test month to be set for June 2018 (last AOGCC witnessed test: June 13, 2014) to align the AOGCC witnessed testing with the UIC MIT permanent scheduled pad testing. CPA] Well Integrity Supervisor 12/17/2017 2 WNS INJ CD2 -30 ConocoPhillips Well Attribute. Max Angle S MD TD Aay'ta, nC. WllaproAPYWII FHIa Hama PMBNon Sklus 501039146500 ALPINE WJ nd '1 ADIS, /W BIm1XX61 92.R 121583] 15,]00.0 Dmrynnl NSO(Pwn) ..LL MSV: NIPPLE MnoliM Ena Owe XBGrn al) pie R.hiN aM• bst Vi0: 43.91 1W30rXOK1 cot-ao. 19IWAn Hde9AM Annolwlon MAIN e1Na1 EM O•Is Mrunnoon Leal Moa ey Ena Dele Last Tag: Rpv Peason: PULL A -f INJ VALVE, SET DAT, ppmven 1216I20P GLV —. SET PLUG, FULL PLUG as ng wrings, carne M.mwl.n oo OM I.n) Toplpxel ...Mo.) neo.wNmo)... wuIs. O... c,. a. mP 11—A DcYNDIJ TOR 16 15.062 37.0 1040 109.0 6250 "0 WELOED - D.Nn,..pl.n OD lin) Ia Qnl TOPINX61 e010egn IXXB1 Sel YapNlrM)... NNLn .. 6ryaa TopTNmaa SURFACE 9516 6921 36.] 3,008.3 2,3]9. 3800 JA5 BTC CAgnP O.aMPnnn Oe lin) IDmI Tep eIXel s.IDrom NXal Set D.Pm IND... mlL 11... Ona. r.vinMa unxccn.aea PRDOUCTION ] 62]6 34.9 11,181.1 7.301.6 26.00 LA0 BTCM .i.e. VIPNon OD (In IDiln T"Yon) .w MwN lNpal !,SD. (IVO)... ML. II,., GrM. TnPTNmN OPEN HOLE 61/0 6.125 11.481.0 15.]00.0 ].288.8 Tubing Strings Tnewg Mvmpuon sang Ne... 10 Ont Ton m.) sN O.pIN IN.. sl wpm pool f- wI aXel Dna. mp cnnnwloo NBING 412 3.950 320 10,9362 ],122/ 1260 L-00 IBTM Completion Details Xa lto TnpwKal rev lTvol Ouzel TOP Ind (9 Iwm Ma C.m (In) 32.0 32e 0.10 NMIGE FMCTUBINGHANGEA 4500 2374 2A16. 54.58 NIPPLE CAMCO CB NIPPLE 361 10,051.2 ,089.1 0319 PACKER BAKER SA PACKER WMILLOUT EXTENSION 3875 10,925.9 ],11].1 64.59 NIPPL RES 'XN NIPPLE (PAN U ) 3.125 cONOOM0R 1?a14r.0 fFSMT ,1 64.61 1 MEG WIRELING ENTPY GUIDE 3.975 Mandrel Inserts w XVPLE?]141 en X Top IXKBI TnplNo) (NKN) NnYa M.I. CO tint 8ery KNa Typ YNN Try. PBX NA (In) T0.0pun Iv.q pun O.X Com t 10.]46)CAMCO KBG-2 1 1 GASLn-I 0MY BK I 0000 0.0 10201201] Notes: General & Safety Ena Dao AA.S,n 102919103NOTE, TREE: FMC 41116 So TREECAPCONNECTION: 7'0715 5/1]2NOTE. Ww Salemac wl AuSIM SCM1emaSaO 12162016 NOTE: Tmubnd Wth TxLA mmmr1cNlon,8 recently NO9em0nslreled an elevalM suslalneX M Pmmur 1&6Y2010 NOTE: In wde110 faclftele diagnosllce, Not IN sWuld Oe circulated to Olean fluid. GAS LIS r. tA?4A 7 PAtltER: 10,H11 s wLED:f4.Paes PRBDunIOX:aS.npeu— DPw Xou: l ua va 1a,]w o-- STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Teat Submit W: IimseaaAalaska.00v: AOGCC.Insoeclors0alaska.00v: phoebe brooks@alaska oov chris.vrellam0ala9ka.aov OPERATOR: FIELD I UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: ConomPhillips Alaska. Inc. Colville River Field / CRU / CD2 1025117 Well CD2 -30 Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. G=Gee PTD 203-135 Type lnj W Tubing 25D 250 250 250 Type Test P Packer TVD 7089 BBL Pump 3.0 IA 200 3000 2950 2950 Interval O Test psi 1772 BBL Return OA 180 190 195 195 Result P Notes: Diagnostic MITM 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 Out Result Notes: TYPE INJ Codea TYPE TEST Codes INTERVAL Cos. Reade Calls W=WNcv P=Pressure Test I=Insist Test P=pass G=Gee O= Other(descnbe In Notes) 4=Four Year Cycle F=FYI a=Stan, V= smeared by Venance I=lnconchelve 1= Indutinal Waatawatar O= Otbr (describe N nobs) N - Not In*fmg Form 10-426 (Revised 01/2017) W2J Diearosfc MIT 10.2S17.xlsx 7 ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 October 12, 2017 Commissioner Hollis S. French Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Dear Commissioner French: RECEIVE® OCT 19 2017 AOGCC ConocoPhillips Alaska, Inc. presents the attached proposal per AIO 18D, Rule 11, to apply for Administrative Approval allowing CRU well CDC -55 (PTD 203-118) to be online in water -only injection service due to previously diagnosed TxIA communication on gas injection. If you need additional information, please contact myself or Rachel Kautz at 659-7126. Sincerely, Travis Smith Well Integrity Supervisor ConocoPhillips Alaska Inc. ConocoPhillips Alaska, Inc. Alpine Well CD2 -55 (PTD 203-118) Technical Justification for Administrative Relief Request Purpose ConocoPhillips Alaska, Inc. proposes that the AOGCC approve this Administrative Relief request as per Area Injection Order 18D, Rule 11, to continue water -only injection for Alpine injection well CD2 -55. The well has known tubing by inner annulus (IA) communication when on gas injection. Well History and Status Colville River Unit well CD2 -55 (PTD 203-118) was completed in October 2003, and placed on injection in December 2003. In July 2017, the well was reported to the Commission for slowly increasing IA pressure while on gas injection. During AOGCC approved injection monitor periods, pressure trends showed TxIA communication exists only when the well is on gas injection service. Diagnostics performed during the monitor period, including passing MITIA and packoff tests, also confirmed the well's integrity to liquid. ConocoPhillips requests an Administrative Approval (AA) to allow the CD2 -55 to remain online in water -only injection service. Barrier and Hazard Evaluation Tubing: The 4-1/2", 12.6 lb, L-80 tubing has integrity to the packer at 11,126' RKB (7,128' TVD) based on a passing MITIA to 2,960 psi on 8/4/2017. Production casing. The 7", 26 lb, L-80 production casing has integrity down to the packer at 11,126' RKB (7,128' TVD) based on the previously mentioned passing MITIA to 2,960 psi. This production casing has an internal yield pressure rating of 7,240 psi. Surface casing: The well is completed with 9-5/8", 36 lb, J-55 surface casing. This surface casing has an internal yield pressure rating of 3,520 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. Monitoring: Each well is monitored daily for wellhead pressure changes. Should leaks develop in the tubing or casing 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/UO plots are compiled, reviewed, and submitted to the AOGCC for review on a monthly basis. Proposed Operating and Monitoring Plan 1. Well will be used for water -only injection service (no MI or gas injection allowed); 2. Perform a passing MITIA every 2 years to maximum anticipated injection pressure; Well Integrity Supervisor 10/14/2017 3. Allow operating IA pressure up to 2000 psi, and operating OA pressure up to 1000 psi; 4. Submit monthly reports of daily tubing, IA, and OA pressures, injection volumes and pressure bleeds for all annuli; 5. Shut-in the well should MIT's or injection rates and pressures indicate further problems with appropriate notification to the AOGCC; 6. Anniversary month to be set as June 2018 (last AOGCC witnessed MITIA: June 13, 2014) to align with the ConocoPhillips Alaska, Inc. UIC MIT Permanent Test Schedule. Well Integrity Supervisor 10/14/2017 WNS INJ CD2 -65 we Iv�w r nnEM� rvwl E URUUTes Max Angle It MD TO Alaska.ln0. wmewe A,BBvn PMmeam. wam.n,d Nus ..".) MD(SHE) dN e1m(MCB) 501032066300 ALPINE INJ 92.91 14,338A6 15,2380 Cemmem WE(ppml ONe M --NM- End Dse KB .M) RI9INaaee O. <oiss. tn4rz0u 224m pM S8SV: NIPPLE Last WO: 4390 10112003 Ve Nee ara aquW ZWTE n Oepm IXNB) EM— AnnWn.n LM MM By BIdOM LBN Tag: Ray Reason: INJ VALVE C/O. GLV C/O pproven 1111yp16 as ng ngs xAxcEl+:sie ON, In, oeec,pN.R oG 0.1 ID 6nl Top IONS) BNG.pn(XKM sel DegX(T )._wuLen lL.. Daee Tep TXlaae CONDUCTOR 16 15.082 3].0 109.0 109.0 62.50 Nf0 WEIDED CO1n00eecllpllon O011q I011n) Tep(XKB) SN OepIb 91KBI 3N dp1111TVD).. w8bn 6._GMe Tep Thread SURFACE 9618 0.921 386 2,]96.6 2,403.1 3fi.00M 8TC coon, B DaeanpU n 60 PM 71") TOP index eN Dap611NK-) Sen pope lTw)... wXLen lL.. cMe T., nod INTERMEDIATE ] 6.278 34.8 12.210.2 ],344.8 2800 Lm ETON! C." OD(Inl 10 (InI TeP IXNH/ S.I Dep -611®) Ben pyJl.......MM Q...GMe Top TnrtN OPENHOLF 8118 6.125 12,2102 15,238.0 Tubing Strings Tubin90aee4Ptlan 911-1 M., 'D (in) TeP(XKB) BMOepin ln_. sN Oep1111TN01 r.. 1M 11WX1 6Me TeDCmMtllon TUBING 4 i2 3.958 32.6 11,995.2 ],331.4 930 L -ell IBTM Completion Details COxDVCTOR',37af090 x nmanD Tep(nxe) Top (1Y➢NryKB) Pop llKl p) from Ove com R.) 324 321 LL13 HA - FMC ID -1-0 HANGER 4.500 2,26.8 1,969.9 4052 NIPPLE CPJACO-DB'NIPPLE 3,812 11,02)4 ],091.2 B6.B0 NIPPLE HFEWNIPPLE 3,813 11.125_] 89.35 PACKER BAKER PREMIER PAGKEfl 3.0]5 NIPPLE. 23478 11,934.6 ],324.9 83.0] PACKER BAKER PREMIEfl PgCKEN 3.8]5 vdLVE.?x4e.6 11,982] ],330.2 86.3] NIPPLE NES 'XN'NIPPLE 3)25 11,993) 7,331.3 8468 WiEG BAKER WIRELINE ENTRY GUIDE 3.875 Other In Hole Wrellne retdevable plugs, valves, pumps, fish, eta) Te Top(1Vp) Top Incl PI PIKE) IS IN ('1 $248.0 f, .2 40.5 Dee C. VALVE AIINJ VALVE ISM HWB-0363) Run DWID 1/132016 lin) 1.250 Mandrel Inserts IN .1 H TW IOK8) Tap ITYDI (XKB1 MaFs MadN 00(In) Sery VNd Typ LoonPoK SIia Type (RI) TRO Run ("I) Run same Co. M489.0 6,850.1 CAMCO HOG -2 1 GAS LIFT DMY I.A. 0.000 0.0 2124/2015 12:30 BYRfAC E:]n Elon HOt0s; Geneml dl S•a}ea,• •) Ena OiN Rnnolon 8912003 NOTE: CEMENT SOZ011,3ar-12,tar CTMD, MILLED OVP, REDRILLEO BY RIG 10/12003 NOTE: THEE: FMC 4 V16 SK TREE OAP CONNECTION: TOTIB 101122010 NOTE: VIew Se Icwl Alaska Sc0ematic9.0 ces UKI. wa1 1127=1 NOTE: ICE PLUG AT2RO6LM NIWLE 11,0271 PACKER. 111251 IN W.CKER. 119148 NIWLE: I PIN? > IN EG. 111992 INTERNEDMTE', 346122102 OPEN HOLE. 12310?15R360— Mame: CD2 -55 Date: 15-Ju1-2017 I -195 90 We: 13 -Oct -2011 Refresh Annular Communication Surveillance 4500 9/8/17 _5 200 -195 INNER MIS 4000 - 7/29/17 _2400 1000 1400 INNER PWI 3500 7/25/17 2160 800 1360 _ INNER _ MIS 3000 7/24/17 70D 1100 -400 INNER_ MIS 2500 7/22/17 _ 2190 _ 800 1390 INNER MIS c 2000 7/16/17 2400 , 400 INNER MIS 1500 1000 500 D N N V1 _WHP —IAP —OAP —WHT Injection/Production 3500 3000 5 zsoD 2000 0 V 150D 1000 500 0 n ti n —DIG] —MGI —PWI SWI —BIPD 170 150 130 LL 110 a 90 70 50 Bleed Data C132-55 9/8/17 _5 200 -195 INNER MIS CD2 -55 - 7/29/17 _2400 1000 1400 INNER PWI CD2 -55 7/25/17 2160 800 1360 _ INNER _ MIS CD2 -55 7/24/17 70D 1100 -400 INNER_ MIS C132-55 7/22/17 _ 2190 _ 800 1390 INNER MIS CD2 -55 7/16/17 2400 2000 400 INNER MIS C Colombie, Jody J (DOA) From: Wallace, Chris D (DOA) Sent: Thursday, September 21, 2017 9:10 AM To: NSK Well Integrity Supv CPF3 and WNS; Colombie, Jody J (DOA) Cc: Senden, R. Tyler Subject: RE: Request for Reconsideration of AIO 18D.001 (Colville River Unit) Rachel, My oversight. We will change the AA to reflect the requested OA 250 psi limit and re -issue ASAP. Thanks and Regards, Chris Wallace, Sr. Petroleum Engineer, Alaska Oil and Gas Conservation Commission, 333 West 7t' Avenue, Anchorage, AK 99501, (907) 793- 1250 (phone), (907) 276-7542 (fax), chrismallace analaska ¢ov CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Chris Wallace at 907-793- 1250 or chris.wallace@alaska aoy. From: NSK Well Integrity Supv CPF3 and WNS (mailto:n2549@conocophillips.com] Sent: Thursday, September 21, 2017 8:59 AM To: Wallace, Chris D (DOA) <chris.wallace@alaska.gov> Cc: Senden, R. Tyler <R.Tyler.Senden@conocophillips.com> Subject: Request for Reconsideration of AID 18D.001 (Colville River Unit) Chris, I returned to the slope yesterday and was reviewing the new Administrative Approval (AA) AID 18D.001 for CRU injector CD2 -73 (PTD 208-196). Based on the pressure trends for the open shoe OA, I believe operations may have a very difficult time maintaining the OA pressure below the 100 psi 'Do Not Exceed' (DNE) pressure limit set in the AA while the well is online. I would like to inquire if the AA could be changed to allow the OA DNE pressure to be set at 250 psi, as requested in the original AA application, since our diagnostics indicate that the surface casing leak is not active at 250 psi and the shut-in OA pressure appears to settle below 250 psi. Will I need to submit this request for reconsideration by mail or will this email suffice? Regards, Rachel Kautz/Travis Smith Well Integrity Supervisor, ConocoPhillips Alaska Inc. Office: 907-659-7126 Cell: 907-943-0450 5 ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 August 29, 2017 Commissioner French Alaska Oil & Gas Conservation Commission 333 West 7"Avenue, Suite 100 Anchorage, AK 99501 Commissioner French, RECEIVED AUG 3 12017 ConocoPhillips Alaska, Inc. presents the attached proposal per AIO 18D, Rule 11, to apply for an Administrative Approval to allow well CD2 -73 (PTD 208-196) to be online in water -only injection service with a surface casing leak to atmosphere. If you need additional information, please contact myself or Travis Smith at 659-7126. Sincerely, Rachel Kautz Well Integrity Supervisor ConocoPhillips Alaska Inc. ConocoPhillips Alaska, Inc. Colville River Unit CD2 -73 (PTD 208-196) Technical Justification for Request of Administrative Approval Purpose ConocoPhillips Alaska, Inc. proposes that the AOGCC approve this request for Administrative Approval, as per Area Injection Order 18D, Rule 11, to allow water -only injection into CRU CD2 -73 due to a known surface casing leak to atmosphere. Well History and Status Colville River Unit well CD2 -73 (PTD 208-196) was completed in 2009 as a service well CD2 -73 was reported to the Commission on May 2, 2017 for showing signs of a surface casing leak to atmosphere via the surface casing by conductor annulus. A diagnostic MITIA was performed and passed to 2500 psi. Outer annulus diagnostics were performed and confirmed a surface casing leak to atmosphere, however, further investigation showed the leak would require at least an excavation to repair. ConocoPhillips Alaska, Inc. now requests Administrative Approval (AA) to allow water -only injection into CD2 -73 with a known surface casing leak to atmosphere. Barrier and Hazard Evaluation Tubing: The 4-1/2", 12.6 ppf, L-80 tubing has integrity to the packer at 16,449 MD based on the passing MITIA to 2500 psi performed on May 2, 2017. Intermediate casing: The 7-5/8", 29.7 ppf, L-80 intermediate casing has an internal yield pressure rating of 6890 psi and has integrity to the packer at 16,499' MD based on the passing MITIA mentioned above. Surface casing: The 10-3/4", 45.5 ppf, L-80 surface casing is set at 3657' MD (2384' TVD), but has a known leak to atmosphere. Diagnostics indicate the leak activates at an OA pressure around/above 300 psi. Primary barrier: The primary barrier to prevent a release from the well and provide zonal isolation is the tubing down to the packer set at 16,499' MD. Second barrier: The secondary barrier to prevent a release from the well and provide zonal isolation is the intermediate casing should the tubing fail. Monitoring: Each well is monitored daily for wellhead pressure changes. Should a leak develop in the tubing or intermediate casing, it will be noted during the daily monitoring process. Pressure trends that indicate annular communication require investigation, Commission notifications, and corrective action, up to and including a shut-in of the well. T/I/O plots are compiled, reviewed, and submitted to the AOGCC for review monthly. Well Integrity Supervisor 8/29/2017 Proposed Operating and Monitoring Plan 1. Well will be used for water only injection. 2. Perform a passing MITIA to maximum anticipated injection pressure every 2 -years. 3. Allow operating IA pressure up to 2000 psi while injecting water; operating OA pressure to be held as low as reasonably possible, not to exceed 250 psi, and OA pressure management is to be maintained by bleeds due to an open shoe. 4. Submit monthly reports of daily tubing, IA, and OA pressures, injection volumes and pressure bleeds for all annuli. 5. Shut-in the well should MIT, injection rates, or pressures indicate further problems with appropriate notification to the AOGCC. 6. Anniversary date to be set for June 30, 2018 (last AOGCC witnessed MIT was July 21, 2014) to align the AOGCC witnessed testing with the UIC MIT permanent 4 -year scheduled pad testing. Well Integrity Supervisor 8/29/2017 WNS INJ CD2 -73 eonoeorn1111p$ WellAttributeB MaxAngle&MD TD Aiaska.Im. WelOore A111MI 11.14 Name WJIB—Stalvs n[I (•I MD IxKO) gIt I(ttNB) 501032059000 ALPINE INJ 93.25 18,658.10 21,810.0 Cammenl H25 (ppml Oak SBSV: WRDP gnnolNioO EnE Odle Last WO: KBGrO(x) 0.1g R¢IeaaeDN 44.851 81142009 HOROONI OD973.W7SO1)9M4:30AM cN M,IWNioI Depin(OKB) EM Oa@ MnMnllon Peat M04 By —512e Last Tag: Rev Reason: PULLA-i INJ VLV, SET%%N Op.e.P 512]1201] -.__.-_.-_...._....._......