The URL can be used to link to this page

Home My WebLink AboutCO 443 CCONSERVATION ORDER 443C Docket Number: CO -17-004 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. February 28, 2018 CPA Request for Administrative Amendment, CRU 6. February 28, 2018 CPA Request to Amend Allowable Gas Offtake Rate, CRU (C0443C.001) ORDERS STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West Seventh Avenue Anchorage, Alaska 99501 Re: THE APPLICATION OF ConocoPhillips ) Conservation Order No. 443C (Errata) Alaska, Inc. for expansion and contraction of ) Docket Number: CO -17-004 the Alpine Oil Pool and the elimination of Rule ) 5 in the existing pool rules, Colville River Unit, ) Colville River Field Arctic Slope, Alaska ) Colville River Unit ) Alpine Oil Pool June 15, 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 acreage of the Alpine Oil Pool (AOP) in the Colville River Unit (CRU). CPAI also requests removal of Rule 5 of Conservation Order No. (CO) 443B, which addresses safety valves. 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 CRU and all lands affected by this order. 2. The areal and vertical extent of the AOP in the CRU was initially defined on March 15, 1999, by the issuance of CO 443. The areal and vertical extent of the AOP has since been modified, most recently on March 26, 2009, by the CO 443B. 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 of the AOP. BLM is the landowner of the acreage proposed to be added to the pool. 4. Ongoing development of the CD5 drillsite in the CRU indicates that the productive area of the AOP likely extends beyond the western boundary of the current pool boundaries. 5. During an in camera session during the hearing, seismic and geologic data showed that the AOP appears to extend beyond the current boundaries and into the proposed expansion acreage. CO 443C (Errata) June 15, 2017 Page 2 of 6 6. CPAI plans to drill an additional development well in the proposed expanded AOP which would be outside the affected acreage of the current AOP. 7. Portions of the current pool definition along the eastern portion of the pool boundary do not appear to be contributing to production and are on acreage that is beyond the current CRU boundary. 8. The AOGCC adopted new statewide regulations pertaining to safety valves on October 13, 2010. 9. On January 11, 2011, the AOGCC issued Other Order No. 66, which reviewed the existing pool rules pertaining to safety valves versus the newly adopted regulations to determine whether or not those rules had been superseded by the regulations, or if the rule was still necessary or needed to be modified in any way. 10. Other Order No. 66 concluded that Rule 5 of CO 443B was not superseded by the new regulations but modified Rule 5 of CO 443B to read "Injection wells (excluding disposal injectors) must be equipped with (i) a double check valve arrangement or (ii) a single check valve and a surface safety valve (SSV). A subsurface -controlled injection valve or surface - controlled subsurface safety valve (SCSSV) satisfies the requirements of a single check valve." 11. During the hearing CPAI requested revision of Rule 5 in CO 443B to be consistent with the changes by Other Order No. 66. CONCLUSIONS: 1. Amending CO 443B to expand the geographic boundaries of the AOP is consistent with the provisions of AS 31.05. Accordingly, the AOP expansion will not promote waste, jeopardize correlative rights, or compromise ultimate recovery and is based on sound engineering principles. 2. Amending CO 443B to contract the eastern geographic boundaries of the AOP to exclude the acreage that does not contribute to pool production is consistent with the provisions of AS 31.05. 3. NOW, THEREFORE, IT IS ORDERED: This Conservation Order supersedes CO 44313, issued March 6, 2009. The findings, conclusions, and administrative records for CO 443B are adopted by reference and incorporated in this decision, except where inconsistent with this Conservation Order. The following rules, in addition to any other requirements (including the statewide regulatory requirements ) that are not superseded by these rules, apply to the Alpine Oil Pool within the following affected area: Umiat Meridian Township Range Sections T10N R3E 1-3: All T l ON R4E 1-6: All TION R5E 5: N1/2NW1/4, SW1/4NWI/4, & NW1/4SW1/4 6: All TI IN R3E 1-2: All 11-14: All 22-27: All 34-36: All CO 443C (Errata) June 15, 2017 Page 3 of 6 TI 1N R4E 1-36: All T11N 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 Field and Pool Name (Source: CO 443A) The field is the Colville River Field. The pool is the Alpine Oil Pool (AOP). Rule 2 Pool Definition (Source: CO 443B) The AOP is defined 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. Rule 3 Well Spacing (Source: CO 443B) Development wells may not be completed closer than 500 feet to an external property line where ownership or land ownership changes. Rule 4 Drilling and Completion Practices (Source: CO 443) a. After drilling no more than 50 feet below a casing shoe set in the AOP, a formation integrity test must be conducted. The test pressure need not exceed a predetermined pressure. b. Casing and completion designs may be approved by the Commission upon application and presentation of data that demonstrate the designs are appropriate and based upon sound engineering principles. c. Permit(s) to Drill deviated wells within the AOP shall include a plat with a plan view, vertical section, close approach data and a directional program description in lieu of the requirements of 20 AAC 25.050(b). d. A complete petrophysical log suite acceptable to the Commission is required from below the conductor to TD for at least one well on each drilling pad in lieu of the requirements of 20 AAC 25.071(a). The Commission may, in its discretion, require additional wells on a pad to be logged using a complete petrophysical log suite. Rule 5 Well Safety Valve Systems (Source: Other Order No. 66) Injection wells (excluding disposal injectors) must be equipped with; a. a double check valve arrangement, or CO 443C (Errata) June 15, 2017 Page 4 of 6 b. a single check valve and a SSV. A subsurface -controlled injection valve or SCSSV satisfies the requirements of a single check valve. Rule 6 Reservoir Pressure Monitoring (Source: CO 443) a. Prior to regular injection, an initial pressure survey shall be taken in each injection well. b. A minimum of six bottom -hole pressure surveys shall be measured annually. Bottom -hole pressure surveys in paragraph (a) may fulfill the minimum requirement. c. The reservoir pressure datum shall be 7,000 feet TVD subsea. d. Pressure surveys may consist of stabilized static pressure measurements at bottom -hole or extrapolated from surface, pressure fall-off, pressure buildup, multi -rate tests, drill stem tests, and open -hole formation tests. e. Data and results from pressure surveys shall be reported annually on Form 10-412, Reservoir Pressure Report. All data necessary for analysis of each survey need not be submitted with the Form 10-412 but shall be made available to the Commission upon request. f. Results and data from special reservoir pressure monitoring tests or surveys shall also be submitted in accordance with part (e) of this rule. Rule 7 Gas -Oil Ratio Exemption (Revised this order to correct regulatory cites) Wells producing from the AOP are exempt from the gas -oil -ratio limits of 20 AAC 25.240(a) so long as the provisions of 20 AAC 25.240(b) apply. Rule 8 Reservoir Surveillance Report (Source: CO 443) A surveillance report is required after one year of regular production and annually thereafter. The report shall include but is not limited to the following: a. Progress of enhanced recovery project(s) implementation and reservoir management summary including engineering and geotechnical parameters. b. Voidage balance by month of produced fluids and injected fluids. c. Analysis of reservoir pressure surveys within the pool. d. Results and where appropriate, analysis of production log surveys, tracer surveys, and observation well surveys. e. Future development plans Rule 9 Well Testing (Source: CO 443) a. All wells must be tested at least twice per month. b. The operator shall optimize stabilization and test duration of each test to obtain a representative test. c. The operator shall record well and field -operating conditions appropriate for maintaining an accurate field production history. d. The operator shall install and maintain test separator meters and gas system meters in conformance with the API Manual of Petroleum Measurement Standards. e. The operator shall maintain records to allow verification of approved production allocation methodologies. CO 443C (Errata) June 15, 2017 Page 5 of 6 Rule 10 Sustained Casine Pressure (Source: CO 443A) a. The operator shall conduct and document a pressure test of tubulars and completion equipment in each development well at the time of installation or replacement that is sufficient to demonstrate that planned well operations will not result in failure of well integrity, uncontrolled release of fluid or pressure, or threat to human safety. b. The operator shall monitor each development well daily to check for sustained pressure, except if prevented by extreme weather conditions, emergency situations, or similar unavoidable circumstances. Monitoring results shall be made available for AOGCC inspection. c. The operator shall notify the AOGCC within three working days after the operator identifies a well as having (a) sustained inner annulus pressure that exceeds 2000 psig or (b) sustained outer annulus pressure that exceeds 1000 psig. d. The AOGCC may require the operator to submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action or increased surveillance for any development well having sustained pressure that exceeds a limit set out in paragraph c of this rule. The AOGCC may approve the operator's proposal or may require other corrective action or surveillance. The AOGCC may require that corrective action be verified by mechanical integrity testing or other AOGCC approved diagnostic tests. The operator shall give AOGCC sufficient notice of the testing schedule to allow AOGCC to witness the tests. e. If the operator identifies sustained pressure in the inner annulus of a development well that exceeds 45% of the burst pressure rating of the well's production casing for inner annulus pressure, or sustained pressure in the outer annulus that exceeds 45% of the burst pressure rating of the well's surface casing for outer annulus pressure, the operator shall notify the AOGCC within three working days and take corrective action. Unless well conditions require the operator to take emergency corrective action before AOGCC approval can be obtained, the operator shall submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action. The AOGCC may approve the operator's proposal or may require other corrective action. The AOGCC may also require that corrective action be verified by mechanical integrity testing or other AOGCC approved diagnostic tests. The operator shall give AOGCC sufficient notice of the testing schedule to allow AOGCC to witness the tests. f. Except as otherwise approved by the AOGCC under paragraph d or e of these rules, before a shut-in well is placed in service, any annulus pressure must be relieved to a sufficient degree (a) that the inner annulus pressure at operating temperature will be below 2000 psig and (b) that the outer annulus pressure at operating temperature will be below 1000 psig. However, a well that is subject to paragraph 3 but not paragraph 5 of these rules may reach an annulus pressure at operating temperature that is described in the operator's notification to the AOGCC under paragraph 3, unless the AOGCC prescribes a different limit. g. For purposes of these rules, "inner annulus" means the space in a well between tubing and production casing; "outer annulus" means the space in a well between production casing and surface casing; "sustained pressure" means pressure that (a) is measurable at the casing head of an annulus, (b) is not caused solely by temperature fluctuations, and (c) is not pressure that has been applied intentionally. Rule 11 Administrative Action (Revised this order) CO 443C (Errata) June 15, 2017 Page 6 of 6 Upon proper application or its own motion, unless notice and a public hearing are otherwise required the Commission may administratively waive the requirements of any rule stated above or administratively amend this order as long as the change does not promote waste, jeopardize correlative rights, or compromise ultimate recovery and is based on sound engineering principles. Rule 12 Gas Offtake Rate (Source: CO 443A.003) a. The cumulative gas off take rate from the Colville River Field (CRF) must not exceed 1 MMCFPD. Q C. Natural gas may not be severed from the CRF for any other purpose than to meet ConocoPhillips' contractual obligations of providing the Village of Nuiqsut with natural gas. Any new pools that process production at the Alpine Central Facility will be subject to the terms of this rule. t ,4i orag , Alaska and dated June 27, 2017, nunc p �unc June 15, 2017. Cathy . Foerster an I. SSeamunt, Jr. o Is nch Chai , 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 tiled 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. ATO -1770 700 G St. Anchorage, AK 99501 OZNIK%�� C¢-3c-,-2c>\� 0 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 Alpine Oil Pool and the elimination of Rule 5 in the existing pool rules, Colville River Unit, Arctic Slope, Alaska IT APPEARING THAT: Conservation Order No. 443C (Errata) Docket Number: CO -17-004 Colville River Field Colville River Unit Alpine Oil Pool June 15, 2017 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 acreage of the Alpine Oil Pool (AOP) in the Colville River Unit (CRU). CPAI also requests removal of Rule 5 of Conservation Order No. (CO) 443B, which addresses safety valves. 