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Home My WebLink AboutCO 341 FCONSERVATION ORDER 341F Docket Number: CO -15-009 Prudhoe Bay Field Prudhoe Bay Unit Prudhoe Bay Oil Pool North Slope Borough, Alaska 1. July 17, 2015 BPXA's request for amendment of Pool Rule 9 and modification of AIO 3A and A10 4F (appendix held confidential in secure storage) 2. July 20, 2015 Notice of hearing, affidavit of publication, email distribution, mailings 3. July 23, 2015 Revised notice of hearing, affidavit of publication, email distribution, mailings 4. August 19, 2015 CPAI's comments 5. August 25, 2015 BPXA's comments (appendix held confidential in secure storage) 6. August 27, 2015 Transcript (parts held confidential in secure storage), sign -in sheet, public testimony, presentations (parts held confidential in secure storage) 7. September 3, 2015 CPAI's supplemental submission 8. September 4, 2015 Email: supplemental information on CO2 disposal 9. September 8, 2015 BPXA's post hearing submission (appendix held confidential in secure storage) 10. November 2, 2015 Request for AA for waiver of monthly reporting of daily production allocation data (CO 341F.001) 11. May 24, 2016 Request for AA for pressure survey and gas oil contact monitoring requirements (CO 341 F.002) 12. December 8, 2016 Request for AA for waiver of neutron logging requirement for coil sidetrack well (CO 34117.003 Denied) 13. December 14, 2016 BPXA's request for AA for waiver of neutron log requirement coil sidetrack well PBU 07-15B (CO 341F.004) 14. January 17, 2017 Request for reconsideration of CO 341F.003 (attachment held confidential in secure storage) 15. December 14, 2016 BPXA's request for AA for waiver of neutron log requirement coil sidetrack well PBU 07-29E (CO 341F.005) 16. December 16, 2016 BPXA's request for AA for waiver of neutron log requirement coil sidetrack well PBU G -27B (CO 341F.006) 17. August 28, 2017 BPXA's request for AA to amend Rules 6, 7, 8 and 13. ORDERS r� STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue Anchorage Alaska 99501 Re: THE APPLICATION OF BP Exploration (Alaska) Inc. for amendment of Prudhoe Oil Pool Rule 9. IT APPEARING THAT: Docket Number: CO-15-009 Conservation Order No. 341F Prudhoe Bay Field Prudhoe Bay Unit Prudhoe Bay Oil Pool North Slope Borough, Alaska October 15, 2015 1. By application received July 17, 2015, BP Exploration (Alaska) Inc. (BPXA) on behalf of itself and ExxonMobil Alaska Production Inc. (ExxonMobil) as working interest owners (WIOs) in the Prudhoe Bay Unit requested that Conservation Order (CO) 341E be amended to increase the allowable gas offtake limit in Rule 9 from an annual average of 2.7 billion standard cubic feet per day (BSCFPD) to 4.1 BSCFPD. 2. Pursuant to 20 AAC 25.540, the Alaska Oil and Gas Conservation Commission (AOGCC) scheduled a public hearing for August 27, 2015. On July 20, 2015, the AOGCC published notice of that hearing on the State of Alaska's Online Public Notice website and 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 of Public Hearing to all persons on the AOGCC's mailing distribution list. On July 21, 2015, the notice was published in the ALASKA DISPATCH NEWS. 3. On July 23, 2015, the AOGCC published notice of that the location of the hearing had changed on the State of Alaska's Online Public Notice website and 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 of Public Hearing to all persons on the AOGCC's mailing distribution list. On July 24, 2015, the notice was published in the ALASKA DISPATCH NEWS. 4. By letter received August 19, 2015, ConocoPhillips Alaska, Inc. (CPAI) on behalf of itself and Chevron U.S.A. Inc. (Chevron) as PBU WIOs supported BPXA's request to increase the allowable gas offtake limit, but requested the limit to be set at 3.6 BSCFPD. 5. On August 25, 2015, the AOGCC received pre -filed testimony from BPXA. 6. On August 27, 2015, the AOGCC received a letter from ExxonMobil supporting BPXA's application 7. The hearing commenced at 9:00 AM on August 27, 2015, in the Alaska State Legislature Building, Legislative Information Office located at 716 West 4th Avenue, Anchorage, Alaska. Conservation Order 341 F • • October 15, 2015 Page 2 of 10 8. Testimony was received from representatives of BPXA, CPAI, and a Mr. Tom Lakosh, a private citizen. 9. The record was held open until September 8, 2015, to allow the presenter to respond to requests made during the hearing. 10. The AOGCC received written comments from Mr. Lakosh on August 27, 2015, the requested additional information from CPAI on September 3, 2015, and the requested additional information from BPXA on September 8, 2015. FINDINGS: Operator and Owners: BPXA is the operator of the leases in the portion of the PBU covered by the Affected Area of this order. BPXA, ExxonMobil, CPAI, and Chevron are the WIOs, and the State of Alaska, Department of Natural Resources (DNR) is the landowner of the Affected Area, which is located within the North Slope Borough, along Alaska's northern coastline. 2. Affected Area: The Affected Area is defined in CO 341E and remains unchanged for this amended order. 3. BPXA Request: BPXA and ExxonMobil request that the allowable gas offtake from the Prudhoe Oil Pool be increased from annual average of 2.7 BSFPD to 4.1 BSCFPD to provide the opportunity to sell gas to the Alaska LNG Project (AK LNG), which is currently being planned, beginning in or about 2025. According to the request, the anticipated sales volume from the Prudhoe Oil Pool to the AK LNG project is 2.7 BSCFPD, and estimated fuel usage for the PBU along with continued small local sales amounts to approximately 0.6 BSCFPD, for a total anticipated annual average daily offtake rate of 3.3 BSCFPD. BPXA believes the requested annual average 4.1 BSCFPD offtake allowable would enable the Prudhoe Oil Pool to provide the fall 3.5 BSCFPD planned capacity for the AK LNG project, should other anticipated gas sources for the AK LNG project not come to fruition, as well as meet fuel -gas needs for the PBU and continue the small volume sales from PBU that are currently taking place. 