_..._.... PWG n gs µ4XGER: ]tA 8 g D_Pplion DUCTOR nsuatetl Do pn) i6 10(int i5.25p cep NNS) 3).0 Sel Depen (xKBt 114.0 get Depen (TVDt... WULen 114.0 (I... 52.50 Gntle H-40 Tep TM1reaJ Wedetl ) g --c "P., wap m9nl Top (xKa) slOepth (NKeI sal Depth RVDL.. wuLen O... eme. Top Tnreaa FACE iD L4 9950 36.] 3,65).2 2,3802 45.50 L-00 BTGM g Oea[nptien 00(m) ID(in) Top (ryKe) Bet Depen (NKBf Set Depth ME)—WULn (._ ................_...-....-.......-_. RMEDIATE- 75/8 68)5 34.8 3,8]0.2 2,459.9 29.70ERy Deanlptlon DO6n) 10 (in) Top(%Ke) 8th Depen (xNB) SN dpIM1 (rVp)... WULen eRMEDIATE- >5I6 6.8]5 3.8]0.2 1],1]3.0 ],195.5 29 )0ERe Oesulptmn OD (in) loin) Top(XNB) Bet Deptn(MM gm Depth MU),.. wuL.nCONDUCTOR Insetted MIP ingrxg N HOLE 6.151370.1140 ing Stringsg Description glnng Ma...ID(In) Top (NNBf DeplM1 (t.SelDeplM1)TVD](..Wt(lol(tGreed Top C[nneclionING 4112395831 4$e 16,520.8 696! E 1260 L-80 IOTM pletion DetailsInel N[per) op(NNR1 TIP(rvD)PIKE) TIP III (P Nem Lee Wee Snl 31.4 31.4 000 HANGER TUBING HANGER 3958 2,325.9 1,910.2 67.93 NIPPLE CAMCO DE -6 NIPPLE 3.812 16,448] 6.941.6 6908 PACKER BAKER PREMIER PACKER 3.875 165064 6,963.1 68.]4 NIPPLE HES XN NIPPLE 1725 165194 6,967.1 65.68 WLEG UN15UEMACH)NE WI RELINE ENTRY GUIDE 3.875 Other In Hole (Wire[ retrievable plugs, valve's; putttps; fish, etc.) - - TIP(rvDI Tlp Pan SURFACE: M, -365)t iop(11.) 1 )NKB) 16506.0 6,962.9 66]4 PWG 381" .. PLUG w/ FILL 1.(UAL G6",8x3'16' S/2920lle 0.000 EO PORTS) Mandrel inserts INTERMEOATE-NPPER; 349 39]Op gt N Tap (NNB) TIP INDI (xKa) Mahe Motlel 00(In) Sery Valve Type Lalen Type pare Sive (in) TRORun (psq Run Oale Do 1 1633].6 6,902.2 CAMCO KDG-2- i GAB LIFT DMY BN 0000 0.0 912412009 R1 Notes: General& Safety Ena 0,11 Annllacln 9/Z2009 NOTE: VIEW SCHEMATIC WAla3ka SOST alic9D 60.9 LIR; TAD79 PACNER:1B440.7 N IPPLE`18,500.0 PLOD: 16,500.0 WLeG:10519f INTERMEDIATELLWER: ITS, I.D. a e a e OPEN HOLE: 17,1730-21 910.0e STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to 'i m.reoatlalacka.aov: AOGCC Insoectorsisto.skaaavohoebe.brooksllalaska.cov OPERATOR: ConocoPM111ps Alaska Inc. FIELD UNIT/ PAD: Colville River FieldiCRU/CD2 DATE: 05/02/17 OPERATOR REP: AOGCC REP: chris.Wallace(laleskank, Well CD2 -]3 Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. G=DIher (desMCe in notes) PTD 208-195 Type In G Tubing 3936 3939 3939 3939 Type Test P Packer TVD 8942 BBL Pump 1 3.2 IA 1191 1 2500 2490 2490 Interval O Test psi 1]36 BBL Retum I OA 1 526 800 600 5% Result P Notes: Diagnostic MITIA Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Int Tubing Type Tesl PackerND BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Typelnj Tubing Type Test PackerND BBL Pump IA Interval Test psi BBL Return OA - Result Netes: WellPressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTO Type In, Tubing Type Test PackerND BBL Pump IA Interval Test psi BBL Return OA Result Notes: well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. EO Min. PTO Typelnj Tubing Type Test PackerND BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Typelnj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Presswes: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test PackerND BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Typelnj Tubing Type Test Packer WD BBL Pump IA Interval Test psi BBL Return OA Result Notes: Twin isU CMes W - Water G=Gas 5=stay I= ln4eetlal Waste,.amr N =Nat Inleding TYPE TEST Codes INTERVAL CMes P=Parsee Teat 1=1n6a1 Too G= other (beast. In Notes) 4=Four Year Cycle V=Requirel by VaNance G=DIher (desMCe in notes) Farm 10426 (Revised 011201]) CRO CD2 -73 Diagnostic MIT 5-2-2017As5 Result Coses Pe Pass F=Fail 1=lnoonduslve Wall Narnne Start Date Days End Date CD2 -73 513112017 90 1 812912017 DoteE Bleed Hismry Annular Communication Surveillance 180 HEILID TIME STR-FRES ENO-FRES OIF-FRES TCl151NG SERVICE 45[0 _MP IM1P 150 90W t]AI' —_wxr 1 40 35W 130 20M 120 25W m 6 110 MW 1009 5[0 W IDW W �0 TO W D Idry-iT Jum17 JWl] AU 17 SP17 .0 'i —DCI O., 4 =MCI D.] i �PNI m R6 _ arv1 0.6 —alaD R.4 0.3 021' 0 ALy-17 Ju�17 Jt417 AUP1T SPIT Dale UN 26 ?Oi; Cono%r.1*0Phi11ips June 261h, 2017 Alaska Oil and Gas Conservation Commission 333 W. 7th Ave #100 Anchorage, Alaska, 99501-3539 RE: Request for Reconsideration Conservation Order No. 443C, Alpine Oil Pool, North Slope, AK Area Injection Order No. 18D, Alpine Oil Pool, North Slope, AK Dear Commissioners: Stephen Thatcher Manager, WNS Development North Slope Operations and Development ConocoPhillips Alaska, Inc. ATO -1770 700 G Street Anchorage, AK 99501 phone 907.263.4464 ConocoPhillips Alaska, Inc. ("ConocoPhillips") respectfully requests reconsideration of two discrete parts of the recent Alpine orders: Conservation Order No. 443C ("CO") and Area Injection Order No. 18D ("AIO"), dated June 15th, 2017 and June 20th, 2017 respectively. We request that two typographical errors in the issued orders be corrected. Correction of the Umiat Meridian Table in the CO and AIO Each of the orders contains a small error in the Umiat Meridian table defining the area of the Alpine Oil Pool. For T11 N R3E one of the sections is improperly listed as "22-17 All". The correct section reference is "22-27 All". In our application, we requested Umiat Meridian sections T11 N R3E 22-27 as the affected sections for the pool expansion and AIO. The land sections T11 N R3E 22-17 are located outside of the requested Alpine pool boundary. We respectfully request that this be corrected on both page 3 of the CO and page 3 of the AIO. 2. Rule 12 Gas Offtake Rate Rule 12 part (a) in the CO states: "The cumulative gas off take rate from the Colville River Field (CRF) must not exceed MMSCFPD." The number of MMSCFPD is not stated. This rule was established in Conservation Order 443A.003, which provided, "[t]he cumulative gas off take rate from the Colville River Field (CRF) must not exceed 1 MMSCFPD." (emphasis added). ConocoPhillips requests that the Commission revise Rule 12 to add the 1 MMSCFPD" language consistent with CO 443A.003. For the reasons set forth above, ConocoPhillips requests that the AOGCC reconsider and revise its ruling on the CO and AIO. Please contact Anu Sood (263-4802) if you have questions or require clarification of this request for reconsideration. Regards, '5—� _� —11.4, Stephen Thatcher Manager, WNS Development PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/AIO-003 ALASKA OIL AND GAS CONSERVATION COMMISSION Before Commissioners: Cathy Foerster, Chair Daniel T. Seamount Hollis French In the Matter of the Application of ConocoPhillips Alaska, Inc., for Administrative Amendments to CO 443B and AIO 18C to Allow for Expansion of the Alpine Oil Pool to Include the westward Development of the Nanuq Kuparuk Sands in Anticipation of Future Development for Oil Production. Docket No.: CO 17-004 AIO 17-003 ALASKA OIL and GAS CONSERVATION Anchorage, Alaska March 14, 2017 9:00 o'clock a.m. VOLUME I PUBLIC HEARING BEFORE: Cathy Foerster Daniel T. Seamount Hollis French COMMISSION Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/AIO-003 Page 2 1 TABLE OF CONTENTS 2 Opening remarks by Chair Foerster 03 3 Remarks by Mr. Johnstone 05 4 Remarks by Mr. Sood 09 5 Remarks by Mr. Knock 11 6 Remarks by Mr. Donnelly 23 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 PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/AIO-003 Page 3 1 P R O C E E D I N G S 2 (On record - 9:05 a.m.) 3 CHAIR FOERSTER: Good morning, I'd like to call 4 this hearing to order. Today is March 14, 2017, the 5 time is 9:05 a.m. We are located at the offices of the 6 Alaska Oil and Gas Conservation Commission, 333 West 7 Seventh Avenue, Anchorage, Alaska. To my left is 8 Commissioner Dan Seamount, to my right is Commissioner 9 Hollis French and I'm Cathy Foerster, the Chair. 10 We're meeting today regarding docket number CO 11 17-004 and area injection order 17-003, Alpine Pool, 12 Colville River unit pool rules. ConocoPhillips Alaska 13 by application received on January 31st, 2017 requests 14 that the Alaska Oil and Gas Conservation Commission 15 approve administrative amendments to CO 443E and AIO 16 18C to allow for expansion of the Alpine oil pool to 17 include the westward development of the Nanuq Kuparuk 18 sands in anticipation of future development for oil 19 production. 20 Computer Matrix will be recording today's 21 proceedings and anyone interested can get a copy of the 22 transcript from them. 23 Okay. It appears that ConocoPhillips intends 24 to testify. Are any other parties present today 25 intending to testify? Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/AIO-003 Page 4 1 (No comments) 2 CHAIR FOERSTER: Okay. I don't need to give 3 you guys all the ground rules, I think you know them. 4 Commissioner Seamount, do you have anything to 5 add for the good of the order before we begin? 6 COMMISSIONER SEAMOUNT: I have nothing to add 7 at this time. 8 CHAIR FOERSTER: Commissioner French? 9 COMMISSIONER FRENCH: No, ma'am. 10 CHAIR FOERSTER: All right. Well, then let's 11 begin. 12 Are you the three people that -- only three 13 people planning to testify? 14 MR. JOHNSTONE: Yeah..... 15 CHAIR FOERSTER: Okay. 16 MR. JOHNSTONE: .....there are others in the 17 room. 18 CHAIR FOERSTER: Who might be available to 19 answer questions? 20 MR. JOHNSTONE: Right. 21 CHAIR FOERSTER: All right. Well, let's just 22 all of you raise your right hand. 23 (Oath administered) 24 IN UNISON: Yes. 25 CHAIR FOERSTER: And say your name. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email• sahile@gci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/A10-003 Page 5 1 MR. JOHNSTONE: Sam Johnstone. 2 MR. KNOCK: Doug Knock. 3 MR. SOOD: Anu Sood. 4 CHAIR FOERSTER: And they all said yes. 5 All right. The order of business is whoever's 6 going to testify first say your name and if you'd like 7 to be recognized as an expert in a particular area tell 8 me that -- tell us that and what that area is and then 9 we'll need to hear your credentials so that we can make 10 a decision of whether to accept you as an expert in 11 that area or not and then you can proceed with your 12 testimony. 13 And for the good of the recording and the court 14 reporter if you interrupt one another -- if someone new 15 starts to talk identify yourself so that the record can 16 reflect who's saying what. 17 All right. So who's starting? 18 SAM JOHNSTONE 19 previously sworn, called as a witness on behalf of 20 ConocoPhillips, stated as follows on: 21 DIRECT EXAMINATION 22 MR. JOHNSTONE: So my name is Sam Johnstone and 23 I'm currently the Colville River unit production 24 engineering supervisor. And I would like to be 25 accepted as an expert in petroleum engineering. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/AIO-003 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 6 CHAIR FOERSTER: And what are your credentials, education and experience. MR. JOHNSTONE: I am a petroleum engineer with 17 years experience. I have a bachelor's and a master's degree in petroleum engineering from Montana Tech. I started by career with Halliburton as a stimulation engineer in Wyoming. After joining ConocoPhillips in 2001 in the Permian Basin as a production engineer and then as a reservoir engineer I transferred to Alaska in 2004 working Kuparuk as a petroleum engineer, working primarily supporting development drilling at Kuparuk. In 2013 I started working the Colville River unit supporting the developments of CD5, GM21 and GM22. And I'm currently as I mentioned about a year and a half ago I moved into the role as production engineering supervisor. CHAIR FOERSTER: Okay. Commissioner Seamount, do you have any questions? COMMISSIONER SEAMOUNT: Yeah. Mr. Johnstone, what do you -- what did you say you're a supervisor of? MR. JOHNSTONE: Production engineering. COMMISSIONER SEAMOUNT: Production engineering at? MR. JOHNSTONE: At western North Slope, Colville River unit. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/AIO-003 Page 7 1 COMMISSIONER SEAMOUNT: Okay. And so you were 2 -- you spent some time in Wyoming? 3 MR. JOHNSTONE: Yeah, I grew up in Wyoming or 4 went to high school in Wyoming in Evanston and then 5 after school went back to Rock -- beautiful Rock 6 Springs. 7 COMMISSIONER SEAMOUNT: Rock Springs. 8 MR. JOHNSTONE: Yes. 9 COMMISSIONER SEAMOUNT: Okay. I used to work 10 out of Green River. 11 MR. JOHNSTONE: Yeah, we lived in Green River 12 instead of Rock Springs. 13 COMMISSIONER SEAMOUNT: It's a nice place. 14 Okay. I have no problems with accepting Mr. Johnstone 15 as an expert witness in -- would it be petroleum -- 16 drilling petroleum engineer or petroleum engineer? 17 MR. JOHNSTONE: Just petroleum engineering. 18 COMMISSIONER SEAMOUNT: Petroleum engineer. 19 Either's fine with me. 20 COMMISSIONER FRENCH: I agree. 21 CHAIR FOERSTER: No questions: Okay. Mr. 22 Johnstone, are you related to Jim Johnstone? 23 MR. JOHNSTONE: No. 24 CHAIR FOERSTER: Okay. You've heard that 25 before, haven't you. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email sahile@gci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/AIC-003 1 MR. JOHNSTONE: Yes. 2 CHAIR FOERSTER: Yeah, he's a long time ARCO. 3 MR. JOHNSTONE: I am related to a Jim 4 Johnstone, but not..... 5 CHAIR FOERSTER: Not the ARCO one? 6 MR. JOHNSTONE: .....the one that you asked me 7 about previously. 8 CHAIR FOERSTER: Okay. All right. I have no 9 problems accepting you as an expert. I'd prefer to 10 know if there's -- if you're going to be focusing on 11 production engineering or reservoir engineering or 12 drilling engineering or..... 13 MR. JOHNSON: So I will -- both Doug and Anu 14 will be presenting the slides and giving most of the 15 testimony and I'm here to support answering some 16 questions that they may not be familiar with. 17 CHAIR FOERSTER: Okay. All right. Then please 18 proceed. 19 And as you refer to slides on the overhead, 20 refer to them either by number or name so that the 21 record can match the document. 22 MR. JOHNSTONE: At this time I'd like to kick 23 it over to Anu Sood to -- for his introduction. 24 CHAIR FOERSTER: Okay. 25 ANU SOOD Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste, 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/AIO-003 Page 9 1 1 previously sworn, called as a witness on behalf of 2 ConocoPhillips, stated as follows on: 3 DIRECT EXAMINATION 4 MR. SOOD: Good morning, Commissioners. My 5 name is Anu Sood. For the record it's pronounced Anu 6 and it's spelled 7 A -N -U, Sood, S -O -O -D. And I'd like to request the 8 Commission allow me to testify today as a petroleum 9 engineering expert. 10 CHAIR FOERSTER: In what area of petroleum 11 engineering..... 12 MR. SOOD: In..... 13 CHAIR FOERSTER: .....production, reservoir, 14 facilities, drilling? 15 MR. SOOD: Currently I work as a production 16 engineer. 17 CHAIR FOERSTER: Is that what your testimony's 18 going to be about..... 19 MR. SOOD: It will be. 20 CHAIR FOERSTER: .....and is that what your 21 expertise is in? 22 MR. SOOD: My expertise is in petroleum 23 engineering is what I'm requested I be allowed to 24 testify in. For the past four years I've worked as a 25 production engineer for the western North Slope. The Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/AIO-003 Page 10 1 first two years I worked onsite in the Alpine field 2 supporting the day to day operation, the fracks, the 3 drilling. And then for the last two years I've worked 4 here in the Anchorage offices supporting the CD5 5 development and also the surveillance of two drill 6 sites, CD2 and CD4 from here. And I also have a 7 degree in chemical engineer from Georgia Tech. 8 CHAIR FOERSTER: Sounds like production 9 engineering is what you've -- what your expertise is 10 in. 11 Do you have any questions for Mr. Sood? 12 COMMISSIONER SEAMOUNT: No questions, no 13 objections to recognizing..... 14 CHAIR FOERSTER: Okay. 15 COMMISSIONER FRENCH: No questions. 16 CHAIR FOERSTER: Okay. Then please proceed, 17 Mr. Sood. 18 MR. SOOD: Thank you. I'd like to introduce 19 Doug Knock who'll be testifying as well, he's our 20 geologist. 21 MR. KNOCK: Do you want me to..... 22 COMMISSIONER FRENCH: Sure. Why not. 23 DOUG KNOCK 24 previously sworn, called as a witness on behalf of 25 ConocoPhillips, stated as follows on: Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email• sahile@gci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO- 17-004/AIO-003 Page 11 1 DIRECT EXAMINATION 2 MR. KNOCK: I'm Doug Knock, D -O -U -G K -N -O -C -K. 3 I'd like to be recognized as an expert in petroleum 4 geology. I have over 29 years of experience working 5 North Slope geology. I'm currently a geologist for the 6 greater western North Slope area and the Alpine field. 