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 CRU and all lands affected by this order. 2. The areal and vertical extent of the AOP in the CRU was initially defined on March 15, 1999, by the issuance of CO 443. The areal and vertical extent of the AOP has since been modified, most recently on March 26, 2009, by the CO 443B. 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 of the AOP. BLM is the landowner of the acreage proposed to be added to the pool. 4. Ongoing development of the CD5 drillsite in the CRU indicates that the productive area of the AOP likely extends beyond the western boundary of the current pool boundaries. 5. During an in camera session during the hearing, seismic and geologic data showed that the AOP appears to extend beyond the current boundaries and into the proposed expansion acreage. CO 443C (Errata) June 15, 2017 Page 2 of 6 6. CPAI plans to drill an additional development well in the proposed expanded AOP which would be outside the affected acreage of the current AOP. 7. Portions of the current pool definition along the eastern portion of the pool boundary do not appear to be contributing to production and are on acreage that is beyond the current CRU boundary. 8. The AOGCC adopted new statewide regulations pertaining to safety valves on October 13, 2010. 9. On January 11, 2011, the AOGCC issued Other Order No. 66, which reviewed the existing pool rules pertaining to safety valves versus the newly adopted regulations to determine whether or not those rules had been superseded by the regulations, or if the rule was still necessary or needed to be modified in any way. 10. Other Order No. 66 concluded that Rule 5 of CO 443B was not superseded by the new regulations but modified Rule 5 of CO 443B to read "Injection wells (excluding disposal injectors) must be equipped with (i) a double check valve arrangement or (ii) a single check valve and a surface safety valve (SSV). A subsurface -controlled injection valve or surface - controlled subsurface safety valve (SCSSV) satisfies the requirements of a single check valve." 11. During the hearing CPAI requested revision of Rule 5 in CO 443B to be consistent with the changes by Other Order No. 66. CONCLUSIONS: 1. Amending CO 443B to expand the geographic boundaries of the AOP is consistent with the provisions of AS 31.05. Accordingly, the AOP expansion will not promote waste, jeopardize correlative rights, or compromise ultimate recovery and is based on sound engineering principles. 2. Amending CO 443B to contract the eastern geographic boundaries of the AOP to exclude the acreage that does not contribute to pool production is consistent with the provisions of AS 31.05. 3. NOW, THEREFORE, IT IS ORDERED: This Conservation Order supersedes CO 44313, issued March 6, 2009. The findings, conclusions, and administrative records for CO 443B are adopted by reference and incorporated in this decision, except where inconsistent with this Conservation Order. The following rules, in addition to any other requirements (including the statewide regulatory requirements ) that are not superseded by these rules, apply to the Alpine Oil Pool within the following affected area: Umiat Meridian Township_Range Sections T10N R3E 1-3: All T l ON R4E 1-6: All T10N R5E 5: N1/2NW1/4, SWI/4NW1/4, & NW1/4SW1/4 6: All TI IN R3E 1-2: All 11-14: All 22-27: All 34-36: All CO 443C (Errata) June 15, 2017 Page 3 of 6 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, SW1/4, & W1/2SE1/4 27-35: All 36: SWI/4SW1/4 Rule 1 Field and Pool Name (Source: CO 443A) The field is the Colville River Field. The pool is the Alpine Oil Pool (AOP). Rule 2 Pool Definition (Source: CO 443B) The AOP is defined 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. Rule 3 Well Spacing (Source: CO 443B) Development wells may not be completed closer than 500 feet to an external property line where ownership or land ownership changes. Rule 4 Drilling and Completion Practices (Source: CO 443) a. After drilling no more than 50 feet below a casing shoe set in the AOP, a formation integrity test must be conducted. The test pressure need not exceed a predetermined pressure. b. Casing and completion designs may be approved by the Commission upon application and presentation of data that demonstrate the designs are appropriate and based upon sound engineering principles. c. Permit(s) to Drill deviated wells within the AOP shall include a plat with a plan view, vertical section, close approach data and a directional program description in lieu of the requirements of 20 AAC 25.050(b). d. A complete petrophysical log suite acceptable to the Commission is required from below the conductor to TD for at least one well on each drilling pad in lieu of the requirements of 20 AAC 25.071(a). The Commission may, in its discretion, require additional wells on a pad to be logged using a complete petrophysical log suite. Rule 5 Well Safety Valve Systems (Source: Other Order No. 66) Injection wells (excluding disposal injectors) must be equipped with; a. a double check valve arrangement, or CO 443C (Errata) June 15, 2017 Page 4 of 6 b. a single check valve and a SSV. A subsurface -controlled injection valve or SCSSV satisfies the requirements of a single check valve. Rule 6 Reservoir Pressure Monitoring (Source: CO 443) a. Prior to regular injection, an initial pressure survey shall be taken in each injection well. b. A minimum of six bottom -hole pressure surveys shall be measured annually. Bottom -hole pressure surveys in paragraph (a) may fulfill the minimum requirement. c. The reservoir pressure datum shall be 7,000 feet TVD subsea. d. Pressure surveys may consist of stabilized static pressure measurements at bottom -hole or extrapolated from surface, pressure fall-off, pressure buildup, multi -rate tests, drill stem tests, and open -hole formation tests. e. Data and results from pressure surveys shall be reported annually on Form 10-412, Reservoir Pressure Report. All data necessary for analysis of each survey need not be submitted with the Form 10-412 but shall be made available to the Commission upon request. f. Results and data from special reservoir pressure monitoring tests or surveys shall also be submitted in accordance with part (e) of this rule. Rule 7 Gas -Oil Ratio Exemption (Revised this order to correct regulatory cites) Wells producing from the AOP are exempt from the gas -oil -ratio limits of 20 AAC 25.240(a) so long as the provisions of 20 AAC 25.240(b) apply. Rule 8 Reservoir Surveillance Report (Source: CO 443) A surveillance report is required after one year of regular production and annually thereafter. The report shall include but is not limited to the following: a. Progress of enhanced recovery project(s) implementation and reservoir management summary including engineering and geotechnical parameters. b. Voidage balance by month of produced fluids and injected fluids. c. Analysis of reservoir pressure surveys within the pool. d. Results and where appropriate, analysis of production log surveys, tracer surveys, and observation well surveys. e. Future development plans Rule 9 Well Testing (Source: CO 443) a. All wells must be tested at least twice per month. b. The operator shall optimize stabilization and test duration of each test to obtain a representative test. c. The operator shall record well and field -operating conditions appropriate for maintaining an accurate field production history. d. The operator shall install and maintain test separator meters and gas system meters in conformance with the API Manual of Petroleum Measurement Standards. e. The operator shall maintain records to allow verification of approved production allocation methodologies. CO 443C (Errata) June 15, 2017 Page 5 of 6 Rule 10 Sustained Casing Pressure (Source: CO 443A) a. The operator shall conduct and document a pressure test of tubulars and completion equipment in each development well at the time of installation or replacement that is sufficient to demonstrate that planned well operations will not result in failure of well integrity, uncontrolled release of fluid or pressure, or threat to human safety. b. The operator shall monitor each development well daily to check for sustained pressure, except if prevented by extreme weather conditions, emergency situations, or similar unavoidable circumstances. Monitoring results shall be made available for AOGCC inspection. c. The operator shall notify the AOGCC within three working days after the operator identifies a well as having (a) sustained inner annulus pressure that exceeds 2000 psig or (b) sustained outer annulus pressure that exceeds 1000 prig. d. The AOGCC may require the operator to submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action or increased surveillance for any development well having sustained pressure that exceeds a limit set out in paragraph c of this rule. The AOGCC may approve the operator's proposal or may require other corrective action or surveillance. The AOGCC may require that corrective action be verified by mechanical integrity testing or other AOGCC approved diagnostic tests. The operator shall give AOGCC sufficient notice of the testing schedule to allow AOGCC to witness the tests. e. If the operator identifies sustained pressure in the inner annulus of a development well that exceeds 45% of the burst pressure rating of the well's production casing for inner annulus pressure, or sustained pressure in the outer annulus that exceeds 45% of the burst pressure rating of the well's surface casing for outer annulus pressure, the operator shall notify the AOGCC within three working days and take corrective action. Unless well conditions require the operator to take emergency corrective action before AOGCC approval can be obtained, the operator shall submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action. The AOGCC may approve the operator's proposal or may require other corrective action. The AOGCC may also require that corrective action be verified by mechanical integrity testing or other AOGCC approved diagnostic tests. The operator shall give AOGCC sufficient notice of the testing schedule to allow AOGCC to witness the tests. £ Except as otherwise approved by the AOGCC under paragraph d or e of these rules, before a shut-in well is placed in service, any annulus pressure must be relieved to a sufficient degree (a) that the inner annulus pressure at operating temperature will be below 2000 psig and (b) that the outer annulus pressure at operating temperature will be below 1000 psig. However, a well that is subject to paragraph 3 but not paragraph 5 of these rules may reach an annulus pressure at operating temperature that is described in the operator's notification to the AOGCC under paragraph 3, unless the AOGCC prescribes a different limit. g. For purposes of these rules, "inner annulus" means the space in a well between tubing and production casing; "outer annulus" means the space in a well between production casing and surface casing; "sustained pressure" means pressure that (a) is measurable at the casing head of an annulus, (b) is not caused solely by temperature fluctuations, and (c) is not pressure that has been applied intentionally. Rule 11 Administrative Action (Revised this order) CO 443C (Errata) June 15, 2017 Page 6 of 6 Upon proper application or its own motion, unless notice and a public hearing are otherwise required the Commission may administratively waive the requirements of any rule stated above or administratively amend this order as long as the change does not promote waste, jeopardize correlative