7 I have a master's degree from the University of Alaska 8 at Fairbanks in geology. 9 CHAIR FOERSTER: Where'd you get your 10 bachelor's? 11 MR. KNOCK: University of Idaho. 12 CHAIR FOERSTER: In geology? 13 MR. KNOCK: Yes. 14 CHAIR FOERSTER: Okay. Commissioner Seamount, 15 do you have any questions for Mr. Knock. 16 COMMISSIONER SEAMOUNT: I have no questions 17 however I'd like to say that this is like a Wyoming 18 reunion because I worked with Mr. Knock's father in 19 Casper for many years. 20 And I have no objections to making him an 21 expert witness in petroleum geology. 22 CHAIR FOERSTER: All right. All right. Please 23 proceed with your testimony. 24 MR. SOOD: Great. Thank you. I just want to 25 acknowledge the Commission and thank you for allowing Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahileggci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/AIO-003 Page 12 1 us to be here to present the slides today. In total 2 we've got 18 slides that we'd like to present today. 3 The first six are -- that Doug and I will be presenting 4 a total of 18 slides and the first six are 5 nonconfidential and then after that we have two slides 6 of confidential material which includes some seismic 7 data and some net pay maps which are proprietary 8 property of ConocoPhillips Alaska. And after we get 9 past those two slides we'll go back into the 10 nonconfidential section which again Doug and I will go 11 back and forth and cover in the presentation today. 12 COMMISSIONER SEAMOUNT: I have a question. 13 CHAIR FOERSTER: Oh, before you proceed 14 Commissioner Seamount has a question. 15 COMMISSIONER SEAMOUNT: You have a..... 16 MR. SOOD: Yes, sir. 17 COMMISSIONER SEAMOUNT: .....you say you have a 18 confidential section and you want to sandwich it in 19 between two nonconfidential sections. Is it possible 20 to describe why it's confidential before we proceed, I 21 mean, would that -- is there a confidential reason why 22 you don't want to describe why it is confidential, I 23 mean, just generally? 24 MR. KNOCK: There is, Commissioner Seamount. 25 We view those slides as the proprietary product of our Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email sahile@gci.net PUBLIC HEARING 3/14/2017 DOCKET NOLO-17-004/AIO-003 Page 13 1 interpretation and our investment. This information 2 has not been shared with the public before, it 3 includes, you know, interpretive material on seismic 4 and our trend mapping, you know, in that area of the 5 Kuparuk that we have not shared with the public. 6 COMMISSIONER SEAMOUNT: Okay. I understand 7 that, but I guess generally the reason why it is 8 confidential is to show that -- why you should or 9 should not expand the pool area; is that correct. 10 CHAIR FOERSTER: Well, that's not why it's 11 confidential, that's why they feel like they need to 12 show it. 13 COMMISSIONER SEAMOUNT: That's why it's 14 confidential. 15 CHAIR FOERSTER: No, that's why they want to 16 show it. 17 COMMISSIONER SEAMOUNT: That's why they don't 18 want to show it. 19 CHAIR FOERSTER: No, that's why they want to 20 show it to us. They want to show it to us because they 21 feel they need it to make their point, but it's 22 confidential because it's got proprietary stuff in it. 23 COMMISSIONER SEAMOUNT: You're not testifying. 24 CHAIR FOERSTER: I'm explaining to you what the 25 question you should be asking. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email sahile@gci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/AIO-003 Page 14 1 MR. KNOCK: Our -- excuse me, our -- this is 2 Doug Knock. Our horizons that we interpreted on 3 seismic are of course our interpretation, the way we've 4 mapped it, the trend of the sand is our interpretation 5 and we don't know that we're going to hold the leases 6 around this area in perpetuity, you know, forever. We 7 would prefer that our interpretation not be made 8 public. 9 COMMISSIONER SEAMOUNT: Understood. Okay. 10 Thank you. 11 CHAIR FOERSTER: Do you have any questions? 12 COMMISSIONER FRENCH: No. 13 CHAIR FOERSTER: I do. Why do you feel it's 14 necessary to provide this information to us? 15 COMMISSIONER SEAMOUNT: That's what I said. 16 MR. KNOCK: This is Doug Knock again. Because 17 in the pool expansion area which we're going to be 18 talking about, the sand extends onto that area and 19 we're going to -- we plan to drill in the near future 20 in the pool expansion area. 21 CHAIR FOERSTER: And there's no nonconfidential 22 data that shows the pool extends into that area? 23 MR. KNOCK: We will show the extent of the -- 24 we will show the pool extension area on maps without 25 our interpretation on top of it. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email• sahile@gci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/AIO-003 Page 15 1 CHAIR FOERSTER: But there's no nonconfidential 2 data that demonstrates that the..... 3 MR. KNOCK: That there's -- why we're going to 4 drill in that area, you know, why -- yeah, we're going 5 to show -- no, there's not -- it's all 6 confidential..... 7 CHAIR FOERSTER: Okay. 8 MR. KNOCK: .....data that..... 9 CHAIR FOERSTER: The point I'm try -- where 10 we're trying to get to with this is we prefer not to 11 show -- not to have confidential data in our public 12 process. And so in order to allow confidential data 13 there need to be two hurdles. The first hurdle is the 14 hurdle of it deserves confidentiality and the second 15 hurdle is it necessary to demonstrate why you're asking 16 for the request you're asking for. And so that's all 17 we're trying to establish is, yes, it deserves to be 18 held confidential and, no, without it you couldn't make 19 your points. Does that make sense? 20 MR. KNOCK: That does make sense. 21 CHAIR FOERSTER: Okay. All right. So is the 22 answer to the second question, no, without it you 23 couldn't make your points? 24 MR. KNOCK: I believe that to be correct. 25 CHAIR FOERSTER: Okay. All right. Let's Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/AIO-003 Page 16� 1 proceed with the nonconfidential part of the 2 presentation then. 3 MR. SOOD: Great. Thank you. This is Anu. 4 I'll move on to slide two here of the presentation. 5 And slide two here lists the agenda for our 6 presentation today. 7 Really the objective of the objective of the 8 presentation is to supply the Commission with all the 9 information necessary to grant our request for the 10 Alpine oil pool expansion. And in today's agenda I 11 will be giving a very brief history of the Alpine oil 12 pool as it sits today. I'll be giving an overview of 13 the aerial expansion request that we've asked for in 14 the application as well as some of the amendments 15 that's being requested inside the conservation order 16 443B and the area injection order. And then I'll hand 17 the presentation back to Doug Knock who will give an 18 overview of the drilling results we've -- in the Nanuq 19 Kuparuk sands with CDS-313 and CD5-315. And then Doug 20 will also talk about the drilling plans we have inside 21 the expansion area with CD5-313X and CD5-316. And once 22 we finish that part of the presentation Doug will cover 23 the absence of any drinking waters inside the -- really 24 the original Colville River unit area as well as the 25 expansion area that we've asked for. And then Doug Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/AIO-003 Page 17 1 will give the presentation back to me and I will 2 describe the conservation order and the AIO amendments 3 in a little more detail at the end of the presentation. 4 So here on slide three I'd like to cover a 5 brief history of the Alpine oil pool. As it sits today 6 the original conservation order 443 was issued to 7 facilitate the very initial development of the Alpine 8 pool. In 2004, October, the conservation order was 9 expanded to allow for additional development westward 10 through the Alpine pool. And then in March of 2009 11 ConocoPhillips demonstrated pressure communication in 12 -- with the -- pressure communication of the Alpine oil 13 pool with the Kuparuk oil pool and thus the Kuparuk oil 14 pool as it stood at the time was terminated and the 15 Kuparuk sandstone reservoir was merged inside the 16 Alpine oil pool. And on the right is a type log of the 17 Alpine 1 well which today describes the bounds of the 18 Alpine oil pool. And the Alpine 1 type log also shows 19 the Nanuq Kuparuk reservoir as well as the Alpine 20 reservoir that's today a part of the Alpine oil pool. 21 The area injection order, AIO 18, were concurrently 22 amended with the conservation orders over the years to 23 again facilitate the very same development over the 24 years. 25 CHAIR FOERSTER: All right. Mr. Sood, could Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/AIO-003 Page 18 1 you refresh my memory on what was the basis for the 2 combining of the two pools, what is the cause of the 3 pressure communication, is it faulting? 4 MR. KNOCK: Commissioner Foerster, I'll take 5 that question. This is Doug Knock. 6 What we've noticed over the development for 7 many years is in northern C2 pad we have the thin 8 Kuparuk sand directly on top of the Alpine sand. So 9 we've got communication that way to the north in Alpine 10 field. When we sighted Alpine field we found pressure 11 communication again between the Alpine sand and the 12 overlying Kuparuk sand. There they're separated by a 13 hundred feet or so. And that's due to faulting there 14 on the east side of the Kuparuk field, the east 15 bounding Alpine fault. And then again at CD4 to the 16 south we have seen some evidence of pressure 17 communication between Alpine and Kuparuk. We saw a 18 little bit of rising pressure in the Kuparuk there due 19 to Alpine injection. 20 CHAIR FOERSTER: Thank you. 21 COMMISSIONER SEAMOUNT: What's the maximum 22 separation you've seen between the Alpine and the 23 Kuparuk? 24 MR. KNOCK: Approximately between 200 and 250 25 feet TVD. In the south there's bigger separation, Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/AIO-003 Page 19 1 you've got the thick Miluveach packaged to the south 2 between the thin Kuparuk sand and the underlying Alpine 3 reservoir. As you go to the north the LCU makes that 4 separation less and less as the LCU is cutting out 5 Miluveach towards the north. 6 COMMISSIONER SEAMOUNT: And are we talking tens 7 of miles of distance between these wells? 8 MR. KNOCK: We are talking five plus miles, 9 five to eight miles. 10 COMMISSIONER SEAMOUNT: Thank you. 11 MR. SOOD: Okay. This is Anu again. So here 12 on slide four we'd like to cover the requests that are 13 being asked for in the pool expansion request. 14 Essentially what we're asking for is shown on 15 the map to the right. What we're showing in the blue 16 area is the Alpine oil pool as it's defined currently. 17 And then the black outline there on the map shows the 18 boundary of the Colville River unit. And so with this 19 pool expansion application request we're asking that 20 the Alpine oil pool be contracted on the eastern 21 boundary by 16 either part or full sections to conform 22 to the boundary of the Colville River unit. And then 23 on the western front the Alpine oil pool be expanded by 24 six full sections to again conform to that same 25 Colville River unit boundary and also to facilitate the Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email• sahile@gci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/AIO-003 Page 20 1 development drilling of two additional wells that we 2 have planned this year. In the middle of the map is -- 3 are the -- the four red lines show the wells that we 4 have either drilled already or that are planned for 5 future development. So CD5-313 and CD5-315 are two 6 Nanuq Kuparuk sand wells which again Doug will go into 7 later on in his slides, but these are the two wells 8 that we used to prove up the development of the Nanuq 9 Kuparuk sandstone and CD5-314X and CD5-316 are the two 10 development wells that we have planned that will be 11 allowed with this pool expansion application. 12 In addition to the aerial changes we're also 13 acting for certain amendments to the conservation order 14 and the area injection order. We're asking for one 15 rule change to the conservation order 443 and that 16 change is to -- is for rule five governing the safety 17 valve systems to be either amended or removed which 18 again when we come back to the end of the presentation 19 I'll go into that in a little more detail. And then 20 the -- we're asking for two additional rules to be 21 added to the area injection order and those rules are 22 governing injection, the injection fluids and the 23 injection pressures inside the pool. 24 All these rules -- amendments that are being 25 proposed as far as this application are really current Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/AIO-003 Page 211 1 practice and we're asking for the regulations to be 2 updated with what is the current practice so that it's 3 a little more clear for us as the operator. 4 CHAIR FOERSTER: All right. So let me ask a 5 question now. It may not have been what you meant, but 6 what I heard was the rule doesn't allow you to do 7 something that you're currently doing? 8 MR. SOOD: So the -- so the two rules that 9 we're asking for in the area injection order, the way 10 the AIO is written currently there's no -- there's 11 really no governance of either the injection fluids or 12 the maximum injection pressures. So what we're asking 13 for today is that there be -- those be set. And I'll 14 cover those more later on in the presentation as well. 15 CHAIR FOERSTER: Okay. So before you leave 16 could you walk over to the map and show me what is 17 being contracted and what is being added? 18 MR. SOOD: Absolutely. 19 CHAIR FOERSTER: Because I -- I'm impaired in 20 my ability to understand what is..... 21 COMMISSIONER SEAMOUNT: Do you want to use this 22 instead? 23 CHAIR FOERSTER: He can just -- whatever's 24 easier. 25 MR. SOOD: I can point to it, I don't mind at Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/AIO-003 Page 22 1 all. What we're asking for is -- so this black line 2 shows the CRU boundary..... 3 CHAIR FOERSTER: Uh-huh. 4 MR. SOOD: .....and then this blue line here 5 shows the Alpine oil pool. And so what we're asking 6 for is..... 7 MR. JOHNSTONE: Can I interrupt for a minute? 8 This is Sam Johnstone. Just to clarify the black line 9 is the existing pool and the blue line is the unit 10 boundary. 11 CHAIR FOERSTER: Okay. 12 MR. SOOD: Right. Did I get those mixed up? 13 MR. JOHNSTONE: Yeah. 14 MR. SOOD: Okay. Thank you. It might be 15 plugged (indiscernible - away from microphone)..... 16 But basically what we're asking for is the 17 Alpine oil pool for it to be contracted in this part, 18 on the western front and then for it to be expanded 19 from here to here. 20 CHAIR FOERSTER: Okay. 21 MR. SOOD: And so these are the six sections 22 we're asking to be expanded and this -- these are the 23 16 (indiscernible - away from microphone) contracted. 24 CHAIR FOERSTER: Okay. Thank you. 25 COMMISSIONER SEAMOUNT: Here's a stupid Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/AIO-003 Page 231 1 question. If a reservoir does not actually extend into 2 an area does it automatically not be part of the pool 3 legally, I mean, can you make a pool area bigger than 4 the area of the reservoir, is there a legal problem 5 with that? 6 MR. JOHNSTONE: You are asking us that 7 question? 8 COMMISSIONER SEAMOUNT: I'm not asking you..... 9 MR. JOHNSTONE: Okay. 10 COMMISSIONER SEAMOUNT: .....I'm asking a 11 lawyer. 12 MR. DONNELLY: I can -- I'm here with 13 ConocoPhillips. 14 CHAIR FOERSTER: All right. Introduce yourself 15 and I need to put -- get you to swear. 16 MR. DONNELLY: My name's Kevin Donnelly. 17 CHAIR FOERSTER: All right. Kevin, raise your 18 right hand. 19 (Oath administered) 20 MR. DONNELLY: Yes, I do. 21 CHAIR FOERSTER: All right. Please proceed. 22 KEVIN DONNELLY 23 called as a witness on behalf of ConocoPhillips, stated 24 as follows on: 25 DIRECT EXAMINATION Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email sahile@gci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/AIO-003 Page 24 1 MR. DONNELLY: I'm Kevin Donnelly, I'm an 2 attorney with ConocoPhillips. And, you know, from a 3 legal perspective we're not asking here today to expand 4 the pool into an area where the reservoir does not 5 extend. So I think that legal question, I think we can 6 hold for another day, but I think -- in my view it 7 would be problematic if we didn't have the geological 8 basis that the reservoir actually extended into that 9 area. 10 Does that answer your question? 11 COMMISSIONER SEAMOUNT: It sort of answers my 12 question. I know that a long time ago in the past we 13 have made pools very large just in case there are some 14 reservoirs sitting out there that no one knew about. 15 And those pools still exist today and there's been no 16 proof that they do or do not -- the reservoir does or 17 does not exist. And I think it leads to the question 18 of whether we need to see the confidential information 19 to prove that it -- to show evidence that it does or 20 does not exist in that area. 21 MR. DONNELLY: I agree. 22 COMMISSIONER SEAMOUNT: Okay. 23 CHAIR FOERSTER: All right. Thank you. 24 MR. SOOD: Okay. Here on slide five I'll hand 25 the presentation over to Doug Knock to cover the Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email sahile@gci.net PUBLIC HEARING 3/14/2017 DOCKET NO CO-] 7-004/AIO-003 Page 251 1 overlaying geology of the sand here. 2 MR. KNOCK: Doug Knock again. This is slide 3 five. Shown here is Nanuq Kuparuk type logs. In 2015 4 we drilled the CDS-313 pilot hole. In that pilot hole 5 we found eight feet of gross Kuparuk sea sand and good 6 reservoir quality. We sidetracked that well and 7 drilled the CD5-313 lateral next to it. That's a 7,400 8 long production lateral, continuous Kuparuk sea sand 9 there. Then we moved west and drilled the CD5-315 10 pilot hole and found nine feet of gross Kuparuk sea 11 sand and sidetracked and drilled a 10,400 foot long 12 lateral in the Kuparuk sea sand with again continuous 13 sand. 14 Also shown on the map on the bottom are the 15 upcoming wells, proposed wells CDS-314X which is a 16 producer location and CD5-316 which is an injection 17 location. As you can see the injector extends on to 18 the pool expansion area. 19 Moving to the next slide, slide number 6, this 20 shows a log cross section for the western most well 21 that I've just talked about, the CD5-315 injector. 22 This was a 10,400 foot long lateral that found seven to 23 12 feet of continuous sand of very good reservoir 24 quality. It reached over a hundred ohms resistivity 25 for a good middle portion of the well. And that kind Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/A1O-003 Page 26 1 of resistivity is well over a hundred millidarcies 2 permeability. 3 On the top of the display is the periscope 4 image, it's a deep resistivity device that we used to 5 geosteer, it's a Schlumberger tool. It provides us a 6 map or a calculated distance to the top and bottom of 7 the sandstone you're drilling in if the distance isn't 8 too great. From the image on the top we found we had 9 eight to 10 feet of sand in this area as we're drilling 10 along, here's the lateral. Didn't really resolve the 11 bottom. In the middle super high resistivity portion 12 of the well we were closer to the top and it probably 13 was a little over 12 feet thick and we weren't mapping 14 the bottom and back. In the latter part of the well 15 the sand thinned a little bit and we were seeing the 16 top and bottom again. So we use these thicknesses to 17 help constrain our mapping. 18 Next slide. Now we have a couple of 19 confidential slides showing our interpretation as it 20 extends into the pool expansion area. 21 CHAIR FOERSTER: Okay. Commissioners Seamount 22 and French, are you comfortable that we need to see the 23 confidential portion of this -- of the presentation? 24 COMMISSIONER SEAMOUNT: Well, let me ask a 25 question. The CD -314X does not exist into the pool Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/A10-003 Page 271 1 expansion, why is that? 2 MR. KNOCK: It's we -- we are -- this reservoir 3 is such good reservoir quality that our well spacing is 4 5,500 to 6,000 feet between laterals. And as we go 5 from the well I just showed, the 315 injector, going 6 our well spacing over one to the west, we're still 7 within the pool and the current unit boundary with the 8 314X. As we move another mile plus further west with 9 the 316 injector we move into the pool expansion area. 10 we hope to drill both of those wells in the second 11 quarter of 2017. 12 COMMISSIONER SEAMOUNT: Okay. So you want to 13 keep this confidential because if we deny the pool 14 expansion and someone sees some information -- a 15 competitor sees some information you're afraid that 16 they may go in there and try to top lease you or 17 something like that? 18 MR. KNOCK: That's correct. That's a 19 possibility and over time we may not hold the leases 20 all around this area. 21 MR. JOHNSTONE: This is Sam Johnstone. I might 22 just add onto that that with this sand, this thin sand, 23 we've developed techniques that require ConocoPhillips 24 to help us identify the extension of this sand which 25 we'll be showing you in the confidential section. And Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/AIO-003 Page 28 1 I think if those were not -- those techniques were not 2 confidential then we're giving away our competitive 3 advantage. 4 COMMISSIONER FRENCH: Madam Chair. 5 CHAIR FOERSTER: Yes. 6 COMMISSIONER FRENCH: This might be a newbie 7 question, but I'll ask it just so I'm sure I understand 8 what's going on. The pool expansion area, the six 9 quarter sections you hold by lease now; is that 10 correct? 11 MR. JOHNSTONE: Yes, that is correct. 12 COMMISSIONER FRENCH: Okay. So you -- and you 13 want to continue holding them in the future, but you 14 want to push the pool into those leases to make it all 15 part of the greater Alpine area that you also hold now 16 and produce from? 17 MR. JOHNSTONE: That is correct. 18 COMMISSIONER FRENCH: Thank you. Those are my 19 questions. 20 CHAIR FOERSTER: All right. Are you 21 comfortable with moving into confidential? 22 COMMISSIONER SEAMOUNT: Yes. 23 CHAIR FOERSTER: Okay. All right. So is -- I 24 would -- I'm going to put the monkey on the Conoco 25 people's back, look around the room and decide who Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/AIO-003 Page 291 1 needs to go. I think, Alan Bailey, we know who you 2 are, but..... 3 MR. JOHNSTONE: We like you, Alan, it's just, 4 you know..... 5 CHAIR FOERSTER: But if you just find yourself 6 a comfortable spot out in the lobby then we'll invite 7 you back when we're done with the confidential section. 8 And, Ms. Colombie's going to close the doors as you -- 9 after you leave. 10 Is there anyone else, ConocoPhillips, that you 11 would like to leave? 12 COMMISSIONER SEAMOUNT: Besides one of the 13 Commissioners? 14 ** CONFIDENTIAL PORTION ** 15 CHAIR FOERSTER: Okay. Ms. Colombie, would you 16 invite Mr. Bailey back into the room. 17 MR. JOHNSTONE: We can take that slide down, I 18 guess. 19 CHAIR FOERSTER: Yeah, take -- yeah, move to 20 the next slide. 21 COMMISSIONER SEAMOUNT: He needs to explain 22 what he just discussed to..... 23 CHAIR FOERSTER: Yes. For the public record 24 and for the courtesy of the public we need you to give 25 an explanation of what you -- what we discussed, that Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/AIO-003 Page 30 1 you showed a map based on blah, blah, blah and that you 2 showed a seismic line that shows the expansion. Just a 3 brief description in your own words that in a 4 nonconfidential way lets the public understand not the 5 details of what they missed, but the character of what 6 they missed. 7 MR. KNOCK: Okay. I'm good doing that, I was 8 looking for the public to come back. I guess I don't 9 have to do that. 10 CHAIR FOERSTER: Thank you for waiting. 11 MR. KNOCK: Okay. Would you like me to 12 proceed? 13 CHAIR FOERSTER: No. 14 (Off record comments) 15 CHAIR FOERSTER: Let Mr. Bailey get settled and 16 then you can proceed. 17 All right. Please proceed with a description 18 of what he missed. 19 MR. KNOCK: This is Doug Knock. What we showed 20 in the confidential section was ConocoPhillips' 21 interpretation of the gross sand thickness trend for 22 the Kuparuk sea sand as it extends west into the pool 23 expansion area. We also showed a 3D seismic line that 24 extends from our current development area in the 25 Kuparuk in the CD4 pad through the CD5 pad and Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/AIO-003 Page 31 1 extending area and heading west into the proposed wells 2 in the pool expansion area for Alpine. 3 Sorry. 4 CHAIR FOERSTER: Did you catch that, Nathan? 5 Okay. 6 MR. KNOCK: Did you catch that? 7 CHAIR FOERSTER: All right. So we're going to 8 leave the request for the pool rule expansion and move 9 into the area injection order request now; is that 10 correct? 11 MR. SOOD: We'll move into -- I have one slide 12 to cover the requested amendment to the conservation 13 order and then after that I'd like to cover the area 14 injection order..... 15 CHAIR FOERSTER: Okay. 16 MR. SOOD: .....amendment..... 17 CHAIR FOERSTER: Okay. 18 MR. SOOD: .....if that's okay. 19 CHAIR FOERSTER: Sounds good. 20 MR. KNOCK: Actually I'm going to address this 21 slide. This is Doug Knock again. 22 CHAIR FOERSTER: Okay. 23 MR. KNOCK: This is slide number 8. This 24 slide's regarding the no underground sources of 25 drinking water in the Colville River unit area. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste, 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/AIO-003 Page 32 1 In the Colville River unit area we have found 2 that the salinity exceeds regulatory standards for 3 freshwater. In 1999 with the Alpine area injection 4 order salinity calculations on wells in the Colville 5 Delta area found no sands with less than 10,000 6 milligrams per liter total dissolved solids. More 7 recent calculations on salinity in the CD5 area also 8 found no sands with less than 10,000 milligrams per 9 liter total dissolved solids. 10 CHAIR FOERSTER: And this would be in the area 11 where you have moving water, not permafrost? 12 MR. KNOCK: That's correct. That's..... 13 CHAIR FOERSTER: Okay. 14 MR. KNOCK: .....exactly right. Water samples 15 in addition from older wells in the Colville Delta area 16 found calculated salinities of 18,500 to 24,000 17 milligrams per liter total dissolved solids. So again 18 well above 10,000 milligrams per liter which is the 19 regulatory standard. Conservation order 443 found that 20 there are no freshwater aquifers in the Colville River 21 unit. 22 Moving on to slide number 9, CD5-21 formation 23 water salinity is shown on this slide with the location 24 map on the left and the CD5-21 log data on the right. 25 We use the apparent water resistivity technique Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/AIO-003 Page 33 1 petrophysically to calculate salinity. This technique 2 is appropriate where you have clean, uncemented wet 3 sand which we do in several sands in the CD5-21 well. 4 The CD5-21 well is the well that we have porosity data 5 in the intermediate hole from CD5. On the map CD5 is 6 shown here and here's the spider path for the CD5-21 7 well. So with the RWA technique we have calculated 8 salinities on the log in these sands shown on the left. 9 Those are the sands that are wet and clean and our 10 calculated salinities are ranging from 16,000 11 milligrams per liter to 25,000 milligrams per liter in 12 the Torok through CD section in the shallower part of 13 the CD5-21 well. We also have looked at vertical wells 14 not on CD5 pad, but in the general area, the Nuiqsut 1 15 and the Clover A and again have not found salinities 16 approaching 10,000 milligrams per liter total dissolved 17 solids. 18 So if no further questions we'll continue on. 19 CHAIR FOERSTER: Any questions, Commissioner 20 Seamount> 21 COMMISSIONER SEAMOUNT: No. 22 CHAIR FOERSTER: Commissioner French? 23 COMMISSIONER FRENCH: No. 24 CHAIR FOERSTER: Okay. 25 MR. SOOD: Okay. This is Anu. Here on slide Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/AIO-003 Page 341 1 10 I'd like to cover the requested amendment to the 2 conservation order. So here in the application what 3 we're asking for is for rule five which governs the 4 regulation of safety valve systems to either be 5 eliminated or for it to be revised, that status 6 consistent with other order 66. Initially when the 7 Alpine conservation order was written in governed the 8 regulation of subsurface safety valves and surface 9 safety valve system for both producers as well as 10 injectors. However in 2011 there was other order 66 11 that was issued which essentially superseded rule five 12 in CO 443B. And now the regulation of the producers 13 and the injectors is concurrently covered by either 14 verbiage in order 66 or 25 265. So at this point we 15 feel that maintaining the rule five inside conservation 16 order 443B creates a little bit of misunderstanding or 17 it could create confusion as to what purpose it serves. 18 So we'd like to request that that rule either be 19 removed or be revised to essentially rephrase the 20 wording inside other order 66. 21 CHAIR FOERSTER: So we've got a statewide rule 22 that is..... 23 MR. SOOD: Uh-huh. 24 CHAIR FOERSTER: .....superseding this rule and 25 so this rule serves no purpose? Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/AIO-003 Page 351 1 MR. SOOD: Right. 2 CHAIR FOERSTER: Okay. 3 MR. SOOD: That's our understanding. 4 CHAIR FOERSTER: Okay. 5 MR. SOOD: And since we were in the process of 6 updating the Alpine oil pool we wanted to take this 7 opportunity to update the rule five as well. 8 CHAIR FOERSTER: Okay. Didn't see any other 9 areas in need of cleanup, just this one? 10 MR. SOOD: Not in the conservation order, 11 ma'am. 12 CHAIR FOERSTER: Okay. Thank you. 13 MR. SOOD: Okay. Here on slide 11 I'd like to 14 cover the first amendment request to the area injection 15 order for the Alpine oil pool. Currently as the AIO 16 rules are written they do not govern the injection 17 pressure for our injection wells. And so with guidance 18 from the AOGCC technical staff what we're asking for is 19 for the AIO to be updated so that it's consistent with 20 the newer area orders that have been issued by the 21 Commission. And we're asking for a new rule to be 22 added which specifies the maximum injection pressure 23 that's allowed. And in this case we're proposing .81 24 psi per foot. And on the next couple of slides I'll 25 cover how we came up with that proposed maximum Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-I 7-004/AIO-003 Page 36 1 pressure. 2 CHAIR FOERSTER: This may be the first time an 3 oil company has asked us to impose a rule on them. 4 MR. SOOD: We're just ahead of the curve. 5 Okay. Here on slide 12 I'll give the 6 presentation back to Doug because he has -- he will 7 cover the containment shelves about the Alpine and the 8 Kuparuk pools and then we'll go back into some of the 9 modeling work we did. 10 Doug, on slide 12. 11 MR. KNOCK: This is Doug Knock, this is slide 12 12 regarding the Alpine 1 well fracture gradient 13 information. From stimulation data, hydraulic fracking 14 and from drilling data we know that the Alpine sands 15 and the Kuparuk sands in the beltman area have a 16 fracture gradient of .65 psi per foot approximately. 17 On this display showing the red lines, this is .65 psi 18 per foot is approximately 12.5 pounds per gallon in 19 converting to pounds per gallon. Also shown on here is 20 our proposed maximum injection gradient of .81 psi per 21 foot applying to the more brittle sandstone package. 22 We know that with injection we are parting the rock 23 within the more brittle sandstones, but we don't 24 believe we're having any impact on the very nicely 25 ductile package of clay rich and organic rich shales Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/AIO-003 Page 37 1 above Alpine and in the Kuparuk. From our mechanical 2 earth modeling which is tied to rock mechanical 3 properties from shale cores that we've acquired at CD4 4 pad. We have calibrated our fracture gradient model 5 along with leakoff test data from some wells at CD4 6 where we've actually done leakoffs within the HRZ, we 7 come up with an average or higher fracture gradient in 8 the Miluveach, Kalubik and HRZ thick shale section 9 above Alpine C and Nanuq Kuparuk of .85 psi per foot or 10 higher for that package of overburden shales. 