rights, or compromise ultimate recovery and is based on sound engineering principles. Rule 12 Gas Offtake Rate (Source: CO 443A.003) a. The cumulative gas off take rate from the Colville River Field (CRF) must not exceed 1 MMCFPD. b. Natural gas may not be severed from the CRF for any other purpose than to meet ConocoPhillips' contractual obligations of providing the Village of Nuiqsut with natural gas. c. Any new pools that process production at the Alpine Central Facility will be subject to the terms of this rule. Done at Anchorage, Alaska and dated June 27, 2017, nunc pro tunc June 15, 2017. //signature on file// Cathy P. Foerster Chair, Commissioner //signature on file// Daniel T. Seamount, Jr Commissioner //signature on file// Hollis S. French 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. Bernie Karl K&K Recycling Inc. Gordon Severson Penny Vadla 3201 Westmar Cir. 399 W. Riverview Ave. P.O. Box 58055 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Fairbanks, AK 99711-0055 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 fy�leC� QMY 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, lames 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 0 (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. Co(onibie AOyCC SyecialAssistant Alaska Oi(and(jas Conservation Commission 333 West 7"' Avenue .Anchorage, Afaska Q. Office: 6907) 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 ) Conservation Order No. 443C Alaska, Inc. for expansion and contraction of ) Docket Number: CO -17-004 the Alpine Oil Pool and the elimination of Rule ) 5 in the existing pool rules, Colville River Unit, ) Colville River Field Arctic Slope, Alaska ) Colville River Unit Alpine Oil Pool June 15, 2017 IT APPEARING THAT: 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 acreage of the Alpine Oil Pool (AOP) in the Colville River Unit (CRU). CPAI also requests removal of Rule 5 of Conservation Order No. (CO) 443B, which addresses safety valves. 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 CRU and all lands affected by this order. 2. The areal and vertical extent of the AOP in the CRU was initially defined on March 15, 1999, by the issuance of CO 443. The areal and vertical extent of the AOP has since been modified, most recently on March 26, 2009, by the CO 443B. 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 of the AOP. BLM is the landowner of the acreage proposed to be added to the pool. 4. Ongoing development of the CD5 drillsite in the CRU indicates that the productive area of the AOP likely extends beyond the western boundary of the current pool boundaries. CO 443c June 15, 2017 Page 2 of 6 5. During an in camera session during the hearing, seismic and geologic data showed that the AOP appears to extend beyond the current boundaries and into the proposed expansion acreage. 6. CPAI plans to drill an additional development well in the proposed expanded AOP which would be outside the affected acreage of the current AOP. 7. Portions of the current pool definition along the eastern portion of the pool boundary do not appear to be contributing to production and are on acreage that is beyond the current CRU boundary. 8. The AOGCC adopted new statewide regulations pertaining to safety valves on October 13, 2010. 9. On January 11, 2011, the AOGCC issued Other Order No. 66, which reviewed the existing pool rules pertaining to safety valves versus the newly adopted regulations to determine whether or not those rules had been superseded by the regulations, or if the rule was still necessary or needed to be modified in any way. 10. Other Order No. 66 concluded that Rule 5 of CO 443B was not superseded by the new regulations but modified Rule 5 of CO 443B to read "Injection wells (excluding disposal injectors) must be equipped with (i) a double check valve arrangement or (ii) a single check valve and a surface safety valve (SSV). A subsurface -controlled injection valve or surface - controlled subsurface safety valve (SCSSV) satisfies the requirements of a single check valve." 11. During the hearing CPAI requested revision of Rule 5 in CO 443B to be consistent with the changes by Other Order No. 66. CONCLUSIONS: 1. Amending CO 443B to expand the geographic boundaries of the AOP is consistent with the provisions of AS 31.05. Accordingly, the AOP expansion will not promote waste, jeopardize correlative rights, or compromise ultimate recovery and is based on sound engineering principles. 2. Amending CO 443B to contract the eastern geographic boundaries of the AOP to exclude the acreage that does not contribute to pool production is consistent with the provisions of AS 31.05. 3. NOW, THEREFORE, IT IS ORDERED: This Conservation Order supersedes CO 44313, issued March 6, 2009. The findings, conclusions, and administrative records for CO 443B are adopted by reference and incorporated in this decision, except where inconsistent with this Conservation Order. The following rules, in addition to any other requirements (including the statewide regulatory requirements ) that are not superseded by these rules, apply to the Alpine Oil Pool within the following affected area: Umiat Meridian Township Range Sections T10N R3E 1-3: All TION R4E 1-6: All CO 443c June 15, 2017 Page 3 of 6 TION R5E 5: N1/2NW1/4, SW1/4NW1/4, & NW1/4SW1/4 6: All Tl 1N R3E 1-2: All 11-14: All 22-17: 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, 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: SW1/4SW1/4 Rule 1 Field and Pool Name (Source: CO 443A) The field is the Colville River Field. The pool is the Alpine Oil Pool (AOP) Rule 2 Pool Definition (Source: CO 443B) The AOP is defined 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. Rule 3 Well Spacing (Source: CO 443B) Development wells may not be completed closer than 500 feet to an external property line where ownership or land ownership changes. Rule 4 Drilling and Completion Practices (Source: CO 443) a. After drilling no more than 50 feet below a casing shoe set in the AOP, a formation integrity test must be conducted. The test pressure need not exceed a predetermined pressure. b. Casing and completion designs may be approved by the Commission upon application and presentation of data that demonstrate the designs are appropriate and based upon sound engineering principles. c. Permit(s) to Drill deviated wells within the AOP shall include a plat with a plan view, vertical section, close approach data and a directional program description in lieu of the requirements of 20 AAC 25.050(b). d. A complete petrophysical log suite acceptable to the Commission is required from below the conductor to TD for at least one well on each drilling pad in lieu of the requirements of 20 CO 443c June 15, 2017 Page 4 of 6 AAC 25.071(a). The Commission may, in its discretion, require additional wells on a pad to be logged using a complete petrophysical log suite. Rule 5 Well Safety Valve Systems (Source: Other Order No. 66) Injection wells (excluding disposal injectors) must be equipped with; a. a double check valve arrangement, or b. a single check valve and a SSV. A subsurface -controlled injection valve or SCSSV satisfies the requirements of a single check valve. Rule 6 Reservoir Pressure Monitorinlj (Source: CO 443) a. Prior to regular injection, an initial pressure survey shall be taken in each injection well. b. A minimum of six bottom -hole pressure surveys shall be measured annually. Bottom -hole pressure surveys in paragraph (a) may fulfill the minimum requirement. c. The reservoir pressure datum shall be 7,000 feet TVD subsea. d. Pressure surveys may consist of stabilized static pressure measurements at bottom -hole or extrapolated from surface, pressure fall-off, pressure buildup, multi -rate tests, drill stem tests, and open -hole formation tests. e. Data and results from pressure surveys shall be reported annually on Form 10-412, Reservoir Pressure Report. All data necessary for analysis of each survey need not be submitted with the Form 10-412 but shall be made available to the Commission upon request. f. Results and data from special reservoir pressure monitoring tests or surveys shall also be submitted in accordance with part (e) of this rule. Rule 7 Gas -Oil Ratio Exemption (Revised this order to correct regulatory cites) Wells producing from the AOP are exempt from the gas -oil -ratio limits of 20 AAC 25.240(a) so long as the provisions of 20 AAC 25.240(b) apply. Rule 8 Reservoir Surveillance Report (Source: CO 443) A surveillance report is required after one year of regular production and annually thereafter. The report shall include but is not limited to the following: a. Progress of enhanced recovery project(s) implementation and reservoir management summary including engineering and geotechnical parameters. b. Voidage balance by month of produced fluids and injected fluids. c. Analysis of reservoir pressure surveys within the pool. d. Results and where appropriate, analysis of production log surveys, tracer surveys, and observation well surveys. e. Future development plans Rule 9 Well Testing (Source: CO 443) a. All wells must be tested at least twice per month. CO 443c June 15, 2017 Page 5 of 6 b. The operator shall optimize stabilization and test duration of each test to obtain a representative test. c. The operator shall record well and field -operating conditions appropriate for maintaining an accurate field production history. d. The operator shall install and maintain test separator meters and gas system meters in conformance with the API Manual of Petroleum Measurement Standards. e. The operator shall maintain records to allow verification of approved production allocation methodologies. Rule 10 Sustained Casing Pressure (Source: CO 443A) a. The operator shall conduct and document a pressure test of tubulars and completion equipment in each development well at the time of installation or replacement that is sufficient to demonstrate that planned well operations will not result in failure of well integrity, uncontrolled release of fluid or pressure, or threat to human safety. b. The operator shall monitor each development well daily to check for sustained pressure, except if prevented by extreme weather conditions, emergency situations, or similar unavoidable circumstances. Monitoring results shall be made available for AOGCC inspection. c. The operator shall notify the AOGCC within three working days after the operator identifies a well as having (a) sustained inner annulus pressure that exceeds 2000 psig or (b) sustained outer annulus pressure that exceeds 1000 prig. d. The AOGCC may require the operator to submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action or increased surveillance for any development well having sustained pressure that exceeds a limit set out in paragraph c of this rule. The AOGCC may approve the operator's proposal or may require other corrective action or surveillance. The AOGCC may require that corrective action be verified by mechanical integrity testing or other AOGCC approved diagnostic tests. The operator shall give AOGCC sufficient notice of the testing schedule to allow AOGCC to witness the tests. e. If the operator identifies sustained pressure in the inner annulus of a development well that exceeds 45% of the burst pressure rating of the well's production casing for inner annulus pressure, or sustained pressure in the outer annulus that exceeds 45% of the burst pressure rating of the well's surface casing for outer annulus pressure, the operator shall notify the AOGCC within three working days and take corrective action. Unless well conditions require the operator to take emergency corrective action before AOGCC approval can be obtained, the operator shall submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action. The AOGCC may approve the operator's proposal or may require other corrective action. The AOGCC may also require that corrective action be verified by mechanical integrity testing or other AOGCC approved diagnostic tests. The operator shall give AOGCC sufficient notice of the testing schedule to allow AOGCC to witness the tests. f. Except as otherwise approved by the AOGCC under paragraph d or e of these rules, before a shut-in well is placed in service, any annulus pressure must be relieved to a sufficient degree (a) that the inner annulus pressure at operating temperature will be below 2000 psig and (b) that the outer annulus pressure at operating temperature will be below 1000 psig. However, a well that is subject to paragraph 3 but not paragraph 5 of these rules may reach an annulus pressure at operating temperature that is described in the operator's notification to the CO 443c June 15, 2017 Page 6 of 6 AOGCC under paragraph 3, unless the AOGCC prescribes a different limit. g. For purposes of these rules, "inner annulus" means the space in a well between tubing and production casing; "outer annulus" means the space in a well between production casing and surface casing; "sustained pressure" means pressure that (a) is measurable at the casing head of an annulus, (b) is not caused solely by temperature fluctuations, and (c) is not pressure that has been applied intentionally. Rule 11 Administrative Action (Revised this order) Upon proper application or its own motion, unless notice and a public hearing are otherwise required the Commission may administratively waive the requirements of any rule stated above or administratively amend this order as long as the change does not promote waste, jeopardize correlative rights, or compromise ultimate recovery and is based on sound engineering principles. Rule 12 Gas Offtake Rate (Source: CO 443A.003) a. The cumulative gas off take rate from the Colville River Field (CRF) must not exceed MMCFPD. 