11 CHAIR FOERSTER: So why would you be willing to 12 inject at a pressure that's going to create a fracture 13 in your formation when..... 14 MR. KNOCK: We historically have -- you 15 basically with cold seawater you are thermally cracking 16 the rock to begin with. And to put away the reasonable 17 volume of seawater to support our producers we have 18 historically been above that point .65 psi per foot. 19 You've got to go above that to really put water away in 20 an injector. 21 CHAIR FOERSTER: Does it effectively waterflood 22 or does it just create a line drive? 23 MR. KNOCK: We have a -- we do have a line 24 drive, that's Alpine's development is line drive 25 injectors and then line drive producers. And, yes, the Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/AIO-003 Page 38 1 water as our 4D seismic shows links up those injectors 2 to be one long injector which is what you want and then 3 the water goes over to the producers. 4 CHAIR FOERSTER: Okay. So because of the 5 minimum stress directions it works in your favor..... 6 MR. KNOCK: And we are lined up with the..... 7 CHAIR FOERSTER: .....if you lined up to that. 8 MR. KNOCK: .....maximum stress direction with 9 our field. That's the way it was developed and we are 10 getting very good recovery with the methodology that 11 we're using. 12 CHAIR FOERSTER: Thank you. 13 COMMISSIONER SEAMOUNT: Is the HRZ brittle? 14 MR. KNOCK: It's real -- you know at depth and 15 temperature it's not, at surface and core, yes, you 16 know, you look at it in a core that we brought to 17 surface and is weathering and being oxidized, at that 18 depth, at 7,000 feet depth and at 160 degrees 19 Fahrenheit it behaved more ductiley to where fracture 20 planes should not -- based on our modeling and based on 21 all our understanding do not extend through those 22 packages. 23 CHAIR FOERSTER: And does the field 24 performance, the operational result, backup that? 25 MR. KNOCK: It does. We -- you know, with 17 Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/AIO-003 Page 39 1 years of development drilling we have never identified 2 any overpressured shallow sands that we've gone through 3 due to injection out of zone. 4 CHAIR FOERSTER: So have you done any 5 temperature or radioactive tracing logging to see the 6 growth of the fracks or..... 7 MR. KNOCK: We have 4D seismic that from the 8 2010 time frame that showed no change in seismic 9 character..... 10 CHAIR FOERSTER: Okay. 11 MR. KNOCK: .....above the reservoir intervals. 12 CHAIR FOERSTER: Thank you. 13 MR. SOOD: Okay. This back to Anu here on 14 slide 13. It shows the results of injection fracture 15 modeling that we use to demonstrate the containment 16 inside the Alpine oil pool. And on the right here what 17 we're showing is a net pressure map which shows the 18 pressure inside the fracture. And what we're showing 19 here are the results of a hydraulic fracturing 20 simulation results which we're using to model injection 21 fracture inside the Alpine oil pool because as Doug 22 said previously we inject above parting pressure of the 23 Alpine sea sand. And here what we wanted to show with 24 this model is whether the injection fluids, how well 25 they're contained inside the oil pool. So this Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/AIO-003 Page 40 1 particular model is based off the Alpine 1 well, the 2 Alpine 1 type log with all the sand properties loaded 3 in. And it basically simulates 10,000 barrels a day of 4 injection over the course of 23 days. And what the 5 results we're showing show is that the injection fluids 6 when we have a stable injection gradient of .81 psi per 7 foot are contained well within the bounds of the pool 8 boundary. And you can see -- I know it's a little hard 9 to see on the map there, but on the graph it -- if 10 you'll point to the top of the Alpine oil pool is that 11 top black line and the bottom of the Alpine oil pool is 12 that line. So what we're showing is that the fluids 13 are contained within those bounds. 14 And slide 14 here shows what the result -- what 15 the model results look like if we injected the same 16 fluids inside the Kuparuk sand instead of the Alpine 17 sand. The nice thing about the Alpine 1 well is it has 18 a penetration inside the Alpine and the Kuparuk sand so 19 we were able to model -- use the same model and inject 20 the same fluid rate inside the Kuparuk sand. And again 21 we're showing containment within the -- well within the 22 bounds of the pool boundary. 23 Here on slide 15 I'd like to cover the second 24 amendment request to the area injection order. And 25 again this is very similar to the first request we Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/AIO-003 Page 41 1 asked for in the AIO. The existing Alpine area 2 injection order does not specify the type of fluids 3 that could be injected for enhanced oil recovery. And 4 so what we're asking for is to essentially formalize 5 what is already a practice of injecting fluids for 6 pressure management and specify the fluids that are 7 allowed. And this will essentially bring us -- bring 8 the Alpine pool in consistency with the newer area 9 injection orders that have been issued by the 10 Commission. The Alpine and the Kuparuk pool is based 11 on a MWAG flood which -- so it uses enriched gas and 12 water for pressure management. And our primary sources 13 of water injection are Kuparuk seawater treatment plant 14 water and produced water from the Alpine central 15 facility which we've injected for the past 15 plus year 16 and also enriched gas from the Alpine central facility. 17 So those are the three primary fluids that are injected 18 in the Alpine oil pool. And then there's a list of 19 seven additional fluids that are used in much smaller 20 volumes for various purposes. 21 And so with this rule and the other fluids that 22 we're asking for are essentially consistent with the 23 fluids that have been approved in other area injection 24 order so we wanted to be as consistent with those as 25 possible with this proposed request. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/AIO-003 Page 42 1 And that really concludes our presentation. We 2 believe that the amendment and this amendment and all 3 the other proposed changes will not promote any waste 4 and will ultimately help us increase recovery from the 5 whole field. And please let me know if you have any 6 questions. 7 CHAIR FOERSTER: Okay. I'm going to suggest 8 that we take a brief recess and see if our smart staff 9 in the back has any questions that we're not smart 10 enough to think of. But before we do that do you have 11 anything you want to ask before we recess, Commissioner 12 Seamount? 13 COMMISSIONER SEAMOUNT: Okay. You've got 10 14 fluids you would like to inject. Do all these fluids 15 optimize oil recovery? 16 MR. SOOD: The different fluids are used for 17 different purposes. And so it really depends on the 18 purpose. The three fluids on top are the ones we use 19 primarily for pressure injection support. The 20 remaining fluids are all used in someway to help 21 support the wells. 22 COMMISSIONER SEAMOUNT: Okay. Thank you. 23 CHAIR FOERSTER: Commissioner French? 24 COMMISSIONER FRENCH: No. 25 CHAIR FOERSTER: All right. Then it is 12 Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/AIO-003 Page 43 1 minutes after 10:00. Let's take a 15 minute recess, 2 come back at 12:22. That's a 10 minute recess. Let's 3 take a 15 minute and come back at 10:27. We're on 4 recess. 5 (Off record) 6 (On record) 7 CHAIR FOERSTER: All right. We'll come back on 8 the record at 10:25. It's two minutes earlier than 9 what we said, but everyone appears to be here. 10 I have a questions, but before I ask my 11 questions, Commissioner Seamount, do you have any 12 questions? 13 COMMISSIONER SEAMOUNT: I have none. 14 CHAIR FOERSTER: Commissioner French? 15 COMMISSIONER FRENCH: None besides those. 16 CHAIR FOERSTER: Okay. Are any of the 17 injection wells going to be hydraulically fractured? 18 MR. JOHNSTONE: No, other than -- not 19 hydraulically stimulated. 20 CHAIR FOERSTER: Okay. Don't forget to say 21 what your name is when you..... 22 MR. JOHNSTONE: Oh, yeah. Sam Johnstone, 23 sorry. 24 CHAIR FOERSTER: Okay. Thank you. During the 25 recess we pulled up other 66 and it specifically left Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email• sahile@gci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO- 17-004/AIO-003 Page 44 1 the Alpine pool out. So there shouldn't be confusion 2 between other 66 and the Alpine specific rule on safety 3 valve systems. However other order 66 does not address 4 check valves and you -all's rules specifically does. So 5 would that not create some confusion? 6 MR. SOOD: Could you restate the question, 7 please? 8 CHAIR FOERSTER: Okay. Other 66 specifically 9 excluded Alpine. And so there shouldn't be any 10 confusion between other 66 and the Alpine rules, it 11 should be clear to anyone reading other 66 to put it 12 aside and look at your own specific pool rules. 13 MR. SOOD: Right. Yes. 14 CHAIR FOERSTER: So I'm a little confused as to 15 the purpose of requesting the elimination of the rules 16 that other 66 leaves intact. 17 MR. SOOD: So really the purpose is that, you 18 know, initially we had the rule and then the rule was 19 rescinded or parts of the rule were. And now we will 20 have an updated area injection order which will 21 continue to reflect the old rule which has been 22 superseded. So we just wanted to take the opportunity 23 to have the rule that's not superseded in the updated 24 conservation order. 25 CHAIR FOERSTER: So I'm not sure I'm following Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/AIO-003 Page 45 1 you. 2 MR. JOHNSTONE: Can I -- this is Sam Johnstone, 3 can I -- so the current rule, rule 5, regarding safety 4 valve -- surface safety valves and SSSVs applies both 5 to producers and injections. In the revision of other 6 order 66 it -- that rule -- the revised language only 7 regulates or governs injection wells. So if we were to 8 move that revised language and replace the language in 9 rule five, that would -- for me that would clarify what 10 our responsibilities are regarding rule five. 11 CHAIR FOERSTER: Okay. So you want to 12 eliminate rule five? 13 MR. JOHNSTONE: I'm -- I'd be fine with 14 amending rule five with the language in other order 66. 15 CHAIR FOERSTER: Well, why would you put a 16 special rule in that just duplicates the statewide 17 rule, I mean, isn't it a given that if there's not a 18 rule addressing it then the statewide rules apply? 19 MR. JOHNSTONE: Right. 20 CHAIR FOERSTER: Okay. So why would you put 21 in, oh, for us we want to follow the statewide rule, 22 why would you do that? 23 MR. JOHNSTONE: No, I think that's the original 24 option we came in with was let's remove it because 25 there's no reason because there's already a statewide Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/AIO-003 Page 461 1 rule. 2 CHAIR FOERSTER: Okay. But the statewide rule 3 doesn't address everything that we're currently 4 requiring at Alpine. 5 MR. JOHNSTONE: Correct. 6 CHAIR FOERSTER: Okay. So what you'd like to 7 do is have less restriction? 8 MR. JOHNSTONE: Yes. 9 CHAIR FOERSTER: Okay. So let's just call it 10 what it is. We're -- this isn't about confusion, this 11 is about alleviating some requirements? 12 MR. JOHNSTONE: No. I must have misunderstood 13 your question. It isn't. And our understanding is 14 that as it said in other order 66 that this revised 15 rule would supersede what was in rule five. 16 CHAIR FOERSTER: Okay. Fourteen existing 17 Commissioner orders include field or pool specific 18 safety valve system requirements that the Commission 19 considers appropriate for retention. Wording for the 20 same safety valve system requirements existing in 21 different Commission orders has been standardized. As 22 an order fully set forth in the attached table, those 23 order are bing, Bing, Bing, bing, bing, bing. 24 MR. JOHNSTONE: Right. 25 CHAIR FOERSTER: So that to me says..... Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-l7-004/AIO-003 Page 47 1 MR. JOHNSTONE: And then the next paragraph. 2 CHAIR FOERSTER: Now therefore it is ordered 3 that individual rules in 34 existing Commission orders 4 that relate to well safety valve systems are hereby 5 rescinded. But your order..... 6 MR. JOHNSTONE: Or revised. 7 CHAIR FOERSTER: Or revised. But your order 8 was one of those ding, ding, dings. 9 MR. JOHNSTONE: Yes, which was revised. 10 CHAIR FOERSTER: Okay. No. They listed 14 11 rules that they say 14 existing orders already have 12 ones and those will remain. And for the other 34 or 40 13 -- 34 then they're rescinded and they go to the 14 statewide rule, correct? 15 MR. JOHNSTONE: So it's my understanding that 16 -- and Kevin can help out. But so our -- the rule was 17 not rescinded for other order 66 for Alpine pool..... 18 CHAIR FOERSTER: Right. 19 MR. JOHNSTONE: .....but it was revised. In 20 the table -- other order 66 table..... 21 CHAIR FOERSTER: Uh-huh. 22 MR. JOHNSTONE: .....as you scroll across the 23 Alpine unit you have an existing order requirement and 24 then on the other side you have the revised rule. 25 CHAIR FOERSTER: Uh-huh. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/AIO-003 Page 48 1 MR. JOHNSTONE: That's where the confusion for 2 me comes in because they are different. 3 MR. DONNELLY: This is Kevin Donnelly, 4 Commissioner Foerster. I think that all we're asking 5 is go by the statewide rule. I think you've hit that 6 on the head and I think that we're not asking for 7 anything more, we're not asking any special 8 dispensation or changing the rules. 9 CHAIR FOERSTER: Okay. 10 MR. DONNELLY: And so we may have over 11 complicated this by presenting this, but all we're 12 saying is rule five no longer applies, that's exactly 13 what other order 66 says. And we're going to live by 14 what's in the table because 443B was one of the bing, 15 bing, bings. 16 CHAIR FOERSTER: So you -- what you're saying 17 is you want to abide by this table? 18 MR. DONNELLY: That's correct. That is 19 absolutely correct. 20 CHAIR FOERSTER: Okay. 21 MR. DONNELLY: Which I think is exactly what 22 other order 66 did. 23 CHAIR FOERSTER: Okay. So what change is 24 needed? 25 MR. DONNELLY: There really isn't a change Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-l7-004/AIO-003 Page 49 1 that's needed. You know, I think that the -- the idea 2 is that from an operation's perspective, you know, our 3 original order still has rule five in it. I think 4 we're just validating that that's gone and we're now 5 going by other order 66. This is just sort of 6 emphasizing that. 7 CHAIR FOERSTER: Okay. If we remove rule five 8 does rule five not state what it's in this matrix? 9 MR. DONNELLY: Rule five states what's..... 10 CHAIR FOERSTER: What the existing order says. 11 MR. DONNELLY: .....the existing order, but not 12 the..... 13 CHAIR FOERSTER: Okay. 14 MR. DONNELLY: .....revised rule, correct. 15 CHAIR FOERSTER: Okay. Well, I have to think 16 about what the legal best way to do that is. But at 17 least I understand what you're asking for. 18 MR. DONNELLY: Yeah, I think that as it stands 19 I think that is the rule we go by, other order 66, it's 20 just a matter of clarifying. 21 CHAIR FOERSTER: You go by the matrix? 22 MR. DONNELLY: Correct. Yeah. 23 CHAIR FOERSTER: Okay. But what's in the 24 matrix is different than the statewide rules so if you 25 defaulted to statewide rules you'd have lower -- you'd Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/AIO-003 Page 501 1 have different requirements than this matrix? 2 MR. DONNELLY: In the existing..... 3 CHAIR FOERSTER: So you're not requesting to go 4 to statewide rules, you're requesting the other order? 5 MR. DONNELLY: (Indiscernible - away from 6 microphone)..... 7 CHAIR FOERSTER: Okay. All right. That's as 8 clear as mud. But, no, I think I know what you're 9 trying to achieve. How we best get there will be 10 reached with some discussions among technical staff and 11 legal staff. 12 All right. Any other questions for the good of 13 the order? 