0 191 Natural gas may not be severed from the CRF for any other purpose than to meet ConocoPhillips' contractual obligations of providing the Village of Nuiqsut with natural gas. Any new pools that process production at the Alpine Central Facility will be subject to the terms of this rule. Done at Anchorage, Alaska and dated June 15, 2017. Cathy t. Foerster DanielT. S ount, Jr. llis F ch Chair, Commissioner Com ssioner 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 desigiated 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 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West Seventh Avenue Anchorage, Alaska 99501 Re: THE APPLICATION OF ConocoPhillips ) Conservation Order No. 443C Alaska, Inc. for expansion and contraction of ) Docket Number: CO -17-004 the Alpine Oil Pool and the elimination of Rule ) 5 in the existing pool rules, Colville River Unit, ) Colville River Field Arctic Slope, Alaska ) Colville River Unit ) Alpine Oil Pool June 15, 2017 IT APPEARING THAT: 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 acreage of the Alpine Oil Pool (AOP) in the Colville River Unit (CRU). CPAI also requests removal of Rule 5 of Conservation Order No. (CO) 443B, which addresses safety valves. 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 CRU and all lands affected by this order. 2. The areal and vertical extent of the AOP in the CRU was initially defined on March 15, 1999, by the issuance of CO 443. The areal and vertical extent of the AOP has since been modified, most recently on March 26, 2009, by the CO 443B. 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 of the AOP. BLM is the landowner of the acreage proposed to be added to the pool. 4. Ongoing development of the CD5 drillsite in the CRU indicates that the productive area of the AOP likely extends beyond the western boundary of the current pool boundaries. CO 443c June 15, 2017 Page 2 of 6 5. During an in camera session during the hearing, seismic and geologic data showed that the AOP appears to extend beyond the current boundaries and into the proposed expansion acreage. 6. CPAI plans to drill an additional development well in the proposed expanded AOP which would be outside the affected acreage of the current AOP. 7. Portions of the current pool definition along the eastern portion of the pool boundary do not appear to be contributing to production and are on acreage that is beyond the current CRU boundary. 8. The AOGCC adopted new statewide regulations pertaining to safety valves on October 13, 2010. 9. On January 11, 2011, the AOGCC issued Other Order No. 66, which reviewed the existing pool rules pertaining to safety valves versus the newly adopted regulations to determine whether or not those rules had been superseded by the regulations, or if the rule was still necessary or needed to be modified in any way. 10. Other Order No. 66 concluded that Rule 5 of CO 443B was not superseded by the new regulations but modified Rule 5 of CO 443B to read "Injection wells (excluding disposal injectors) must be equipped with (i) a double check valve arrangement or (ii) a single check valve and a surface safety valve (SSV). A subsurface -controlled injection valve or surface - controlled subsurface safety valve (SCSSV) satisfies the requirements of a single check valve." 11. During the hearing CPAI requested revision of Rule 5 in CO 443B to be consistent with the changes by Other Order No. 66. CONCLUSIONS: 1. Amending CO 443B to expand the geographic boundaries of the AOP is consistent with the provisions of AS 31.05. Accordingly, the AOP expansion will not promote waste, jeopardize correlative rights, or compromise ultimate recovery and is based on sound engineering principles. 2. Amending CO 443B to contract the eastern geographic boundaries of the AOP to exclude the acreage that does not contribute to pool production is consistent with the provisions of AS 31.05. 3. NOW, THEREFORE, IT IS ORDERED: This Conservation Order supersedes CO 44313, issued March 6, 2009. The findings, conclusions, and administrative records for CO 443B are adopted by reference and incorporated in this decision, except where inconsistent with this Conservation Order. The following rules, in addition to any other requirements (including the statewide regulatory requirements ) that are not superseded by these rules, apply to the Alpine Oil Pool within the following affected area: Umiat Meridian Township Range Sections TION R3E 1-3: All T10N R4E 1-6: All CO 443c June 15, 2017 Page 3 of 6 TION R5E 5: N1/2NW1/4, SWI/4NW1/4, & 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, SI/2NW1/4, SWI/4, & W1/2SE1/4 27-35: All 36: SW1/4SW1/4 Rule 1 Field and Pool Name (Source: CO 443A) The field is the Colville River Field. The pool is the Alpine Oil Pool (AOP) Rule 2 Pool Definition (Source: CO 443B) The AOP is defined 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. Rule 3 Well Spacing (Source: CO 443B) Development wells may not be completed closer than 500 feet to an external property line where ownership or land ownership changes. Rule 4 Drilling and Completion Practices (Source: CO 443) a. After drilling no more than 50 feet below a casing shoe set in the AOP, a formation integrity test must be conducted. The test pressure need not exceed a predetermined pressure. b. Casing and completion designs may be approved by the Commission upon application and presentation of data that demonstrate the designs are appropriate and based upon sound engineering principles. c. Permit(s) to Drill deviated wells within the AOP shall include a plat with a plan view, vertical section, close approach data and a directional program description in lieu of the requirements of 20 AAC 25.050(b). d. A complete petrophysical log suite acceptable to the Commission is required from below the conductor to TD for at least one well on each drilling pad in lieu of the requirements of 20 CO 443c June 15, 2017 Page 4 of 6 AAC 25.071(a). The Commission may, in its discretion, require additional wells on a pad to be logged using a complete petrophysical log suite. Rule 5 Well Safety Valve Systems (Source: Other Order No. 66) Injection wells (excluding disposal injectors) must be equipped with; a. a double check valve arrangement, or b. a single check valve and a SSV. A subsurface -controlled injection valve or SCSSV satisfies the requirements of a single check valve. Rule 6 Reservoir Pressure Monitoring (Source: CO 443) a. Prior to regular injection, an initial pressure survey shall be taken in each injection well. b. A minimum of six bottom -hole pressure surveys shall be measured annually. Bottom -hole pressure surveys in paragraph (a) may fulfill the minimum requirement. c. The reservoir pressure datum shall be 7,000 feet TVD subsea. d. Pressure surveys may consist of stabilized static pressure measurements at bottom -hole or extrapolated from surface, pressure fall-off, pressure buildup, multi -rate tests, drill stem tests, and open -hole formation tests. e. Data and results from pressure surveys shall be reported annually on Form 10-412, Reservoir Pressure Report. All data necessary for analysis of each survey need not be submitted with the Form 10-412 but shall be made available to the Commission upon request. f. Results and data from special reservoir pressure monitoring tests or surveys shall also be submitted in accordance with part (e) of this rule. Rule 7 Gas -Oil Ratio Exemption (Revised this order to correct regulatory cites) Wells producing from the AOP are exempt from the gas -oil -ratio limits of 20 AAC 25.240(a) so long as the provisions of 20 AAC 25.240(b) apply. Rule 8 Reservoir Surveillance Report (Source: CO 443) A surveillance report is required after one year of regular production and annually thereafter. The report shall include but is not limited to the following: a. Progress of enhanced recovery project(s) implementation and reservoir management summary including engineering and geotechnical parameters. b. Voidage balance by month of produced fluids and injected fluids. c. Analysis of reservoir pressure surveys within the pool. d. Results and where appropriate, analysis of production log surveys, tracer surveys, and observation well surveys. e. Future development plans Rule 9 Well Testing (Source: CO 443) a. All wells must be tested at least twice per month. CO 443c June 15, 2017 Page 5 of 6 b. The operator shall optimize stabilization and test duration of each test to obtain a representative test. c. The operator shall record well and field -operating conditions appropriate for maintaining an accurate field production history. d. The operator shall install and maintain test separator meters and gas system meters in conformance with the API Manual of Petroleum Measurement Standards. e. The operator shall maintain records to allow verification of approved production allocation methodologies. Rule 10 Sustained Casing Pressure (Source: CO 443A) a. The operator shall conduct and document a pressure test of tubulars and completion equipment in each development well at the time of installation or replacement that is sufficient to demonstrate that planned well operations will not result in failure of well integrity, uncontrolled release of fluid or pressure, or threat to human safety. b. The operator shall monitor each development well daily to check for sustained pressure, except if prevented by extreme weather conditions, emergency situations, or similar unavoidable circumstances. Monitoring results shall be made available for AOGCC inspection. c. The operator shall notify the AOGCC within three working days after the operator identifies a well as having (a) sustained inner annulus pressure that exceeds 2000 psig or (b) sustained outer annulus pressure that exceeds 1000 psig. d. The AOGCC may require the operator to submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action or increased surveillance for any development well having sustained pressure that exceeds a limit set out in paragraph c of this rule. The AOGCC may approve the operator's proposal or may require other corrective action or surveillance. The AOGCC may require that corrective action be verified by mechanical integrity testing or other AOGCC approved diagnostic tests. The operator shall give AOGCC sufficient notice of the testing schedule to allow AOGCC to witness the tests. e. If the operator identifies sustained pressure in the inner annulus of a development well that exceeds 45% of the burst pressure rating of the well's production casing for inner annulus pressure, or sustained pressure in the outer annulus that exceeds 45% of the burst pressure rating of the well's surface casing for outer annulus pressure, the operator shall notify the AOGCC within three working days and take corrective action. Unless well conditions require the operator to take emergency corrective action before AOGCC approval can be obtained, the operator shall submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action. The AOGCC may approve the operator's proposal or may require other corrective action. The AOGCC may also require that corrective action be verified by mechanical integrity testing or other AOGCC approved diagnostic tests. The operator shall give AOGCC sufficient notice of the testing schedule to allow AOGCC to witness the tests. f. Except as otherwise approved by the AOGCC under paragraph d or e of these rules, before a shut-in well is placed in service, any annulus pressure must be relieved to a sufficient degree (a) that the inner annulus pressure at operating temperature will be below 2000 psig and (b) that the outer annulus pressure at operating temperature will be below 1000 psig. However, a well that is subject to paragraph 3 but not paragraph 5 of these rules may reach an annulus pressure at operating temperature that is described in the operator's notification to the CO 443c June 15, 2017 Page 6 of 6 AOGCC under paragraph 3, unless the AOGCC prescribes a different limit. g. For purposes of these rules, "inner annulus" means the space in a well between tubing and production casing; "outer annulus" means the space in a well between production casing and surface casing; "sustained pressure" means pressure that (a) is measurable at the casing head of an annulus, (b) is not caused solely by temperature fluctuations, and (c) is not pressure that has been applied intentionally. Rule 11 Administrative Action (Revised this order) Upon proper application or its own motion, unless notice and a public hearing are otherwise required the Commission may administratively waive the requirements of any rule stated above or administratively amend this order as long as the change does not promote waste, jeopardize correlative rights, or compromise ultimate recovery and is based on sound engineering principles. Rule 12 Gas Offtake Rate (Source: CO 443A.003) a. The cumulative gas off take rate from the Colville River Field (CRF) must not exceed MMCFPD. b. Natural gas may not be severed from the CRF for any other purpose than to meet ConocoPhillips' contractual obligations of providing the Village of Nuiqsut with natural gas. c. Any new pools that process production at the Alpine Central Facility will be subject to the terms of this rule. Done at Anchorage, Alaska and dated June 15, 2017. //signature on file// Cathy P. Foerster Chair, Commissioner //signature on file// Daniel T. Seamount, Jr. Commissioner //signature on file// Hollis S. French 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 eventhe period runs until 5:00 p.m. on the next day that does not fall on a weekend orstate 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 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Thursday, June 15, 2017 2:35 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; AKDCWeIIIntegrityCoordinator, 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 Qarlington@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: CO 443C (CPA) Attachments: co443c.pdf Please see attached. Re: THE APPLICATION OF ConocoPhillips ) Conservation Order No. 443C Alaska, Inc. for expansion and contraction of ) Docket Number: CO -17-004 the Alpine Oil Pool and the elimination of Rule ) 5 in the existing pool rules, Colville River Unit, ) Colville River Field Arctic Slope, Alaska ) Colville River Unit Alpine Oil Pool June 15, 2017 Jody J. Colombie AOGCC Specia(Assistant ACaska OifandGas Conservation Commission 333 'Vest 7" Avenue Anchorage, ACaska 99501 Office: (907) 793-1221 Fax: (907) 276-7542 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jody Colombie at 907.793.1221 or iody.colombie@alaska.aov. y s .�... c 'F�`�:_t a _..r..;. i.''�t .,e`. Y'.rS sc,i _ x•, 'n. �1,: .�_'.Y. r. .. s, .. THE STATE 3MWI, NA, Nil 49 GOVERNOR ]SILL 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: Alaska ®Ill and Gas 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.claska.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. Cathyp. Foerster iel ount, Jr. Chair, Commissioner L Commissioner Hollis S. Frenc 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 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. o/ A T SKAx� Al-JAt 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. OILq�0 I \ill-.•�. //signature on file// //signature on file// //signature on file// Cathy P. Foerster Daniel T. Seamount, Jr. Hollis S. French Chair, Commissioner Commissioner Commissioner ON CO CO 443C (Errata) AIO 18D (Errata) June 27, 2017 Page 2 of 2 RECONSIDERATION AND APPEAL As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event 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 �sokeC� la-3v-2o�`� Singh, Angela K (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 1 (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, lames 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. Cotombie AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 'Nest 71h 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.aov. THE STATE Alaska Oil and Gas }ALASKA Conservation Commission GOVERNOR BILL WALKER ADMINISTRATIVE APPROVALS CONSERVATION ORDER NO. 443C.001 CONSERVATION ORDER NO. 562.005 CONSERVATION ORDER NO. 569.004 CONSERVATION ORDER NO. 605.003 Mr. Stephen Thatcher Manager, WMS Development North Slope Operations and Development ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.olaska.gov Re: Docket Number: CO -18-002 and AIO-18-014 Request for administrative approval to amend allowable gas offtake for the Colville River Field and authorize surface commingling of production from the Lookout Oil Pool with production from the Fiord and Qannik Oil Pools. Colville River Field Colville River Unit Alpine Oil Pool Nanuq Oil Pool Fiord Oil Pool Qannik Oil Pool Dear Mr. Thatcher: By letter dated February 28, 2018, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to amend the allowable gas offtake rate established for the Colville River Field (CRF) to increase the allowable rate from 1 MMSCFPD to 7 MMSCFPD to allow for development of the Lookout Oil Pool (LOP) in the Greater Moose's Tooth Unit (GMTU). By a different letter also dated February 28, 2018, CPAI requested administrative approval to amend the Common Production Facilities and Surface Commingling rules for the Fiord and Qannik Oil Pools to allow commingling production on the surface with production from the LOP.' ' The Alpine and Nanuq Oil Pools pool rules do not contain a rule that would preclude commingling those pools with the LOP. CO 443C.001, CO 562.005, CO 569.004, and CO 650.003 August 13, 2018 Page 2 of 4 In accordance with Rule 11 of Conservation Order No. (CO) 443C and Rule 12 of COs 562, 569, and 605, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request to increase the allowable gas offtake rate from the CRF. On February 13, 2007, the Alaska Oil and Gas Conservation Commission (AOGCC) authorized a 1 MMSCFPD gas offtake from the CRF for the sole purpose of meeting contractual obligations to ship gas from the CRF to the village of Nuiqsut. CPAI plans to begin production from the LOP in GMTU in late 2018 and has requested authority to ship gas from the CRF to the GMTU to support LOP development. The LOP is expected to routinely produce significant excess gas that will be shipped, along with the produced oil and water, to the Alpine Central Facility (ACF) where the gas will be returned to the LOP, used for lease operations within the CRF, or injected into the pools in the CRF for EOR purposes. However, prior to initial production the GMTU facilities may take gas from the CRF to pack production lines and/or heat facilities. Additionally, after production commences there may be periods when LOP development switches from water to gas injection when the gas needs of the LOP enhanced oil recovery project exceeds the volume of gas being produced from the LOP resulting in the LOP needing to purchase extra gas from the CRF. Over its life the LOP is expected to produce nearly 40 BCF more gas than it will need for lease usage and EOR injection. This excess gas will be used in the CRF for EOR injection projects in the CRF's oil pools. Because this excess gas from the LOP will be used for EOR purposes in the CRF, the net benefit in oil production from the CRF will far outweigh the temporary delay in recovery that would be associated with shipping gas from the CRF to the GMTU. The Fiord and Qannik Oil Pools are currently authorized to commingle production on the surface with production from other CRF oil pools. These rules need to be amended to allow the LOP production to be commingled as well. The LOP is an Alpine formation reservoir. As such, production from the LOP should be compatible with the CRF oil pools. The administrative action rules for the affected orders allow the AOGCC to amend an order administratively if the proposed action will not result in waste, will not jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in increased risk of fluid movement into freshwater. Waste is prevented because the long-term benefits of using the gas from the LOP for EOR purposes in the CRF far outweigh the short-term and largely negligible impacts of periodically shipping small volumes of gas from the CRF to the GMTU to support LOP development. Correlative rights are protected because all of the affected pools are within the Colville River Unit. Selling small volumes of gas from the CRF to the GMTU is based on sound engineering and geoscience practices because the sharing of production facilities and infrastructure will lessen environmental impacts and increase ultimate recovery through the sharing of expenses. Selling gas from one unit to another has no impacts on the risk of fluids moving into freshwater. CO 443C.001, CO 562.005, CO 569.004, and CO 650.003 August 13, 2018 Page 3 of 4 Now therefore it is ordered that Rule 12 of CO 443C and Rule 11 of CO 605 are amended to read as follows: Allowable Gas OffTake 1. The cumulative gas offtake rate from the CRF must not exceed 7 MMCFPD. 2. Natural gas may not be severed from the CRF for any other purpose than to meet ConocoPhillips' contractual obligations of providing the Village of Nuiqsut with natural gas and to support development of the Lookout Oil Pool in the Greater Moose's Tooth Unit. 3. Any new pools that process production at the ACF will be subject to the terms of this administrative approval. The conditions of approval in CO 562.001 and 569.001 are amended to read as follows: 1. The cumulative gas off take rate from the CRF must not exceed 7 MMCFPD. 2. Natural gas may not be severed from the CRF for any other purpose than to meet ConocoPhillips' contractual obligations of providing the Village of Nuiqsut with natural gas and to support development of the Lookout Oil Pool in the Greater Moose's Tooth Unit. 3. Any new pools that process production at the ACF will be subject to the terms of this administrative approval. Rule 6 of CO 569 is amended to read as follows: Rule 6 Common Production Facilities and Surface Commingline a. Production from the Fiord Oil Pool may be commingled with production from other CRU pools and the Lookout Oil Pool in surface facilities prior to custody transfer. b. Production shall be allocated to wells within the Fiord Oil Pool in accordance with the procedures described in Section 5.0 of ConocoPhillips' application dated November 22, 2005. c. Each producing well must be tested a minimum of twice per month. d. The Commission may require more frequent or longer tests if the allocation quality deteriorates. e. The operator shall retain electronic file(s) containing daily allocation data and daily test data for a minimum of five years. f. The operator shall provide the Commission with a well test and allocation review report in conjunction with an annual reservoir surveillance report. CO 443C.001, CO 562.005, CO 569.004, and CO 650.003 August 13, 2018 Page 4 of 4 And Rule 6 of CO 605 is amended to read as follows: Rule 6 Common Production Facilities and Surface Commineline a. Production from the Qannik Oil Pool and other CRU pools and the Lookout Oil Pool may be commingled in surface facilities prior to custody transfer. b. Production shall be allocated to wells within the Qannik Oil Pool in accordance with the procedures described in Section 6.0 of CPAI's application, dated April 3, 2008. c. Each producing well must be tested a minimum of twice per month. d. The Commission may require more frequent or longer testing if the allocation quality deteriorates. e. The operator shall retain electronic file(s) containing daily allocation data and daily test data for a minimum of five years. f The operator shall provide the Commission an annual well test and allocation review report in conjunction with the annual reservoir surveillance report required under Rule 9 (below). DONE at Anchorage, Alaska and dated August 13, 2018. p Hollis S. French Cath P. oersteDaniel T. Seamount, Jr. Chair, Commissioner Commissioner Commissioner AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which eventthe period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. THE STATE °fALAS- A GO\'ERNOI2 RILL 1\'ALKER Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVALS CONSERVATION ORDER NO. 443C.001 CONSERVATION ORDER NO. 562.005 CONSERVATION ORDER NO. 569.004 CONSERVATION ORDER NO. 605.003 Mr. Stephen Thatcher Manager, WMS Development North Slope Operations and Development ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510 Re: Docket Number: CO -18-002 and A10- 18-014 333 west Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 oogcc.oloska.gov Request for administrative, approval to amend allowable gas