14 (No comments) 15 CHAIR FOERSTER: All right. Is there anyone 16 else who has anything they'd like to say, any 17 additional testimony from ConocoPhillips, anybody else 18 in the audience? 19 (No comments) 20 CHAIR FOERSTER: Seeing nothing, we're going to 21 adjourn at 10:30. 22 (Hearing adjourned 10:30 a.m.) 23 (END OF REQUESTED PORTION) 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 PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/AIO-003 Page 51 1 TRANSCRIBER'S CERTIFICATE 2 I, Salena A. Hile, hereby certify that the 3 foregoing pages numbered 02 through 51 are a true, 4 accurate, and complete transcript of proceedings in re: 5 Docket No.: CO 17-004, AIO 17-003 public hearing, 6 transcribed under my direction from a copy of an 7 electronic sound recording to the best of our knowledge 8 and ability. 9 Date Salena A. Hile, Transcriber 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: sahileggci.net STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Docket No. CO 17-004 and AIO 17-003 March 14, 2017 at 9:00 am NAME AFFILIATION Testify (yes or no) t n n _ 0 ConocoPhillips Alpine Oil Pool Expansion March 141h, 2017 Objective: Review Nanuq Kuparuk development drilling progress and the proposed Alpine Oil Pool expansion Presentation Outline: w Existing Alpine Oil Pool w Alpine Oil Pool Expansion w Future Nanuq Kuparuk sand development w CD5-313 / CD5-315 drilling results w CD5-314X /CDS-316 drilling plans ® No Underground Sources of Drinking Water - Injection Containment in the Alpine Oil Pool ® Proposed CO & AIO Amendments ComcoFhiliips History Conservation Order (CO 443) • Oct 1998 original CO 443 issued • Oct 2004 CO 443A approved to expand development • Mar 2009 CO 443B approved joining Alpine and Kuparuk pools Area Injection Order (AIO 18) • Jan 2000 original AlO 18 issued • Apr 2000 A10 18A approved Class II disposal • Oct 2004 NO 18B approved to expand development 7276 • Mar 2009 AlO 18C approved injection into expanded Alpine pool GR NID, RC DT 0 gAP1 150 1:1000 1.1 ohrn.m 103.0 150 uts.ffl 50 C RQ RH06 G 1. ,hm.rn 1D3.0 1.55 Wcm3 2.6 Alpine #1 Type Log Nan. KuparuK Miluveach Alpine C Alpine A Kingak Updating AOP boundary • Add 6 sections in southwest corner of the CRU to accommodate new leases and development plan ® Contract —16 sections on the east side of the CRU to align with the contracted unit boundary • Requested pool rule changes ® Remove CO 443B Rule 5 governing safety valve systems • Add A10 rule to govern injection pressure Add A10 rule specifying authorized injection fluids •.'.,n+.•ep 1•�R IAM k'-A5KA COLVILLE RIVER UNIT "/roll Pea Alone Un Pad E.Pnilor «• Pla errlt Le4rr4l INone Oil Pod Conow on Lalerdl (3 Alpz,e Oil Pod N k ConOCOMMIPS Colvdie River Unit Alpine Oil Pool Expansion COn000i�liliips r 4 5rJ "/roll Pea Alone Un Pad E.Pnilor «• Pla errlt Le4rr4l INone Oil Pod Conow on Lalerdl (3 Alpz,e Oil Pod N k ConOCOMMIPS Colvdie River Unit Alpine Oil Pool Expansion COn000i�liliips Nanuq Kuparuk Type Log 728 North Periscope Deep Resistivity Image Kuparuk Kalubik 0^ -OF 7320 P 7340 7360 0 0 0 0 0 0 rt e•f v' rel ri ri Miluveach s 0 0 0 0 0 o v o o v o 0 0 0 0 0 0 0 0 0 0 o a v o o n o sn o v+ ea LM o Rt+ o LM o en o vs o a� u1 in w %0 er t- 00 00 cT M Q G r4 r1 r4 ri sal M ri M ri rl H -4 N N N Lateral length: 10,392 feet Net Sand: 10,392 feet Thickness: 7-12 feet continuous Perm est: 100-500 and South ConocoPhillips Confidential Section Break ® Salinity exceeds regulatory standard for freshwater Water salinity calculations on wells in the Colville Delta area for the 1999 Alpine AlO found no sands with < 10,000 mg/l TDS Water salinity calculations on wells in the CD5 area found no sands with < 101000 mg/I TDS Water Samples collected from drill stem and production testing of several wells in the Colville Delta area yielded 18,500 to 24,000 mg/I TDS CO443 found there are no freshwater aquifers in the Colville River Unit (Conclusion #5). Salinities calculated with Rwa technique - assumes clean, 100% wet sands No clean sands with < 10,000 mg/I TDS were found in CD5-21, Nuiqsut 1 or Clover A ,... ,..LI I it2RiF bk Ti2P P 'i �Nuigsut 1 Cb5 21 -4M- It EIt ''1 {3iig�3`c WO Fee ., Alpne Od Pea E+pxnaan PlenreJ LAt/d ..' NPee OSI Pod Cennwtim L.We �AlPne au Pea rr ;sz Conoco"Ilps CoNdle River Unit Alpine Oil Pool Expansion Salinity 21,000 mg/I 24,000 mg/I 18,000 mg/I 20,000 mg/I 21,000 mg/I 25,000 mg/I 16,000 mg/I CD5-21 GR t RES 100 PHIT, u FTEMP Zoo RWA Measured N AL A$KA I COLVILLE RIVER UNIT ,... ,..LI I it2RiF bk Ti2P P 'i �Nuigsut 1 Cb5 21 -4M- It EIt ''1 {3iig�3`c WO Fee ., Alpne Od Pea E+pxnaan PlenreJ LAt/d ..' NPee OSI Pod Cennwtim L.We �AlPne au Pea rr ;sz Conoco"Ilps CoNdle River Unit Alpine Oil Pool Expansion Salinity 21,000 mg/I 24,000 mg/I 18,000 mg/I 20,000 mg/I 21,000 mg/I 25,000 mg/I 16,000 mg/I CD5-21 GR t RES 100 PHIT, u FTEMP Zoo RWA Measured • Original COs for all WNS pools specified a surface controlled subsurface safety valve (SCSSSV) for producing wells and gas injection wells • Alpine CO was revised by Other Order 66 in 2011. • WNS producers now regulated by 20 AAC 25.265 • WNS injectors now regulated by Other Order 66 • Proposed Revision: Remove CO 4436 Rule 5 (operations of safety valve systems) because it has been superseded by Other Order 66 ConocoPhillips • Existing Alpine A1O does not govern injection pressure • Proposed Revision: Add AlO rule that limits the injection pressure to 0.81 psi/ft 11 Cor*coMillips 6700 6800 6900 7000 7100 7200 7300 7400 Collapse GR Resistivitv Vshale r-mrtnra Grariiant UCS 0 150 1 100 0 1 8 PPG 18 0 PSI 1000 -7 �1 Took '- LOT data from Al' H RZ i "n Ln 00 I Kalubik 1 1 �._ Nanuq Kup r *2- Miloveac AtP A CL a y ti o Kingak Nuigsut )ine wells Truk Maximum injection gradien Alpine and Kuparuk sands: 0.65 psi/ft fracture gradient from stimulation and drilling data HRZ, Kalubik, Miluveach: 0.85-0.90 psi/ft fracture gradient from LOT and mechanical earth model d- ConocoPhillips WATER INJECTION WITHOUT PROPPED FRACTURE IN THE ALPINE ZONE FLOODED AT 10,000 BPD prte,.* -- - - - -. -- ..7'7.'..1",ilit'f.f 11!11!111111li1/11H11111111lIll/Eilllillflllilllill11111!111!9111 Ilil!Ili 13 WATER INJECTION WITHOUT PROPPED FRACTURE IN THE NANUQ KUPARUK ZONE FLOODED AT 10,000 BPD --------------------------------------- ---- ® monruu.nuaunuuununuuunnommuuuurqurrauonununauuu uunnnnuennunruuuunnnuannnnnunuuuunnuuuaonr0O0°°°O0°0°1°°1°1°°°°1°10°0O1°°1°��0110°°0i°ii iiiiiiiiiiii uni�iiif�iiniiiii� IIIIIIIIOIIIIIIIIIUIIIIIII--111................................................III__I„_...._....I..................... .,,,.,,,,,,,.,,,, , ,,,...,.t... ......,.„..„..„....„..„... 14 • Existing Alpine NO does not specify the injection fluids ® Proposed Revision: Add rule specifying authorized injection fluids 1. Source water from the Kuparuk seawater treatment plant 2. Produced water from the Alpine Central Facility 3. Enriched hydrocarbon gas (MI) from the Alpine Central Facility 4. Lean Gas 5. Fluids used during hydraulic stimulation 6. Tracer survey fluids to monitor reservoir performance (chemical, radioactive, etc.) 7. Fluids used to improve near wellbore injectivity 8. Fluids used to seal wellbore intervals which negatively impact recovery efficiency (cement, resin, etc.) 9. Fluids associated with freeze protection (diesel, dead crude, glycol, methanol etc.) 10. Standard oilfield chemicals (corrosion inhibitor, scale inhibitor, etc.) ConocoPhillips Confidential Exhibits 1— 4 held in secure storage Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Docket Number CO -17-004 and AIO-17-003 Alpine Oil Pool, Colville River Unit Pool Rules ConocoPhillips Alaska, Inc. (CPAI), by application received January 31, 2017, requests the Alaska Oil and Gas Conservation Commission (AOGCC) approve administrative amendments to Conservation Order 443B (CO 443B) and Area Injection Order 18C (AIO 18C) to allow for the expansion of the Alpine Oil Pool to include the westward development of the Nanuq Kuparuk sands in anticipation of future development for oil production. The AOGCC has tentatively scheduled a public hearing on this application for March 14, 2017, at 9:00 a.m. at 333 West 7th Avenue, Anchorage, Alaska 99501. To request that the tentatively scheduled hearing be held, a written request must be filed with the AOGCC no later than 4:30 p.m. on February 21, 2017. If a request for a hearing is not timely filed, the AOGCC may consider the issuance of an order without a hearing. To learn if the AOGCC will hold the hearing, call (907) 279-1433 after February 23, 2017. In addition, written comments regarding this application may be submitted to the AOGCC, at 333 West 7th Avenue, Anchorage, Alaska 99501. Comments must be received no later than 4:30 p.m. on March 9, 2017, except that, if a hearing is held, comments must be received no later than the conclusion of the March 14, 2017 hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact the AOGCC at (907) 279-1433, no later than March 7, 2017. Cathy P oerster Commi sioner Misty Alexa Manager, WNS Development North Slope Operations and Development ConocoPhillips Alaska, Inc. ATO -1770 700 G St. Anchorage, AK 99501 -cAa i U@ 2---7 - 20 k`7 RUi Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Docket Number CO -17-004 and AIO-17-003 Alpine Oil Pool, Colville River Unit Pool Rules ConocoPhillips Alaska, Inc. (CPAI), by application received January 31, 2017, requests the Alaska Oil and Gas Conservation Commission (AOGCC) approve administrative amendments to Conservation Order 443B (CO 44313) and Area Injection Order 18C (AIO 18C) to allow for the expansion of the Alpine Oil Pool to include the westward development of the Nanuq Kuparuk sands in anticipation of future development for oil production. The AOGCC has tentatively scheduled a public hearing on this application for March 14, 2017, at 9:00 a.m. at 333 West 7t" Avenue, Anchorage, Alaska 99501. To request that the tentatively scheduled hearing be held, a written request must be filed with the AOGCC no later than 4:30 p.m. on February 21, 2017. If a request for a hearing is not timely filed, the AOGCC may consider the issuance of an order without a hearing. To learn if the AOGCC will hold the hearing, call (907) 279-1433 after February 23, 2017. 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 4:30 p.m. on March 9, 2017, except that, if a hearing is held, comments must be received no later than the conclusion of the March 14, 2017 hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact the AOGCC at (907) 279-1433, no later than March 7, 2017. Hsignature on fileH Cathy P. Foerster Commissioner STATE OF ALASKA ADVERTISING ORDER NOTICE TO PUBLISHER SUBMIT INVOICE SHOWING ADVERTISING ORDER NO., CERTIFIED AFFIDAVIT OF PUBLICATION WITH ATTACHED COPY OFADVERTISMENT. ADVERTISING ORDER NUMBER AO-17-023 FROM: AGENCY CONTACT: Jody Colombie/Samantha Carlisle Alaska Oil and Gas Conservation Commission DATE OF A.O. AGENCY PHONE: 333 West 7th Avenue 02/07/17 1(907) 279-1433 Anchorage, Alaska 99501 DATES ADVERTISEMENT REQUIRED: COMPANY CONTACT NAME: PHONE NUMBER: ASAP FAX NUMBER: (907)276-7542 TO PUBLISHER: Alaska Dispatch News SPECIAL INSTRUCTIONS: PO Box 149001 Anchorage, Alaska 99514 TYPE OF ADVERTISEMENT: LEGAL DISPLAY CLASSIFIED I OTHER (Specify below) DESCRIPTION PRICE CO-17-004 and AIO-17-003 Initials of who prepared AO: Alaska Non -Taxable 92-600185 Streivjl; No;,.IC SHOWtMGAA.vi R[TSi G:: URDER :1!i0;, CERTIFIED P.tiBtirea rl0.N wiTH.ATTACHED . COPY OF ::: Department of Administration Division of AOGCC 333 West 7th AvenueJAIlt Anchorage, Alaska 99501 Pae 1 of 1Pages al of $ REF Type Number Amount Date Comments I PVN ADN89311 2 Ao AO-17-023 3 4 FIN AMOUNT SY Appr Unit PGM LGR Object FY I DIST LIQ I 17 021147717 3046 17 z 3 4 5 Purchasing Authority Name: � Title: P �ingthor' ature Telephone Number 4J CO— 12 1. A.O. # and receiving agency name must appear on all invoices and documents relating to this purch se. 2. The state is registered for tax free transactions under Chapter 32, IRS code. Registration number 92-73-0006 K. It a for the exclusive use of the state and not for resale. DI S:*li2IT#L1 10> . :::::::::::::::":"......:»::":::::"::":::::";::::"::."::::'..:'.'.'.':'.':'.'.'.'::'::::::':':':':':':':::":'::::':::':':'::':':" ": _ :':':': ":":"::::.. ....................................................... ... t 1 ii FIsC8Ii:R. eceJYIn' �'>:::::::::::::::�::: : I)ysioti:FscaU©riginal AO:.:.:::::::::.:Copies:c:uiilishei;(fa:xed);:Dly s.o .... , ... .. g. ........ ...... . Form: 02-901 Revised: 2/7/2017 270227 0001399979 $204.20 G FE I FEP 10 701? 4-JIGGG AFFIDAVIT OF PUBLICATION STATE OF ALASKA THIRD JUDICIAL DISTRICT Emma Dunlap being first duly sworn on oath deposes and says that he/she is a representative of the Alaska Dispatch News, a daily newspaper. That said newspaper has been approved by the Third Judicial Court, Anchorage, Alaska, and it now and has been published in the English language continually as a daily newspaper in Anchorage, Alaska, and it is now and during all said time was printed in an office maintained at the aforesaid place of publication of said newspaper. That the annexed is a copy of an advertisement as it was published in regular issues (and not in supplemental form) of said newspaper on February 08, 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 charged private individuals. Subscribed and sworn to before me this 8th day of February, 2017 Notary Publicin d for The State of Alaska. Third Division Anchorage, Alaska MY COMMISSION EXPIRES Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Docket Number CO -17-004 and AIO-17-003 Alpine Oil Pool, Colville River Unit Pool Rules ConocoPhillips Alaska, Inc. (CPAI), by application received January.31, 2017, requests the Alaska oil and Gas Conservation Commission (AOGCC) approve administrative amendments to Conservation Order 4438 (CO 44313) and Area Injection Order 18C (AID 18C) to allow for the expansion of the Alpine oil Pool to include the westward development of the Nanuq Kuparuk sands in anticipation of future development for oil production. The AOGCC has tentatively scheduled a public hearing on this application for March 14, 2017, at 9:00 a.m. at 333 West 7th Avenue, Anchorage, Alaska 99501. To request that the tentatively scheduled hearing be held, a written request must be filed with the AOGCC no later than 4:30 p.m. on February 21, 2017. If a request for a hearing is not timely filed, the AOGCC may consider the issuance of an order without a hearing. To learn if the AOGCC will hold the hearing, call (907) 279-1433 after February 23, 2017. in addition, written comments regarding this application may be submitted to the AOGCC, at 333 West 7th Avenue, Anchorage, Alaska 99501. Comments must be received no later than 4:30 p.m. on March 9, 2017, except that, if a hearing is held, comments must be received no later than the conclusion of the March 14, 2017 hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact the AOGCC at (907)279-1433, no later than March 7, 2017. Hsignature on file// Cathy P. Foerster Commissioner AO -17-023 Published: February 8, 2017 Notary Public BRITNEY L. THOMPSON State of Alaska My Commission Expires Feb 23, 2019 Bernie Karl K&K Recycling Inc. Gordon Severson Penny Vadla P.O. Box 58055 3201 Westmar Cir. 399 W. Riverview Ave. Fairbanks, AK 99711 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 rn�,; -oL 2--7- 2 o \-T 0 Singh, Angela K (DOA) From: Carlisle, Samantha J (DOA) Sent: Tuesday, February 07, 2017 8:25 AM To: Ballantine, Tab A (LAW); Bender, Makana K (DOA); Bettis, Patricia K (DOA); Bixby, Brian D (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Cook, Guy D (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA); French, Hollis (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Herrera, Matthew F (DOA); Jones, Jeffery B (DOA); Kair, Michael N (DOA); Link, Liz M (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Quick, Michael J (DOA); Regg, James B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Wallace, Chris D (DOA); AK, GWO Projects Well Integrity; AKDCWellIntegrityCoordinator, Alan Bailey, Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew VanderJack; Ann Danielson; Anna Raff; Barbara F Fullmer, bbritch; bbohrer@ap.org; Ben Boettger; Bill Bredar; Bob Shavelson; Brandon Viator; Brian Havelock, Bruce Webb; Caleb Conrad; Candi English; Cocklan-Vendl, Mary E; Colleen