offtake for the Colville River Field and authorize surface commingling of production from the Lookout Oil Pool with production from the Fiord and Qannik Oil Pools. Colville River Field Colville River Unit Alpine Oil Pool Nanuq Oil Pool Fiord Oil Pool Qannik Oil Pool Dear Mr. Thatcher: By letter dated February 28, 2018, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to amend the allowable gas offtake rate established for the Colville River Field (CRF) to increase the allowable rate from 1 MMSCFPD to 7 MMSCFPD to allow for development of the Lookout Oil Pool (LOP) in the Greater Moose's Tooth Unit (GMTU). By a different letter also dated February 28, 2018, CPAI requested administrative approval to amend the Common Production Facilities and Surface Commingling rules for the Fiord and Qannik Oil Pools to allow commingling production on the surface with production from the LOP.' ' The Alpine and Nanuq Oil Pools pool rules do not contain a rule that would preclude commingling those pools with the LOP. CO 443C.001, CO 562.005, CO 569.004, and CO 650.003 August 13, 2018 Page 2 of 4 In accordance with Rule 11 of Conservation Order No. (CO) 443C and Rule 12 of COs 562, 569, and 605, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request to increase the allowable gas offtake rate from the CRF. On February 13, 2007, the Alaska Oil and Gas Conservation Commission (AOGCC) authorized a 1 MMSCFPD gas offtake from the CRF for the sole purpose of meeting contractual obligations to ship gas from the CRF to the village of Nuiqsut. CPAI plans to begin production from the LOP in GMTU in late 2018 and has requested authority to ship gas from the CRF to the GMTU to support LOP development. The LOP is expected to routinely produce significant excess gas that will be shipped, along with the produced oil and water, to the Alpine Central Facility (ACF) where the gas will be returned to the LOP, used for lease operations within the CRF, or injected into the pools in the CRF for EOR purposes. However, prior to initial production the GMTU facilities may take gas from the CRF to pack production lines and/or heat facilities. Additionally, after production commences there may be periods when LOP development switches from water to gas injection when the gas needs of the LOP enhanced oil recovery project exceeds the volume of gas being produced from the LOP resulting in the LOP needing to purchase extra gas from the CRF. Over its life the LOP is expected to produce nearly 40 BCF more gas than it will need for lease usage and EOR injection. This excess gas will be used in the CRF for EOR injection projects in the CRF's oil pools. Because this excess gas from the LOP will be used for EOR purposes in the CRF, the net benefit in oil production from the CRF will far outweigh the temporary delay in recovery that would be associated with shipping gas from the CRF to the GMTU. The Fiord and Qannik Oil Pools are currently authorized to commingle production on the surface with production from other CRF oil pools. These rules need to be amended to allow the LOP production to be commingled as well. The LOP is an Alpine formation reservoir. As such, production from the LOP should be compatible with the CRF oil pools. The administrative action rules for the affected orders allow the AOGCC to amend an order administratively if the proposed action will not result in waste, will not jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in increased risk of fluid movement into freshwater. Waste is prevented because the long-term benefits of using the gas from the LOP for EOR purposes in the CRF far outweigh the short-term and largely negligible impacts of periodically shipping small volumes of gas from the CRF to the GMTU to support LOP development. Correlative rights are protected because all of the affected pools are within the Colville River Unit. Selling small volumes of gas from the CRF to the GMTU is based on sound engineering and geoscience practices because the sharing of production facilities and infrastructure will lessen environmental impacts and increase ultimate recovery through the sharing of expenses. Selling gas from one unit to another has no impacts on the risk of fluids moving into freshwater. CO 443C.001, CO 562.005, CO 569.004, and CO 650.003 August 13, 2018 Page 3 of 4 Now therefore it is ordered that Rule 12 of CO 443C and Rule 11 of CO 605 are amended to read as follows: Allowable Gas OffTake 1. The cumulative gas offtake rate from the CRF must not exceed 7 MMCFPD. 2. Natural gas may not be severed from the CRF for any other purpose than to meet ConocoPhillips' contractual obligations of providing the Village of Nuiqsut with natural gas and to support development of the Lookout Oil Pool in the Greater Moose's Tooth Unit. 3. Any new pools that process production at the ACF will be subject to the terms of this administrative approval. The conditions of approval in CO 562.001 and 569.001 are amended to read as follows: 1. The cumulative gas off take rate from the CRF must not exceed 7 MMCFPD. 2. Natural gas may not be severed from the CRF for any other purpose than to meet ConocoPhillips' contractual obligations of providing the Village of Nuiqsut with natural gas and to support development of the Lookout Oil Pool in the Greater Moose's Tooth Unit. 3. Any new pools that process production at the ACF will be subject to the terms of this administrative approval. Rule 6 of CO 569 is amended to read as follows: Rule 6 Common Production Facilities and Surface Commingling a. Production from the Fiord Oil Pool may be commingled with production from other CRU pools and the Lookout Oil Pool in surface facilities prior to custody transfer. b. Production shall be allocated to wells within the Fiord Oil Pool in accordance with the procedures described in Section 5.0 of ConocoPhillips' application dated November 22, 2005. c. Each producing well must be tested a minimum of twice per month. d. The Commission may require more frequent or longer tests if the allocation quality deteriorates. e. The operator shall retain electronic file(s) containing daily allocation data and daily test data for a minimum of five years. f. The operator shall provide the Commission with a well test and allocation review report in conjunction with an annual reservoir surveillance report. CO 443C.001, CO 562.005, CO 569.004, and CO 650.003 August 13, 2018 Page 4 of 4 And Rule 6 of CO 605 is amended to read as follows: Rule 6 Common Production Facilities and Surface Comminelin¢ a. Production from the Qannik Oil Pool and other CRU pools and the Lookout Oil Pool may be commingled in surface facilities prior to custody transfer. b. Production shall be allocated to wells within the Qannik Oil Pool in accordance with the procedures described in Section 6.0 of CPAI's application, dated April 3, 2008. c. Each producing well must be tested a minimum of twice per month. d. The Commission may require more frequent or longer testing if the allocation quality deteriorates. e. The operator shall retain electronic file(s) containing daily allocation data and daily test data for a minimum of five years. f. The operator shall provide the Commission an annual well test and allocation review report in conjunction with the annual reservoir surveillance report required under Rule 9 (below). DONE at Anchorage, Alaska and dated August 13, 2018. //signature on file// //signature on file// //signature on file// Hollis S. French Cathy 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. Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Penny Vadla 399 W. Riverview Ave. Soldotna, AK 99669-7714 George Vaught, Jr. 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 INDEXES ConocoPhillips February 28, 2018 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 Hollis French, Chair MAR 01 7013 Alaska Oil and Gas Conservation Commission p /� 333 W. 7th Ave #100 A©GCC Anchorage, Alaska, 99501-3539 RE: Application to Amend Allowable Gas Offtake Rate, Colville River Unit, North Slope, AK Dear Commissioner French, ConocoPhillips Alaska, Inc. ("CPAI") as operator of the Colville River Unit ("CRU") and Greater Mooses Tooth Unit ("GMTU"), requests that the Alaska Oil and Gas Conservation Commission ("Commission") approve CPAI's application to amend the Allowable Gas Off Take Rate from the CRU to allow CRU gas to be transferred to the Greater Mooses Tooth Unit (GMTU). This application is being made concurrently with applications for GMTU Lookout Oil Pool applications for Conservation Orders and Area Injection Orders. Enclosed are two printed originals of this application for expanded gas offtake and a disc containing an electronic version of the application. Please contact John Cookson (265-6547) if you have questions or require additional information. Regards, YL Stephen Thatcher Manager, WNS Development North Slope Operations and Development Cc: Land Manager - Alaska, Anadarko E&P Onshore LLC Bruce W. Hunt, Petro -Hunt LLC Enclosures (3) Application to Amend CRU AGOTR February 28, 2018 Page 2 of 5 APPLICATION TO AMEND THE ALLOWABLE GAS OFF TAKE RATE COLVILLE RIVER UNIT Request for Expanded Offtake This application is submitted for approval by the Alaska Oil and Gas Conservation Commission ("Commission") to amend the Allowable Gas Off Take Rate ("AGOTR") for the Colville River Unit ("CRU") to provide gas to the Greater Mooses Tooth Unit Lookout Oil Pool ("GMTU"). The current AGOTR for all CRU participating areas is 1 MMCFPD, as set forth in Administrative Approval Nos.443A.003, 562.001, 563.001, 569.001, and CO 605. ConocoPhillips Alaska, Inc. ("CPAI") as operator of the CRU and GMTU, requests that the Commission amend the AGOTR from the CRU to a maximum of a monthly cumulative volume of 7 million standard cubic feet per day ("MMCFPD") to provide 1 MMCFPD to the Village of Nuiqsut and on an as needed basis up to 6 MMCFPD to the GMTU for intermittent operational needs. It is also requested that this AGOTR apply to all currently defined pools within the CRU and any future pools that commingle production at the Alpine Central Facility ("ACF"). Background The Commission has approved an AGOTR not to exceed 1 MMCFPD from the "Colville River Field" for the purposes of providing the Village of Nuiqsut with natural gas. See, e.g., Administrative Approval No. 443A.003. In addition, the AGOTR applies to any new pools that process production at the ACF. Id. The current pools processing production from the ACF are the Alpine Oil Pool (which includes the Kuparuk oil pool), Fiord Oil Pool, Nanuq Oil Pool and Qannik Oil Pool. As a frame of reference, CRU provided 0.4 MMCFPD to the Village of Nuiqsut during November 2017. Production from the CRU pools is commingled and processed at the ACF. All of the commingled gas is either consumed within the CRU for operational purposes, re -injected to enhance oil recovery from the CRU, or provided to the Village of Nuiqsut. Gas production from all CRU oil pools was 67.3 MMCFD during the month of November 2017. The GMTU will begin production into the ACF in late 2018 as described in the Lookout Oil Pool Conservation and Area Injection Order applications that are submitted concurrently with this application. GMTU gas production will be sent to ACF for processing. Gas needed for GMTU operations will be returned to GMTU, any excess GMTU gas after accounting for GMTU's share of fuel and flare will be injected into CRU participating areas. GMTU Requirement for Gas from the CRU Production from the GMTU is expected to generate significant excess gas. In most instances, the amount of GMTU Return Gas will be more than enough to provide for the gas requirements of the GMTU. CPAI estimates that approximately 38 BCF of gas beyond the gas needs of the GMTU will be produced and injected into CRU PAs as Outside Substance Gas. There will be months, however, when the GMTU will need gas beyond what it produces for its operations. Prior to GMTU production startup, GMTU may require CRU native gas to pack production lines and heat facilities. This initial start-up gas will be purchased from the Colville River Unit, and will not exceed the offtake limit being requested in this application. Once operations begin, GMTU will typically provide more gas to CRU than it needs in return, and there will be no need for CRU gas at GMTU. However, during cycles when GMTU injection wells are converted from water injection to enriched gas injection, it is expected that GMTU gas requirements may periodically be greater than the available GMTU gas production. Consequently, CRU gas will be Application to Amend CRU AGOTR February 28, 2018 Page 3 of 5 necessary on these occasions for GMTU operations. Figure 1 shows a forecast of periods after start-up when CRU gas may be needed for operations at GMTU. This forecast indicates a peak requirement of approximately 6 MMCFD of CRU gas. Other than at startup, GMTU will likely not require significant amounts of gas from CRU until 2021. The forecasted cumulative CRU gas needed for GMTU operations is 11,000 MMCF. Figure 2 shows the net cumulative excess GMTU gas injected into CRU. Overall, it is forecasted that GMTU will inject a net 38,000 MMCF of gas into the CRU as Outside Substances Gas. Once GMTU production begins, there is never a negative net cumulative balance of GMTU gas that is injected into the CRU. Figure 3 shows the results of a simulation of the benefit of gas injection on oil recovery and is further described in the Lookout oil pool Area Injection Order application. In general, the oil benefit of gas injection is greatest for reservoirs that have received less gas injection and there is a continued but lesser oil benefit out to very high volumes of gas injection. This oil benefit of gas injection will apply to both GMTU and CRU oil pools. Justification for Expanded Offtake The justification for increasing the AGOTR to a monthly cumulative volume of 7 MMCFD is as follows: 1) The increased offtake will provide for a monthly cumulative volume of 1 MMCFD in sales to the Village of Nuiqsut and a monthly cumulative volume of 6 MMCFD on an as needed basis to the GMTU. 2) CRU gas will be needed by the GMTU intermittently for operational purposes to maximize efficient oil recovery from the GMTU. 3) CRU oil recovery will benefit from the net increased gas injection that GMTU production provides. Application to Amend CRU AGOTR February 28, 2018 Page 4 of 5 6 5 4 D W U 3 2 1 0 Jan -18 Jan -23 Jan -28 Jan -33 1an38 Jaa43 Figure 1. Forecasted Gas Sales from CRU to GMTU 45,000 40,000 35,000 30,000 U 25.000 g 20,000 15,000 10,000 5,000 Jan -18 lan-23 Jan -28 1an33 Jan -38 Figure 2. Cumulative Net GMTU Gas Injection into CRU Jan -43 Application to Amend CRU AGOTR February 28, 2018 Page 5 of 5 90 Fri] 70 0 ami 60 0 d 50 O v 40 at m E 30 U) 20 Assumed Condrt m Pressure = 3750 psi* 10 i Temperature =1g7° F Current Injectant MW : 213lb/lb•mol 0 20 40 60 $o 100 Pore Volumes of Gas Injected, % PV Current ACF Injectant Lean Gas 120 140 160 -+-Lean Gas- Current Cempnsdionai Blend -+--0: Erriching Fluid-- 151K. Enriching Fluid- 20'.4 Enriching Fluid Figure 3. Simulated Oil Benefit of Gas Injection 5 ConocoPhilli s February 28, 2018 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 Hollis French, Chair MAR ft f 2DIS Alaska Oil and Gas Conservation Commission 333 W. 7th Ave #100 �� C Anchorage, Alaska, 99501-3539 RE: Request for Administrative Amendments, Colville River Unit, North Slope, AK Dear Commissioner French, ConocoPhillips Alaska, Inc. ("CPAP') as operator of the Colville River Unit ("CRU") and Greater Mooses Tooth Unit ("GMTU"), requests that the Alaska Oil and Gas Conservation Commission administratively amend area injection orders for the Fiord, Nanuq, and Qannik oil pools to allow injection of GMTU Lookout Oil Pool ("LOP") produced water into any of the other CRU oil pools. CPAI also requests that the conservation orders for the Fiord and Qannik oil pools be amended to allow commingling of LOP production in surface facilities prior to custody transfer. This request is being made concurrently with applications for a LOP Conservation Order and Area Injection Order. Those applications provide further background for this request. The CO application explains that LOP production is expected to be compatible with production from the CRU oil pools. The Fiord, Nanuq and Qannik pools area injection orders have specific rules for "fluids authorized for injection." LOP produced water is not specifically listed as a fluid authorized for injection. The recent Commission order authorizing the expansion of the Alpine Pool Area Injection Order provides that "[p]roduced water from the Alpine Central Facility" is a fluid authorized for injection. See Area Injection Order No. 18D, Rule 1 b. CPAI requests that the Alpine pool language be used to amend the Fiord, Nanuq and Qannik area injection orders to allow for injection of any produced water from the Alpine Central Facility including LOP produced water injection. This amendment will provide for consistency in CRU oil pool area injection orders. CPA[ also requests that the Fiord, Alpine and Qannik pool rules be amended to allow for the commingling of LOP production in CRU surface facilities prior to custody transfer. The Nanuq oil pool rules allow production to be "commingled with production from other pools in surface facilities prior to custody transfer." See Conservation Order 562, Rule 7a. CPAI requests that similar language be adopted for the Fiord, Alpine and Qannik pools to allow for the commingling of production from these oil pools with other production at the Alpine Central Facility. Request for Administrative Amendments February 28, 2018 Page 2 of 2 Please contact John Cookson (265-6547) if you have questions or require additional information. Regards, Stephen Thatcher Manager, WNS Development North Slope Operations and Development Cc: Land Manager - Alaska, Anadarko E&P Onshore LLC Bruce W. Hunt, Petro -Hunt LLC ECFV JUN 26 2017 ACGCC ConocoPhillips June 2611, 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. 1. 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, UT. , /-Lt— 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 COMMISSION Anchorage, Alaska March 14, 2017 9:00 o'clock a.m. VOLUME I PUBLIC HEARING BEFORE: Cathy Foerster Daniel T. Seamount Hollis French 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 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 nci gei.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/A1O-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 443B 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/A1O-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/A1O-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/A1C-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/AIO-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/A10-003 Page 9 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 -0-0-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 CDS 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/A10-003 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: sahile@gci.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 NOCO-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- I7-004/AIO-003 Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net 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 CD5-313 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 NO CO-] 7-004/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. AK99501 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 a gci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/AIO-003 Page 201 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 CDS-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 NOLO-17-004/AIO-003 Page 21 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: sahileggci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/A10-003 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. AK99501 Fax: 907-243-1473 Email: sahile@gci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/A1O-003 Page 23 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 NOCO-17-004/AIO-003 Page 25 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 CD5-313 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 CD5-314X 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/AIO-003 Page 2 6 1 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/AIO-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: sahileggci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/AIO-003 Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahileggci.net Page 29 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: sahileggci.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/A10-003 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 34 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: sahileggci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/AIO-003 Page 3 6 1 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/A10-003 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/A1O-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/A1O-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: sahilea gci.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/AIO-003 Page 431 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/A1O-003 Page 46 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? g 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- 17-004/A10-003 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/A10-003 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: sahileggei.net PUBLIC HEARING 3/14/2017 DOCKET NOCO-17-004/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. AK99501 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: sahileggei.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) l )-CJ. ro7 U ConocoPhillips Alpine Oil Pool Expansion March 14th, 2017 Objective: Review Nanuq Kuparuk development drilling progress and the proposed Alpine Oil Pool expansion . resentation Outline: w Existing Alpine Oil Pool w Alpine Oil Pool Expansion w Future Nanuq Kuparuk sand development w CD5-313 / CD5-315 drilling results CD5-314X / CD5-316 drilling plans � No Underground Sources of Drinking Water � Injection Containment in the Alpine Oil Pool � Proposed CO & A10 Amendments 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 AlO 18A approved Class II disposal • Oct 2004 AlO 18B approved to expand development • Mar 2009 AlO 18C approved injection into expanded Alpine pool e:: 7276' 3 GRh"D Alpine RD DT G g SP1 150 1:1D00 1;0 ohm. M 100.0 150 usfft 50 G RD RHOS C 1.0 Ono) 100,0 1.55 91om3 2.5 953. r 7000 t} 7040 7050 T 70so r 7100 S 7120 75 7140 - 7160 f 71so r 7220 .7240- 240 7260- 7250 7SO- 7300- 300 -,x320 7320- 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 VIWII Pal Afire all Poo Em"nvon �»• Pia"ea Lawal Aare Oil Poo Ccnlra:tan iLarrat MAlone OilPco ConocoPhillips comae River Unit Atptne Oil Pool Expansion ConoA;hillips Nanuq Kuparuk Type Log D5 Pad 1 � i CD4 Pad' 5PB CDS-313PB1 C) � O � w La a w 0 2 4miles iver Unit 7280 7300 - to 7340 7360 T 0 North Periscope Deep Resistivity Image Kuparuk i Kalubik low ra+,... 114 ` Mlluveach ,Jj� a Ll 0 00 0 0 0 0 0 0 0 0 0 0 0 o 0 0 0 0 0 0 0 0 0 0 0 0 0 o LM 0 Ln o in us O Ln 0 Ln 0 uY en en a V Ln in Ko %0 N r` 00 CO cn M r1 r4 ri r♦ rr ri ri ri r-1 ra r1 e -i rl vi Lateral length: 10,392 feet Net Sand: 10,392 feet Thickness: 7-12 feet continuous Perm est: 100-500 and South 0 o 0 0 0 0 0 0 0 0 0 0 o ,n 0 Ln 0 9n o c rr N N N N N N N N Confidential Section Break Salinity exceeds regulatory standard for freshwater Water salinity calculations on wells in the Colville Delta area for the 1999 Alpine A10 found no sands with < 10,000 mg/I 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). ConocoPhillips 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 ■ r»..,e nxw ,M ALASKA ' 1N� COLVILLE RIVER UNIt Ti2N P. :3Ci F,2NR4E T12NRBE isNulgsut 1* { 21 „ is 11Nk3El T;1N€iAtw TlINUT to a Clover A ConocoPhiillps wal PaC -.-' NP,ia at Poa E.mnuen Cotwle River Unit Noce Oil Paa CenV*tbon Alpin* oil Pod ExpansionLexran C3Nene Oil Ped voum. Salinity 21,000 mi. 24,000 mg/1 18,000 mg/1 20,000 mg/1 21,000 mg/1 25,000 mg/1 16,000 mg/1 CD5-21 GR —1 RES tau PHIT o FTEMP Zoo RWA Measured ConocI3P iliips • 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 Como3 hillips • Existing Alpine NO does not govern injection pressure • Proposed Revision: Add NO rule that limits the injection pressure to 0.81 psi/ft 6700 6800 6900 7000 7100 7200 7300 7400 Collapse GR Resistivity Vshale Fracture Gradient UCS 0 150 1 100 0 1 8 PPG 18 0 pgi 1000 MIR MM mom Torok •;� , LOT data from Al s= iY HRZ N CL Ln 00 .., c y iGalubiik Nanuq Kup+ �a Miluveach Q a k o :CIO Wngak 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 Conoc4illips WATER INJECTION WITHOUT PROPPED FRACTURE IN THE ALPINE ZONE FLOODED AT 10,000 BPD AI ine IIFI - --- ........_. 1 Ili ! tee. �i . - nnnnmm�rnnmm/rnttn�l�r�nmrA>Il�nmt�mrrr T11tIn11ES1ilinll!'tl31ii1N1113nFIrtHnITLll3lilllifit6iTlt7i1S{nflnnlilnn" � t nnn11un1nlnnrn/nitln{ulnnnulrllllnnnm/nunnrnnlnntl nrmllnnalluunnanunnlnurnnl/w/uuununnmunlruunnrr rillnllilt4nnilniniiMnitiinnnnnlirntlir/Innn1111n{lllt1n11nnlnlnnlrlit1111111/iiit111nnN111ntriirrnnnitr111nn11nnitllilll111trnnttnnlinllnnllrln11H11111ln1 111nt1ltlI1111lHPlnlilltnlll/Initnnllttlninilratnlintintnllttilltlnlitiln1111/roll /rn11111ni1lndlnnuflnittlr IInInlNlltIIIIIltlillllnnl/111nnit1in/1NNlilrnlli/nF Ifllttrttll9tln6111iittirhirnilt111!