Miller, Connie Downing; Crandall, Krissell; D Lawrence; Dale Hoffman; Dave Harbour, David Boelens; David Duffy; David House; David McCaleb; David McCraine; David Tetta; ddonkel@cfl.rr.com; DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elizabeth Harball; Elowe, Kristin; Evan Osborne; Evans, John R (LDZX); Gary Oskolkosf, George Pollock, Gordon Pospisil; Greeley, Destin M (DOR); Gretchen Stoddard; gspfoff, Hurst, Rona D (DNR); Hyun, James J (DNR); Jacki Rose; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jill Simek; Jim Watt; Jim White; Joe Lastufka; Radio Kenai; Burdick, John D (DNR); Easton, John R (DNR); Larsen, John M (DOR); John Stuart; Jon Goltz; Chmielowski, Josef (DNR); Juanita Lovett; Judy Stanek; Kari Moriarty, Kasper Kowalewski; Kazeem Adegbola; Keith Torrance; Keith Wiles; Kelly Sperback; Frank, Kevin J (DNR); Kruse, Rebecca D (DNR); Gregersen, Laura S (DNR); Leslie Smith; Lori Nelson; Louisiana Cutler, Luke Keller, Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Mealear Tauch; Michael Bill; Michael Calkins; Michael Moora; MJ Loveland; mkm7200; Mueller, Marta R (DNR); Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nikki Martin; NSK Problem Well Supv; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Renan Yanish; Richard Cool; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shahla Farzan; Shannon Donnelly, Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Skutca, Joseph E (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Stephanie Klemmer; Stephen Hennigan; Sternicki, Oliver R; Moothart, Steve R (DNR); Steve Quinn; Suzanne Gibson; Sheffield@aoga.org; Ted Kramer, Temple Davidson; Teresa Imm; Thor Cutler, Tim Jones; Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Umekwe, Maduabuchi P (DNR); Vinnie Catalano; Well Integrity, Well Integrity, Weston Nash; Whitney Pettus; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Assmann, Aaron A; Bajsarowicz, Caroline J; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Catie Quinn; Don Shaw; Eric Lidji; Garrett Haag; Smith, Graham O (DNR); Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Fair, Holly S (DNR); Holly Pearen; Jamie M. Long; Jason Bergerson; Jesse Chielowski; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Franger, James M (DNR); Morgan, Kirk A (DNR); Umekwe, Maduabuchi P (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); Tostevin, Breck C (LAW); Wayne Wooster, William Van Dyke Subject: CO -17-004 and AIO-17-003 Public Hearing Notice (Alpine Oil Pool) Attachments: CO -17-004 and AIO-17-003 Public Hearing Notice.pdf ConocoPhillips Alaska, Inc. (CPAI), by application received January 31, 2017, requests the Alaska Oil and Gas Conservation Commission (AOGCC) approve administrative amendments to Conservation Order 443B (CO 443B) and Area Injection Order 18C (AIO 18C) to allow for the expansion of the Alpine Oil Pool to include the westward development of the Nanuq Kuparuk sands in anticipation of future development for oil production. Samantha Carlisle Executive Secretary III Alaska Oil and Gas Conservation Commission 333 West 71h Avenue Anchorage, AK 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 mnintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Samantha Carlisle at (907) 793-1223 or Samantlna.Carlisle@alaska.gov. Jan 301h, 2017 Catherine P. Foerster, Chair Alaska Oil and Gas Conservation Commission 333 W. 7th Ave #100 Anchorage, Alaska, 99501-3539 JAN 3 1 70117 Misty Alexa Manager, WNS Development North Slope Operations and Development ConocoPhillips Alaska, Inc. ATO -1770 700 G Street Anchorage, AK 99501 phone 907.265.6822 RE: Application for Pool Rules Expansion Alpine Oil Pool, North Slope, AK Dear Commissioner Foerster: ConocoPhillips Alaska, Inc. ("CPAI") as operator of the Colville River Unit ("CRU") and on behalf of the Working Interest owners, requests that the Alaska Oil and Gas Conservation Commission ("Commission") approve administrative amendments to Conservation Order C0443B and Area Injection Order 18C to allow for the expansion of the Alpine Oil Pool ("AOP") to include the westward development of the Nanuq Kuparuk sands in anticipation of future development for oil production. The proposed AOP, as described in the attached application, extends the existing AOP to include prospective Nanuq Kuparuk sandstone targets that CPAI intends to drill in 2017. Enclosed are two printed originals of the application and a disc containing an electronic version of the application. Please contact Anu Sood (263-4802) if you have questions or require additional information. Regards, Misty exa Manager, WNS Development North Slope Operations and Development Cc: Michael Nance, Anadarko E&P Onshore LLC, Michael Nixson, Anadarko E&P Onshore LLC Enclosures (3) PAGE LEFT BLANK INTENTIONALLY CPAI Application for Alpine Oil Pool Expansion Jan 2017 Page 1 Cono(coPhillips APPLICATION FOR EXPANSION AND OTHER MODIFICATION OF THE ALPINE OIL POOL INJECTION ORDER Jan 30th, 2017 1. Introduction 2. Alpine Oil Pool History 3. Proposed Alpine Pool Expansion 4. Nanuq Kuparuk Sand Development 5. Development Drilling Plans 6. Proposed Amendments to Alpine Oil Pool Rules 7. Proposed Amendment to Alpine Area Injection Order 8. No Underground Sources of Drinking Water List of Figures 1. Proposed Alpine Oil Pool Area 2. Nanuq Kuparuk Type Log 3. Water Injection without propped fracture in the Alpine 4. Water Injection without propped fracture in the Nanuq Kuparuk 5. Kuparuk Seawater Treatment Plant Water Composition 6. Alpine Facility Produced Water Composition 7. Alpine Facility Gas Injectant Composition 8. Alpine Pool Expansion Area with Penetrations Examined for Freshwater Sources 9. Clover A Formation Water Salinity 10. CD5-21 Formation Water Salinity 11. Nuiqsut 1 Formation Water Salinity CPAI Application for Alpine Oil Pool Expansion Jan 2017 Page 2 12. Confidential: Nanuq Kuparuk C Gross Sand Thickness 13. Confidential: CD5-315 Lateral Cross Section 14. Confidential: West-East VP/ VS Seismic Section 15. Confidential: Alpine C Gross Sand Thickness Confidential materials are submitted in Appendix 1 CPAI Application for Alpine Oil Pool Expansion Jan 2017 Page 3 1. INTRODUCTION Document Scope This application is submitted for approval by the Alaska Oil and Gas Conservation Commission ("Commission") to expand the Alpine Oil Pool to accommodate the development of the Nanuq Kuparuk sands, to contract acreage on the eastern side of the pool to conform to the Colville River Unit (CRU) boundary, and to update the existing Alpine Pool Conservation Order (CO) 443B and Area Injection Order (AIO) 18C. In addition to expanding the AOP, CPAI also requests the commission revise the CO rules and AIO rules specified below to eliminate redundancy and clarify injection requirements. 2. ALPINE OIL POOL HISTORY Original AOP CO 443 & AIO 18 The Alpine Oil Pool CO 443 as issued in October, 1998 by the commission originally included the accumulation of hydrocarbons common to and correlating with the interval between the measured depths of 6,876 feet and 6,976 feet in the Bergschrund No. 1 well. This accumulation stratigraphically defines the oil-bearing sandstone body named Alpine. The AIO to inject fluids for enhanced oil recovery from the Alpine Oil Pool was granted in January, 2000. Amendment CO 443A & AIO 18B In October 2004, C0443 and AIO 18 were concurrently expanded to accommodate development. Amendment CO 443E & 18C In March, 2009, CPAI demonstrated pressure communication between the Alpine and Kuparuk formations in the Colville River Unit. The commission thus terminated the Nanuq Kuparuk Oil Pool CO 563 and amended conservation order CO 443A to include the Nanuq Kuparuk formation. Thus CO 443A was amended to CO 443B to stratigraphically include Nanuq Kuparuk Oil Pool acreage within the Alpine Oil Pool (AOP). The AOP was redefined as the accumulation of hydrocarbons common to and correlating with the interval between the measured depths of 6,980 feet and 7,276 feet in the Alpine No. 1 well. Alpine Oil Pool AIO 18B was also concurrently amended to AIO 18C expanding the Alpine Oil Pool EOR project. This expansion defined the AOP as stratigraphically including the Nanuq-Kuparuk Oil Pool acreage. 3. PROPOSED ALPINE OIL POOL APPLICATION Request Scope ConocoPhillips Alaska, Inc. (CPAI) requests the commission to amend CO 443B and AIO 18C to expand the AOP area to include 6 more full sections of land at the western boundary and contract 16 full and partial sections from the eastern boundary (Figure 1). Extending the AOP westward into Umiat Meridian T10NR3E Sections 2-3 and T11N R3E Sections 22, 27, 34, 35, will allow development drilling of up to two additional Kuparuk sand wells: CD5-314X and depending on results, potentially CD5-316. The development plans for these two wells are described in Section 4: Nanuq Kuparuk Sand Development. Contracting 16 full and partial sections on the eastern side will bring the AOP in line with the eastern CRU boundary. CPAI Application for Alpine Oil Pool Expansion Jan 2017 Page 4 As proposed to be expanded and contracted, the affected area of the AOP pool rules is totally encompassed within the sixth expansion of the Colville River Unit, which expansion was approved by the Royalty owners and the Alaska Department of Natural Resources on July, 2016. 4. NANUQ KUPARUK SAND DEVELOPMENT Development Plans The expansion of the AOP will extend the pool to include the western extension of the Nanuq Kuparuk reservoir for development from the CD5 pad (Figure 1). Up to two wells targeting the Nanuq Kuparuk sandstone could be drilled and completed in 2017. These planned wells were used to help determine the outline of the proposed oil pool expansion. Nanuq Kuparuk production from the CD4 pad began in late 2006. A total of 4 producers and 5 injectors were drilled to develop the reservoir from CD4. In 2015, the CD5-313 producer and CD5-315 injector were completed in the continuation of the Nanuq Kuparuk trend to the west. As of this application date, roughly 30 MMBO have been produced from the Nanuq Kuparuk reservoir. Figure 2 is a type log for the Nanuq Kuparuk reservoir. The Nanuq Kuparuk reservoir lies within the Early Cretaceous -aged Kuparuk River Formation. The reservoir is a thin, transgressive, shallow marine sandstone that lies atop the Lower Cretaceous Unconformity ("LCU"), which is a regional erosional surface. It consists of fine- to medium -grained, quartz -rich sandstone that contains varying amounts of glauconite, and ranges from 4 to 14 feet thick The continuation of the Nanuq Kuparuk reservoir westward to the expansion area is largely tied to encouraging results from the CD5-315 lateral. Appendix 1 is a confidential section that expounds upon the geology of the pool expansion area. 5. DEVELOPMENT DRILLING PLANS Planned Wells CPAI intends to drill the CD5-314X production well in 2017. Depending on the presence and extent of the Nanuq Kuparuk sands, supporting injection well CD5-316 will be drilled (Figure 1). 6. PROPOSED AMENDMENTS TO ALPINE OIL POOL RULES Affected Area CPAI proposes the area subject to conservation order for the Alpine Oil Pool be expanded and contracted so that the order applies to the following, restated lands: Umiat Meridian T1 ON, R3E Section 1-3 all T1 ON, R4E Section 1-6 all T1 ON, R5E Section 5 N1/2NW1/4, SW1/4NW1/4, NW1/4SW1/4 Section 6 all T11N, R3E Section 1-2 all Section 11-14 all Section 22-27 all CPAI Application for Alpine Oil Pool Expansion Jan 2017 Page 5 Rule 5 CPAI requests that the commission delete Rule 5 of CO 443B, which originally governed the operations of safety valve systems. To eliminate redundant requirements and standardize wording for multiple field and pool specific safety valve system requirements, individual commission orders that relate to well safety valve systems were rescinded or revised per Order 66 in 2011. At this point, Rule 5 is extraneous. For clarity and good order, CPAI asks that Rule 5 be deleted in the updated AOP conservation order. 7. PROPOSED AMENDMENT TO ALPINE AREA INJECTION ORDER (AIO) To conform to the proposed changes to the affected area of the Alpine Oil Pool described in section 6, above, CPAI proposes that the affected area for AIO 18B be restated as follows: Umiat Meridian T1 ON, RK Section 34-36 all T1 IN, R4E Section 1-36 all T11N, R5E Section 1 W1/2W1/2 Section 2-11 all Section 14 NW1/4NW1/4 Section 15 W1/2, NE1/4, N1/2SE1/4, SW1/4SE1/4 Section 16-21 all Section 22 NW1/4, NW1/4SW1/4 Section 28-33 all T12N, R3E Section 25-26 all Section 35-36 all T12N, R4E Section 20-36 all T12N, R5E Section 13-15 all Section 19-23 all Section 26 NW1/4NW1/4, S1/2NW1/4, SW1/4, W1/2SE1/4 Section 27-35 all Section 36 SW1/4SW1/4 Rule 5 CPAI requests that the commission delete Rule 5 of CO 443B, which originally governed the operations of safety valve systems. To eliminate redundant requirements and standardize wording for multiple field and pool specific safety valve system requirements, individual commission orders that relate to well safety valve systems were rescinded or revised per Order 66 in 2011. At this point, Rule 5 is extraneous. For clarity and good order, CPAI asks that Rule 5 be deleted in the updated AOP conservation order. 7. PROPOSED AMENDMENT TO ALPINE AREA INJECTION ORDER (AIO) To conform to the proposed changes to the affected area of the Alpine Oil Pool described in section 6, above, CPAI proposes that the affected area for AIO 18B be restated as follows: Umiat Meridian T1 ON, RK Section 1-3 all T10N, R4E Section 1-6 all T1 ON, R5E Section 5 N1/2NW1/4, SW1/4NW1/4, NW1/4SW1/4 Section 6 all T11N, R3E Section 1-2 all Section 11-14 all Section 22-27 all Section 34-36 all T11N, R4E Section 1-36 all T11N, R5E Section 1 W1/2W1/2 CPAI Application for Alpine Oil Pool Expansion Jan 2017 Page 6 Authorized Injection Pressures CPAI requests that the commission adopt a rule to govern injection pressure as follows: Proposed Rule: Authorized Injection Pressure for Enhanced Recovery Injection pressures will be managed not to exceed the maximum injection gradient of 0.81 psi/ft to ensure containment of injected fluids within the Alpine Oil Pool. In the Nanuq Kuparuk expansion area, the Kuparuk sandstone is overlain by 200-300 feet of Kalubik and HRZ shale and underlain by approximately 200 feet of Miluveach shale. Fracture gradient analysis has been calibrated with rock mechanical properties from core data and leak off tests from drilling data. Both the overlying Kalubik-HRZ sequence and the underlying Miluveach have fracture gradients of 0.85 psi/ft or higher. To ensure containment of injected fluids within the AOP, injection pressures will be managed as to not exceed the maximum injection gradient of 0.81 psi/ft. Average injection pressures will follow the fracture closure pressure gradient at sand face of 0.74 psi/ft. An internal containment assurance analysis, conducted by CPAI, indicates that the estimated maximum injection gradient of 0.81 psi/ft in the Alpine and Kuparuk wells in MWAG service will not initiate or propagate fractures through the confining strata. Operating at or below this limit will protect against the possibility of injection pressures causing injection or formation fluids to escape the AOP. The internal containment assurance analysis involved the use of a frac model based on Alpine 1 well log data and calibrated by using data from core sample geo-mechanical tests. The simulations of the long- term water injection cases were run and indicate that fracture growth is contained within the AOP without risk of breaking through overburden or under -burden containment zones. The frac modelling software used was version 8.4.0.15 of Grid Oriented Hydraulic Fracture Extension Replicator (GOHFER), due to its reliability and common use within ConocoPhillips as well as in the fracturing industry. GOHFER is a planar 3-D geometry fracture simulator developed by Barree & Associates in association with Stim-lab and is commercially available throughout the industry for performing hydraulic fracture simulation work. Section 2-11 all Section 14 NW1/4NW1/4 Section 15 W1/2, NE1/4, N1/2SE1/4, SW1/4SE1/4 Section 16-21 all Section 22 NW1/4, NW1/4SW1/4 Section 28-33 all T12N, R3E Section 25-26 all Section 35-36 all T12N, R4E Section 20-36 all T12N, R5E Section 13-15 all Section 19-23 all Section 26 NW1/4NW1/4, S1/2NW1/4, SW1/4, W1/2SE1/4 Section 