/Iniinpnnrinnntltltltltll111nt1llnnnllln/ntlit rRNI/nlrillnllnnnllnlnn�n1111rIn1r11411nt11t1tilll�nininnlnt1n11nnniilrtlnl U'i,r .i"f':! ! B t l.i53ilthl13t1 .. ''? ltt 11'..1'Ci'R.3ir! iati 3q'ltlkl'r 3 1$t ry vrt i- ce i ! ie + 1Yt1 i 31 t 3 ! ! i I T 1 7 1 ictRS IIIIIIIIIIinilntl11111t1111u1tlluLtutttnunuuuenuumettuuu.e.tu.eeuu uuu..i.ii .uuuuu .....0 .. ......... ......... ...:..... 1 1 1 ' 13 WATER INJECTION WITHOUT PROPPED FRACTURE IN THE NANUQ KUPARUK ZONE FLOODED AT 10,000 BPD nnnunun mluuunnnuuunuuununununnuunnnm nauuonuunuontnunanmunnunumnu ... mnnmuniunuttuuunununununnnuuot/noulluuul - omuamuumunununanuunnunouunn • 1 11 nuuuunnuaulmunwmnuouuununauuuluautuum uununnnuunuunununuununuunnnm � • • • nnunnununannnnunnnunuunnunuuuunuununn nununununnnnoui/uuuonnnununanouunu►uow • uullnuaonuuunnnunnuunnrrununomnununuoummnunanaaaum wuuuuumuuuunnuuuuunnumunuowaounnutlnnunnmauumuw nnnnlmm�nuuunnunu/nnuuounummrnanonun uuonunmununuuunuuuntununuuuuunnnuuunnnonuwunnnuun • • • - • • • •/uuoonwnanunmw/uumllllnou/luwmluauaom munumuuunmmnnulluunnnuuunuuunnmmunumnnnnnumnuul •..aUu•1...11.lILfuO..•..a.Ulu..Ol1Uu. .0 1... uua uUull Iun LU .... /..IL.1.111...'b.a Y.YNY..ILL.i..1.O11aaY.I IIi111..Y1.1.II H101..1hill. -r 1 1 1 • • • � IIIIIIIIIIIIIt1111iti111111111/IIIIIIIIIIIIIIIIIIItIlilllllilll111111111/Ili/1111Illlllltllllll11111 1111111111111rill/Ililpllilllllllllllillllllllillilllllllllllll/11111111111111111 •rtte i 1 1 i��!. • Iilill11111IIIIIIIIIillli/1111/III1111111111111111111111111111/IIIIIIIIIIIIIIIINIIIIIIIIIIIIIIIIIII 1111111111111111111111111111111111111111Itllllllllllllllllllilll/111/1111IItlillll�h111� " 111111/Illillllllilltlllillllltlllllllll1111IIIIIIIIIIIIIIIIIIIIIItlllliil �IIIIIIiIII 111 ltll11111 1111111111111111111111111111111111111111/� 1111111/III/crit111111111111Itllllll IIIIIIIIIillllllllll - ;F, � � • �Iltllllllllllilllllltlllllllllllllllililllitlillllll11i11111111111111IIIIIIIIIIIII IIIIIIIIIIIIIIIIIIIIIIIIIIIIt1111111111111tI1111I111IIII111111111111111111111111111i11111II111111I1. . • , if Existing Alpine A1O 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.) 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 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 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 `-Aa 2---7 - 20 k`T 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 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. //signature on file// Cathy P. Foerster Commissioner STATE OF ALASKA ADVERTISING ORDER NOTICE TO PUBLISHER SUBMIT INVOICE SHOWING ADVERTISING ORDER NO., CERTIFIED AFFIDAVIT OF PUBLICATION WH'H ATTACHED COPY OF ADVERTISMENT. 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 F CLASSIFIED OTHER (Specify below) DESCRIPTION PRICE CO-17-004 and AIO-17-003 Initials of who prepared AO: Alaska Non -Taxable 92-600185 svi;nf'[ INYOfCIr SfIOW�NGADV>~R'[ISf{!1G: ..:ORDE:RNO;�CE.RTIFIED:AFF►DAVIT;OF;:;; PUBLICATION: WIT1i ATrACtWR COPY OF:::.: Department of Administration DIVISIOn Of AOGCC 333 W est 7th Avenue Anchorage, Alaska 99501 Pae 1 of 1 Total Of All Pages $ REF Type Number Amount Date Comments I PVN ADN89311 2 AD AO-17-023 3 4 FIN AMOUNT SY Appr Unit PGM LGR Object FY DIST LIQ 1 17 021147717 3046 17 2 3 4 5 Purchasing Authority Name: P� Title: /-- fes} P rch ing u[hor' afore Telephone Number G/g7� cJC7�/C_J g —1.Z3 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. 14Qire for the exclusive use of the state and not for resale. Dl<S:fRI13UTIfON: Division.Fiscal/Origtnal AO . Copies I'ublisher:(faxed), Divisjoil Fiscal, Receiving: Form: 02-901 Revised: 2/7/2017 270227 0001399979 $204.20 STATE OF ALASKA RECEIVED FER 10 2011 AOGCC AFFIDAVIT OF PUBLICATION 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. Signed Subscribed and sworn to before me this 8th day of Februarv, 2017 Notary PublicIn d for The State of Alaska. Third Division Anchorage, Alaska MY COMMISSION EXPIRES �3 9 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 4436 (CO 4436) and Area Injection Order 18C (AIO 18C) to allow for the expansion of the Alpine Oil Pool to include the westward development of the Nan uq 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. //signature on file// Cathy P. Foerster Commissioner AO -17-023 Published: February 8, 2017 f Notary P�iblic BRITNEY L. THOMPSON State of Alaska L Commission Expires Feb 23, 2019 Bernie Karl Gordon Severson Penny Vadla K&K Recycling Inc. 3201 Westmar Cir. 399 W. Riverview Ave. P.O. Box 58055 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 2--I- 2 o 1,-7 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@gmaii.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 1 (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 7" Avenue Anchorage, AK 99501 (907) 793-1223 CONFIDENTIALLTY NOTICE. This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Samantha Carlisle at (907) 793-1223 or Samantha.Carlisle@alaska.ggy. Jan 30th, 2017 Catherine P. Foerster, Chair Alaska Oil and Gas Conservation Commission 333 W. 7th Ave #100 Anchorage, Alaska, 99501-3539 �IEGEIVED ,]AN 3 12017 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 ConocoPhillips APPLICATION FOR EXPANSION AND OTHER MODIFICATION OF THE ALPINE OIL POOL AND MODIFICATION OF THE ALPINE AREA INJECTION ORDER Jan 30t", 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 443B & 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 T11 N 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, RK Section 1-3 all T1 ON, R4E Section 1-6 all T10N, R5E Section 5 N1/2NW1/4, SW1/4NW1/4, NW1/4SW1/4 Section 6 all T11N, RK Section 1-2 all Section 11-14 all Section 22-27 all CPA] 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, R3E Section 34-36 all T11N, 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, R3E Section 1-3 all T1 ON, R4E Section 1-6 all T10N, R5E Section 5 N1/2NW1/4, SWI/4NW1/4, NW1/4SW1/4 Section 6 all T11 N, 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) ell: 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 CPA[ 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 CPA] 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 (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. FaSW= Equation 1 0" `xRt 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 - 56) /AT Equation 3 0 Sonic derived Porosity AT Delta Temperature 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). CPAI Application for Alpine Oil Pool Expansion Jan 2017 Page 11 FIGURE 2: NANUQ KUPARUK TYPE LOG CD5-315PB1 CD5-313PB1 GR P34H RHOS ssTVD I GR P34H «PI 150 1.00 ohm.m 100.00 2.000 91Cm3 3.000 115 lb 9kP1 150 1.00 ohm m 100.00 2. Color fill q TMPH C Colorfill 10.63 MA3 0,001 Colorfiil 1 10- 0 IM1111i'mi, 7314 7286 7316 l' _ 7288 „ 7318 I _e i R 7280 VII CPAI 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 BPD 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 CPA[ Application for Alpine Oil Pool Expansion Jan 2017 Page 14 FIGURE 5: KUPARUK SEAWATER TREATMENT PLANT WATER COMPOSITION Sample Number: 5-160243-00063 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 Date: 02/24/2016 Analysis Results Test Parameter Result UOM BACTERIA' ATP ATPASE 31692 RLU D 10 N EX 1 C • ACETATE ACETATE -K5.0 mel D 10 N EX I CBUTYRAT E BUTYRATE iS.O mg/I DIONEx IC' CHLORIDE CHLORIDE 18447.8 mg/I 010NEY IC' FORMATE FORMATE sS.O mg/I DIONEX IC' PROPIONATE PROPIONATE <5.0 mg/I DIO NET{ IC' SULFATE SO4(SULFATE) 2500.0 me ICP METALS' AL (ALUMINUM) AL(ALUMINUM) 0.04 mel ICP METALS' B (BORON) 8(BORON) 4.65 mg/I ICP METALS' BA (BARIUM) BA (BARIUM) 0.15 mel ICF METALS' CA (CALCIUM) CA (CALCIUM) 42B.59 me] ICP METALS' CR (CHROMIUM) CR (CHROMIUM) 0.01 Mel ICA METALS' FE (IRON) FE(IRON) 0.07 mel ICP METALS' K(POTASSIUM) K (POTASSIUM) 391.42 mel ICP METALS' LI (LITHIUM) LI (LITHIUM) 0.22 mel ICP METALS' MG (MAGNESIUM) MG (MAGNESIUM) 1110.38 me ICA METALS • MN (MANGANESE) MN (MANGANESE) 0.009 mel ICP METALS • NA 0ODIUM) NA(SODIUM) 9973.70 mg/I ICP METALS' P (PHOSPHORUS) P (PHOSPHORUS) 0.03 mel ICP METALS • SI (SILICON) SI(SILICON) 1.43 mel 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: S-160203-00063 Sample Name: STP Seawater Plant Discharge Location: Area: KUPARUK Unit: STP Sample Point: STP SPD Sampled Date: 2/2/2016 3:50:00PM Matrix Id: WATER- SEA Reviewed By: Carville, Daniele Date: 02/24/2016 Analysis Results: Test Parameter Result UOM SR (STRONTIUM) 8.26 mg/1 ICP METALS • ZN (ZINC) ZN(ZINC) 0.02 mg/1 S-2320 ALKALIN ri Y *TOTAL BICARBONATE (HCO3) 191.8 mg/1 CARBONATE (CO3) 0.0 mg/1 S-2510 • CONDUCTIVITY CO NDUCrIVITY 53800 uS/Qn S-2520 SALINITY' SP GRAY SPE0FIC GRAVITY 1.0269 S-4500 PH (B)PH PH 7.12 S-450 0 S 2- (F) ' S U LFI D E BY TITR SULFIDE 1.8 mg/I CPA] Application for Alpine Oil Pool Expansion Jan 2017 Page 16 FIGURE 6: ALPINE FACILITY PRODUCED WATER COMPOSITION KUPARUK LAB ANALYTICAL REPORT 907-659-7214 nl020@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 Matra Id: WATER- PRODUCED Reviewed By: Carville, Daniele Date:10/30/2016 Ana Ns is Res alts: 1= I�mm e. Resit LQM DIONEX IC' ACETATE ACETATE 400.0 mg/I 010NEX ICBUTYRATE BUTYRATE 4.0 mg/1 DIONEK IC • CHLORIDE CHLORIDE 14285.1 mg/I DIONES IC* FORMATE FORMATE X5.0 mg/I DIONEX IC' PROPIONATE PROPIONATE 29.7 mg/I DIONS( IC • SULFATE S 04 IS U LFATE) 4070 mg/I ICA METALS • AL(AW MI N UM) ALfCALUMINUM) 0.04 mg/I ICA METALS ' B (BORON) B(BORON) 22.07 mg/I ICP METALS' BA (BARIUM) BA(BARIUM) 2.98 mg/I ICP METALS ' CA (CALCIUM) CA(CALCIUM) 164.33 mg/I ICP METALS • CR (CHROMIUM) CR (CHROMIUM) 0.01 mg/I ICA METALS • FE (IRON) FE (IRON) 4.73 mg/I ICA METALS • K(POTASSIUM) K (POTASSIUM) 50.63 mg/I ICA METALS ' U (LITHIUM) U (LITHIUM) 1.47 mg/l ICP METALS • MG (MAGNESIUM) MG (MAGNESIUM) 123.03 mg/I ICP METALS' MN (MANGANESE) MN (MANGANESE) 0.065 mg/I ICP METALS ' NA ($ODIUM) NA(SODIUM) 9188.43 mg/I ICP METALS ' P(PHOSPHORUS) P (PHOSPHORUS) 3.32 mg/I ICP METALS' SI (SILICON) SI (SIUCON) 17.60 mg/I ICA METALS • SR (STRONTIUM) SR (STRONTIUM) 12.09 mg/I ConotoPhillips 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 nl02O@cop.com Sample 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 Matra Id: WATER - PRODUCED Revievied By: Carville, Daniele Date: 10/3012016 Ana his E Res inti• I£SS Parameter �.rsJi Sid ICP METALS - ZN (ZINC) ZN (ZINC) 0.13 mg/I S-2320 ALFAUNITY • TOTAL BICARBO NATE (H CO 3) 1327.9 mg/1 CARBO NATE (003) 0.0 mg/I 5-2510' CONDUCTIVITY CONDUCTIVITY 44100 u5/an S-2520 SALIN ITY * SP GRAV SPECIFIC GRAVITY 1.0204 S-4500 PH (B)' PH PH 787 Sample NotWComments ConocoP11ll1ps CPAI Application for Alpine Oil Pool Expansion Jan 2017 Page 18 FIGURE 7: ALPINE FACILITY GAS INJECTANT COMPOSITION (MOLE %) CPB LABORATORY REPORT 907-659-5654 AKOPSLablntertek@bp.com Sample Information Sample ID Number: PD22663 Sample Facility: KUPARUK Collection Date/Time: 0311212016, 2:00 AM Sample Point: Mixing Manifold Sample Description: Produced Gas Sample Type: NATURAL GAS Well Number_ M-02 Results Analysis Name Result Units Carbon Dioxide (Normalized) 0.661 Male% 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 (Normailzed) 1.762 Mole% i -Pentane (Normalized) 0.283 Mole% n -Pentane (Normalized) 0.242 Mole% C6 Group (Normalized) 0.097 Mole% C7 Group (Normalized) 0.046 Mole% C8 Group (Normalized) 0.014 Mole% Line Pressure 4050 prig C6+ (Normalized) 0.160 Male% Compressibility Factor 0.9956 Nitrogen (Normalized) 0.530 Mole% Oxygen Contamination <0.001 Mole% Specific Gravity Ideal @ 14.696 psia 0.7982 Specific Gravity Real @ 14.696 psis 0.8015 BTU Gross Dry Ideal @ 14.696 psia 1364.8 Btu/cf BTU Gross Dry Real @ 14.65 psia 1366.5 Btu/cf BTU Gross Saturated Ideal @ 14.73 1344.2 Btulcf BTU Net Ideal @ 14.696 psia 1240.9 Btu/cf Molecular Weight (calculated) 23.11 BTU Gross Saturated Real @ 14.65 1338.4 Btu/cf 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 8: PLOT OF ALPINE POOL EXPANSION AREA WITH PENETRATIONS EXAMINED FOR FRESHWATER SOURCES CPAI Application for Alpine Oil Pool Expansion Jan 2017 Page 20 FIGURE 9: CLOVER A FORMATION WATER SALINITY CLOVER A FORMATION WATER SALINITY wo I ..oma •_ 250 _ :-:. :,::: ,-- ::::: ,: :.:• :::::: �. :: „ zo 40 °arc='; 60 so t,. Soo Iso 'F- I 1000 1000 1250 . 1500. 1750 ...... .,.r._.....:... -w... s Base Permafrost 2000 2250 s�M 7- 2500 2750' 3000 7 qi 3250 w Casing Shoe 3500 gym 7 3750 .000 to naso � 0500 e � I 1750 I j 5000 f{ l 5250 ; i CPAI Application for Alpine Oil Pool Expansion Jan 2017 Page 21 FIGURE 10: CD5-21 FORMATION WATER SALINITY ,.FORMATION 0� m Soo 750 1250 1750 2000 2150 Casing Shoe -=Omni - air- - _=TMEN CPAI Application for Alpine Oil Pool Expansion Jan 2017 Page 22 FIGURE 11 : NUIQSUT 1 FORMATION WATER SALINITY 1:3000 250 500 750 1000 1250 1750 2000 2250 2500 2750 3000 3250 - 3500 3750 4000 4250 4500 4750 5000 5250 5500 5750 6000 6250 6500 6750 7000 NUIOSUT I FORMATION WATER SALINITY ppCasing 0 mann memo NONE ism - ■■■■■■.■■■ � i►��r��—� ------ice-- Confidential pages 23 — 27 held in secure storage