27-35 all Section 36 SW1/4SW1/4 Authorized Injection Pressures CPAI requests that the commission adopt a rule to govern injection pressure as follows: Proposed Rule: Authorized Injection Pressure for Enhanced Recovery Injection pressures will be managed not to exceed the maximum injection gradient of 0.81 psi/ft to ensure containment of injected fluids within the Alpine Oil Pool. In the Nanuq Kuparuk expansion area, the Kuparuk sandstone is overlain by 200-300 feet of Kalubik and HRZ shale and underlain by approximately 200 feet of Miluveach shale. Fracture gradient analysis has been calibrated with rock mechanical properties from core data and leak off tests from drilling data. Both the overlying Kalubik-HRZ sequence and the underlying Miluveach have fracture gradients of 0.85 psi/ft or higher. To ensure containment of injected fluids within the AOP, injection pressures will be managed as to not exceed the maximum injection gradient of 0.81 psi/ft. Average injection pressures will follow the fracture closure pressure gradient at sand face of 0.74 psi/ft. An internal containment assurance analysis, conducted by CPAI, indicates that the estimated maximum injection gradient of 0.81 psi/ft in the Alpine and Kuparuk wells in MWAG service will not initiate or propagate fractures through the confining strata. Operating at or below this limit will protect against the possibility of injection pressures causing injection or formation fluids to escape the AOP. The internal containment assurance analysis involved the use of a frac model based on Alpine 1 well log data and calibrated by using data from core sample geo-mechanical tests. The simulations of the long- term water injection cases were run and indicate that fracture growth is contained within the AOP without risk of breaking through overburden or under -burden containment zones. The frac modelling software used was version 8.4.0.15 of Grid Oriented Hydraulic Fracture Extension Replicator (GOHFER), due to its reliability and common use within ConocoPhillips as well as in the fracturing industry. GOHFER is a planar 3-D geometry fracture simulator developed by Barree & Associates in association with Stim-lab and is commercially available throughout the industry for performing hydraulic fracture simulation work. CPAI Application for Alpine Oil Pool Expansion Jan 2017 Page 7 To study how fractures are initiated during injection in the Alpine and Kuparuk reservoirs and whether they can be effectively contained within the target interval, the following cases were simulated for a horizontal well: 1) Water Injection without propped fracture in the Alpine zone flooded at 10,000 bpd (Figure 3) 2) Water Injection without propped fracture in the Nanuq Kuparuk zone flooded at 10,000 bpd (Figure 4) The above simulations and 15+ years of injection history show that injection induced fractures will be contained within the AOP; no breakthrough of the overburden or under -burden containment zones will occur. Authorized Fluids for Enhanced Recovery CPAI requests that the commission specify a rule to include the type of fluids to be injected for enhanced recovery. Miscible Water -Alternating Gas flood is the enhanced recovery mechanism in the AOP with the use of either produced water or seawater. Other fluids may also be injected for: reservoir stimulation, reservoir performance evaluation, freeze protection, or chemical inhibition; however, these fluids are not planned for continuous injection as a means for enhanced recovery. The volumes of these other fluids are expected to be less than 0.1 % of the total volume injected and are not expected to hinder the recovery efficiency of the AOP. Proposed Rule: Authorized Fluids for Injection for Enhanced Recovery Fluids authorized for injection are: a. Source water from the Kuparuk seawater treatment plant b. Produced water from the Alpine Central Facility c. Enriched hydrocarbon gas (MI) from the Alpine Central Facility d. Lean gas e. Fluids used during hydraulic stimulation f. Tracer survey fluids to monitor reservoir performance (chemical, radioactive, etc.) g. Fluids used to improve near wellbore injectivity (via use of acid or similar treatment) h. Fluids used to seal wellbore intervals which negatively impact recovery efficiency (cement, resin, etc.) i. Fluids associated with freeze protection (diesel, dead crude, glycol, methanol etc.) j. Standard oilfield chemicals (corrosion inhibitor, scale inhibitor, etc.) Fluid Compatibility Fluid compositions are listed in Figures 5 to 7. No compatibility issues between the fluids listed above and Alpine-Kuparuk Reservoir fluids have been identified. CPAI Application for Alpine Oil Pool Expansion Jan 2017 Page 8 8. NO UNDERGROUND SOURCES OF DRINKING WATER No USDW History In the original Alpine Pool application, CPAI demonstrated there are no freshwater aquifers in the Colville River Unit. In finding number 18 of CO 443, the Commission stated: "Calculated water salinity ranges from 15,000 to 18,000 milligrams per liter (mg/1) total dissolved solids (TDS) throughout the Cretaceous and older stratigraphic section in the Colville Delta area. Water samples collected from drill stem and production testing of several wells in the Colville Delta area yielded 18,500 to 24,000 mg/I TDS." In conclusion number 5 of CO 443, the Commission stated: "There are no freshwater aquifers in the Colville River Unit". That prior finding and conclusion remain valid. Aquifer Studies in the AOP Expansion Area An internal study conducted by CPAI found no shallow fresh water bearing sands containing less than 10,000 mg/ TDS in the proposed expansion area. Three key wells were selected based on the presence of sufficient shallow logs and for geographic coverage over the expansion area. (Figure 8). The methodology used and results obtained from salinity calculations on Clover A (Figure 9), CD5-21 (Figure 10), and Nuiqsut 1 (Figure 11) are as follows. The calculations use the Rwa technique that re -writes the standard Archie equation (Equation 1) to solve for formation water resistivity in 100% water filled rock (Equation 2). The result can be given in either resistivity at a given temperature or salinity in mg/I. FRta.Syv Equation O'nxRt RW = Equation 2 a SW Salinity in mg/I Rw Resistivity of water necessary to make a zone 100% wet (0) Porosity in decimal from logs Rt Formation resistivity from logs m Cementation exponent. Assumed to be 2.0 per the Archie correlation a Assumed to be 1.0 per the Archie correlation Porosity (0) is mostly derived from either a Neutron -Density cross -plot or Density. Sonic has been used when neither Density nor Neutron log is available. For sonic porosity, the "Hunt -Raymer" algorithm is used (Equation 3). 0 = 0.6 * (AT 0 Sonic derived Porosity AT Delta Temperature - 56) /AT Equation 3 Log plots of Gamma Ray, Resistivity, Density Porosity, RWA and Salinity of the wells are shown in Figures 9 to 11. Clover A has only MWD GR/Resistivity information above 3400 feet with no fresh water bearing sands. Shaley sands between 3500 feet and top of the shallowest known oil bearing formation bear no fresh water. Calculated salinities are well above 40,000 mg/I, hence no fresh water aquifers. (Figure 9). CD5-21 has very little in the way of sand in its shallow interval (below Permafrost to about 5000 feet). The few shaley sands encountered have salinity ranging from 25,000 mg/I to 40,000 mg/I. It's conclusive that this well did not penetrate any fresh water bearing formation (Figure 10). CPAI Application for Alpine Oil Pool Expansion Jan 2017 Page 10 FIGURE 1: PLOT OF THE PROPOSED ALPINE OIL POOL CPAI Application for Alpine Oil Pool Expansion Jan 2017 Page 9 Nuiqsut -1 did not encounter any sand until approximately 2400 feet MD. Most of the shallow sands are tight (porosity 10-14%) and the few porous ones (20-29% porosity) have salinities ranging from 45,000- 65,000 mg/I. Detailed review of this well concludes that there is no fresh water aquifer (Figure 11). CPA[ Application for Alpine Oil Pool Expansion Jan 2017 Page 11 FIGURE 2: NANUQ KUPARUK TYPE LOG r STUD GRP34H RHOS 1:75 0 gkPl 15a 1.00 onm.m 100.00 2.000 km3 Color SII TNPH Color SG 1 10.60 tt31R3 .. gr CD5-313PB1 SSTVD GR P34H RH09_ 1:75 10 oi4Pl 150 1.00 ohm.m 100.00 .WD afcm3 3.040 riillml illk!4 1l:,,illi Ito II 1114 Fi •,r CPA] Application for Alpine Oil Pool Expansion Jan 2017 Page 12 FIGURE 3: WATER INJECTION WITHOUT PROPPED FRACTURE IN THE ALPINE ZONE FLOODED AT 10,000 RPD CPAI Application for Alpine Oil Pool Expansion Jan 2017 Page 13 FIGURE 4: WATER INJECTION WITHOUT PROPPED FRACTURE IN THE NANUQ KUPARUK ZONE FLOODED AT 10,000 BPD CPAI Application for Alpine Oil Pool Expansion Jan 2017 Page 14 FIGURE 5: KUPARUK SEAWATER TREATMENT PLANT WATER COMPOSITION Sample Number: S-160203-00063 Sample Name: STP Seawater Plant Discharge Location: Area: KUPARUK Unit: STP Sample Point: STP SPD Sampled Date: 2/2/2016 3:50:OOPM Matrix Id: WATER- SEA Reviewed By: Carville, Daniele Dater 02/24/2016 Analysis Results: Test Nremete r Result UOM BACTERIA' ATP ATPASE 31692 RLU DIONEX IC' ACETATE ACETATE <5.0 mg/I DIO NEX IC' BUTYRATE BUTYRATE e5.0 mg/I DIO NET{ IC' CHLORIDE CHLORIDE 184478 mg/I DID NEX IC' FORMATE FORMATE 45.0 mg/I DIO NEX ICPROPIONATE PROPIONATE <5.0 mg/I DIO NEX IC' SULFATE SO4(SULFATE) 2500.0 mg/I ICP METALS' AL(ALUMINUM) AL(AWMINUM) 0.04 mg/I ICP METALS' B (BORON) B(BORON) 4.65 mg/I ICP METALS' BA (BARIUM) BA (BARIUM) 0.15 mg/I ICP METALS' CA (CALCIUM) CA (CALCIUM) 428.59 mg/I ICP METALS' CR (CHROMIUM) CR (CHROMIUM) 0.01 mg/I ICP METALS' FE (IRON) FE(IRON) 0.07 mg/I ICP METALS' K (POTASSIUM) K (POTASSIUM) 391.42 mg/I ICP METALS' LI (LITHIUM) LI (LITHIUM) 0.22 mg/I ICP MErALS' MG (MAGNESIUM) MG (MAGNESIUM) 1110.38 mg/I ICP METALS' MN (MANGANESE) MN (MANGANESE) 0.009 mg/I ICP METALS' NA SODIUM) NA(SODIUM) 9973.7D mg/I ILP METALS' P (PHOSPHORUS) P (PHOSPHORUS) 0.03 mg/I ILP METALS' SI (SILICON) SI(SILICON) 1.43 mg/I ICP METALS' SR (STRONTIUM) CPAI Application for Alpine Oil Pool Expansion Jan 2017 Page 15 FIGURE 5: KUPARUK SEAWATER TREATMENT PLANT WATER COMPOSITION (CONTINUED) Sample Number: 5-160203.00063 Sample Name: STP Seawater Plant Discharge Location: Area: KUPARUK Unit: STP Sample Paint: STP SPD Sampled Date: 2/2/2016 3:50:DDPM Matrix Id: WATER- SEA Reviewed By. Carville, Daniele Date:02/24/2D16 Analysis Results Test Parameter Result UDM SR(STRONTIUM) 8.29 mg/I ICP METALS' ZN (ZINC) ZN(ZINC) 0.02 mg/1 5-2320 ALKALIN ITY • TOTAL BI CAR BO NATE(H003) 191.8 mg/I CARBONATE (CO3) 0.0 mg/I 5-2510 • CONDUCTIVITY CONDUCTIVITY 53800 uS/vn 5-2520SALINITY' SP GRAV S PE Cl FIC GRAVITY 1.0269 5-4500 PH (B)PH PH 7.12 S-4500 S2- (F) • SULFIDE BY TITR SULFIDE 1.8 mg/1 CPAI Application for Alpine Oil Pool Expansion Jan 2017 Page 16 FIGURE 6: ALPINE FACILITY PRODUCED WATER COMPOSITION KUPARUK LAB ANALYTICAL REPORT 907-659-7214 n1020@cop.com Sa mple Number. S-161011-00326 Sample Name: Alpine Flash Drum Location: Area: ALPINE Unit: ALPFAC Sample Point: A7PWFD Sampled Date: 10/7/2016 2:34:OOAM Matrix Id: WATER - PRODUCED Reviewed By: Carville, Daniele Date: 10/30/2016 Ana hs is Res ults .1= 2w=z R -,It Sd7l81 DIONER IC* ACETATE ACETATE 400.0 mg/I DIOND IC' BUTYRATE BUTYRATE <5.0 mg/I DIONEXIC' CHLORIDE CHLORIDE 14285.1 mg/1 DIONE%ICFORIVATE FORMATE 15.0 mg/I DIONEX IC • PROPIONATE PROPIONATE 29.7 mg/I DIONE%IC• SULFATE SO4(SULFATE) 407.0 mg/I ICP METALS • AL(ALUMI NUM) AL(ALUMINUM) 0.04 mg/I ICP METALS . B(BORON) B(BORON) 22.07 mg/I ICP METALS • B4 (BARIUM) BA(B4RIUM) 2.98 mg/1 ICP METALS' CA (CALCIUM) CA(CALCIUM) 164.33 mg/I ICA METALS ' OR (CHROMIUM) CR (CHROMIUM) 0.01 mg/I ICP METALS • FE (IRON) FE (IRON) 4.73 mg/I ICP METALS • K(POTASSIUM) K (POTASSIUM) 50.63 mg/I ICP METALS • U (LITHIUM) U (LITHIUM) 1.47 mg/I ICP METALS • MG (MAGNESIUM) MG (MAGNESIUM) 123.03 mg/I ICP METALS • MN (MANGANESE) MN (MANGANESE) 0.065 mg/I ICP METALS • NA GSODIUM) NA(SODIUM) 9388.43 mg/I ICP METALS • P(PHOSPHORUS) P (PHOSPHORUS) 3.32 mg/I ICP METALS • $I (SILICON) SI f$IUCON) 17.60 mg/I ICP METALS' SR (STRONTIUM) SR (STRONTIUM) 12.09 mg/1 ConocoPhillips CPAI Application for Alpine Oil Pool Expansion Jan 2017 Page 17 FIGURE 6: ALPINE FACILITY PRODUCED WATER COMPOSITION (CONTINUED) KUPARUK LAB ANALYTICAL REPORT 907-659-7214 n1020@cop.com Sample Number. S-161011-00326 Sample Name: Alpine Flash Drum Location: Area: ALPINE Unit: ALPFAC Sample Point: A7PWFD Sampled Date. 10/712016 2:34:00AM Matra Id: WATER - PRODUCED Reviev M BV. Carville, Daniele Date: 10/30/2016 Analysis Reseks: IQ� Ga ra roarer it ci ii I C]M ICP METALS • ZN 4ZINL� ZN (ZINC) 0.13 mg/I S-2320 ALKA U NrrY • TOTAL BICAR 80 NATE (HCO3) 1327.9 mg/I CARBa NATE(CO3) 0.0 mg/I 5-2510' CONDUCTIVITY CONDUCTIVITY 44100 uS/an S-2520 SALINITY • SP GRAV SPED FIC GRAVITY 1.0204 S-4500 PH (B) • PH PH 787 Sample Notes/Comments CPAI Application for Alpine Oil Pool Expansion Jan 2017 Page 18 FIGURE 7: ALPINE FACILITY GAS INJECTANT COMPOSITION (MOLE %) GPB LABORATORY REPORT 907-659-5654 AKOPSLablntertek@bp.com Sample Information Sample ID Number: PD22663 Sample Facility: Kl1PARUK Collection DatefTime: 133/11212016, 2:00 AM Sample Point: Mixing Manifold Sample Description: Produced Gas Sample Type: NATURAL GAS Well Number M-02 Results Analysis Name Resuft Units Carbon Dioxide (Normalized) 0.661 Mole% Line Temperature 147 deg F Methane (Normalized) 71.307 Mole% Ethane (Normalized) 10.774 Mole% Propane (Normalized) 13.211 Mole% i -Butane (Normalized) 1.070 Mole% n -Butane (Nommailzed) 1.762 Mole% i -Pentane (Normalized) 0.283 Mole% n -Pentane (Normalized) 0.242 Mole% C6 Group (Normalized) 0.097 Male% C7 Group (Normalized) 0.046 Mole% C8 Group (Normalized) 0.014 Mole% Line Pressure 4050 psig C6+ (Normalized) 0.160 Mole% Compressibility Factor 0.9956 Nitrogen (Normalized) 0.530 Mole% Oxygen Contamination <0.001 Male% Specific Gravity Ideal @ 14.696 psis 0.7982 Specific Gravity Real @ 14.696 psia 0.8015 BTU Gross Dry Ideal @ 14.696 Asia 1364.8 Btu/cf BTU Gross Dry Real @ 14.65 psia 1366.5 Btulcf BTU Gross Saturated Ideal @ 14.73 13442 Btulcf BTU Net Ideal @ 14.696 psia 1240.9 Btulcf Molecular Weight (calculated) 23.11 BTU Gross Saturated Real @ 14.65 1338.4 Btulcf Specific Gravity Real @ 14.65 psia 0.8014 C9 Group (Normalized) 0.003 Mole% Analyzed by: GLJMBE Sample Comment: CPAI Application for Alpine Oil Pool Expansion Jan 2017 Page 19 FIGURE 8e PLOT OF ALPINE POOL EXPANSION AREA WITH PENETRATIONS EXAMINED FOR FRESHWATER SOURCES 0 COvlle River Ulm N/, 9 1U �ii ALASKA I N 18 17 ^fir 16 7s T-11 3 R4E 21 22 COLVILLE RIVER UNIT H. �� 29 za 27 26 33 3`5 36 31 32 33 34 35 36 710KIR4 " ��a�� Conoco" ® Subject Wells with TDS =Alpine Oil Pool Expansion Alaska, Inc. Well Pad F—\7 Alpine Oil Pool Contraction Colville River Unit ••••• Planned Latera! ® Alpine Oil Pool Alpine Oil Pool Expansion �• Lateral Miles 0 0.5 1 2 3 6 5 4 3 2 7 6 4 3 2 1 11 12 7 8 9 1 11 12 7 8 9 10 11 12 14 13 18 17 it; 14 13 1fi 17 16 15 14 13 ry p� �y I' f 2NyR3 23 24 19 20 21 2$ 23 24 19 22 23 \\ 27 g20 y2 T12 26 25 30 29 23 27 26 2; 30 29 23 27 \ 34 35 36 31 32 33 34 35 36 31 32 33 34 35 3 2 1 6 3 2 j ';. _.a • NUIQSU f I 1 6 5 4 3 2 12 7 10 11 CD 8 9 10 21 11 12 7 s 9 10 11 \ 14 13 T11N 17 16 15 T11 RAE 14 13 18 17 16 T1 I N RE 15 23 ' 24 19 21 22 23 24 df . 19 20 21\ 25�0 30 Q 29 w 28 27 26 25 30 24 28 4if i Cw „ 315 e4 31 32 33 34 35 36 31 32 33 /f CL VERA 5 4 3 2 , 6� 710KIR4 " ��a�� Conoco" ® Subject Wells with TDS =Alpine Oil Pool Expansion Alaska, Inc. Well Pad F—\7 Alpine Oil Pool Contraction Colville River Unit ••••• Planned Latera! ® Alpine Oil Pool Alpine Oil Pool Expansion �• Lateral Miles 0 0.5 1 2 3 CPAI Application for Alpine Oil Pool Expansion Jan 2017 Page 20 FIGURE 9: CLOVER A FORMATION WATER SALINITY CLOVER A FORMATION WATER SALINITY _..... .. , StaUu;i. 1250 4�+ Soo 750 jt f 1 1000 7250 1500 ....... .. Base PeTnahos; F 1750 . 7000 2250 ss '' 2500 ca »s0 t i 3000 �. 3750 cse Casing shoe ty ii 3750 Cj 4000 4250 4500 4750 {1 0 5000 L 5250 CPAI Application for Alpine Oil Pool Expansion Jan 2017 Page 21 FIGURE 10: CDS-21 FORMATION WATER SALINITY 1951 250 soo 750 ,1Do0 1250 CPAI Application for Alpine Oil Pool Expansion Jan 2017 Page 22 NUIQSUT I FORMATION WATER SALINITY ItMG m 0 0 750 I 9_7 1250 1500 2000 CasingSoo Shoe 2250 2750 3000 32. 3500 3750 TT rO EM _ 1 9 loss m umwmyj� ■mmmm OMEN - i ®I ��7�..--_ -_-------- Confidential pages 23 — 27 held in secure storage