4. CPAI Request: CPAI and Chevron request that the allowable gas offtake from the Prudhoe Oil Pool be increased, but only to an annual average of 3.6 BSCFPD. The basis for this request is CPAI's disagreement with BPXA' S assumption that the Prudhoe Oil Pool must provide the full 3.5 BSCFPD capacity of the AK LNG project for an indefinite period of time. CPAI and Chevron contend this assumption is unrealistic because an annual average limit of 3.6 BSCFPD will provide the ability to meet the full 3.5 BSCFPD capacity of the AK LNG project for several months in the event of an extended period of disruption to the other sources of gas feeding the AK LNG project. CPAI also requests that CO 341E be amended to allow for future modifications of the allowable gas offtake limit to be achieved administratively. Alternative Development Plans Considered: During the hearing, confidential information and testimony were presented in which the WIO's discussed reservoir simulation model construction, showed simulation results for BPXA's proposal along with several other development options —including alternative offtake rates and AK LNG project start dates, and presented sensitivity analyses for different aspects of the simulation model. The Conservation Order 341F • • October 15, 2015 Page 3 of 10 simulation results show that ultimate recovery from the Prudhoe Oil Pool could only be maximized with major gas sales as there are significantly more barrels of oil equivalent (BOE) of reserves in the form of gas within the pool than there are in the liquids that remain within the pool. The simulation results also indicate that ultimate recovery is relatively insensitive to size and timing of gas sales and to the various sensitivity cases that were also analyzed. The only sensitivity case that may have a significant impact on ultimate recovery is the size of the Prudhoe Oil Pool being significantly different than expected, which is unlikely given the amount of well, seismic, and reservoir data available for the pool. 6. Reservoir Development and Management: The Prudhoe Oil Pool will continue to be developed with the goal of maximizing liquids recovery until major gas sales in support of the AK LNG project begin (currently envisioned to commence in or about 2025). Once major gas sales begin, production from the field would continue, but the volume of gas available for reinjection for enhanced oil recovery purposes will be reduced by the amount sold to the AK LNG project. However, an effluent stream from the AK LNG gas treatment plant (GTP) that is nearly pure carbon dioxide will be available for injection. Eventually, the production wells within the Prudhoe Oil Pool will not be able to provide enough gas to meet the AK LNG project sales requirement. At that time, the WIO's anticipate existing gas cap injection wells will begin to be converted from injectors to producers in order to meet sales requirements. CONCLUSIONS: 1. Selling gas from the Prudhoe Oil Pool is necessary to maximize ultimate recovery from the reservoir. The ultimate recovery achievable under major gas sales is relatively insensitive to differences in the specifics of the sale. 2. An annual average gas offtake rate of 3.6 BSCFPD provides adequate capacity to meet the anticipated gas sales requirements for the AK LNG project. This determination is made without prejudice to future reconsideration should circumstances change. Monitoring of development operations within the Prudhoe Oil Pool prior to commencement of major gas sales is vital to ensure that liquids recovery is maximized. 3. CO2 within the AK LNG GTP effluent stream may prove to be a very valuable resource for enhanced recovery projects on the North Slope. Conservation Order 341F • • October 15, 2015 Page 4 of 10 NOW THEREFORE IT IS ORDERED: The following rules, in addition to the statewide requirements under 20 AAC 25 (to the extent not superseded by these rules), govern development in the affected area described below: Affected Area: Umiat Meridian Township Range Section T10N R12E 1, 2, 3, 4, 10, 11, 12 T10N R13E 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16, 24 T10N R14E 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, 26, 27, 28, 36 T10N R15E all T10N. R16E 5, 6, 7, 8, 17, 18, 19, 20, 29, 30, 31 T11N R11E 1, 2, 3, 4, 9, 10, 11, 12, 13, 14, 15, 24, 25 T11N R12E all THN R13E all THN R14E all T11N R15E all THN R16E 17, 18, 19, 30, 31, 32 T12N R10E 13, 24, T12N RHE 15, 16, 17, 18, 19, 20, 21, 22, 25, 26, 27, 28, 29, 30, 32, 33, 34, 35, 36 T12N R12E 23, 24, 25, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35, 36 T12N R13E 19, 20, 21, 22, 23, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35, 36 T12N R14E 25, 26, 27, 28, 29, 31, 32, 33, 34, 35, 36 T12N R15E 25, 26, 27, 28, 29, 30 ,31 ,32, 33, 34, 35, 36 Rule 1 Pool Definition The Prudhoe Oil Pool is defined as (i) the accumulations of oil that are common to and that correlate with the accumulations found in the Atlantic Richfield - Humble Prudhoe Bay State No. 1 well between the depths of 8,110 feet and 8,680 feet, and (ii) the accumulation of oil that is common to and correlates with the interval from 9,638 to 9,719 measured feet on the Borehole Compensated Sonic Log, Run 2, Dated September 28, 1975, in the Atlantic Richfield -Exxon NGI No. 1 well, and that is in hydraulic communication with the gas cap of the former accumulations in the Sag River Formation. Conservation Order 341F • • October 15, 2015 Page 5 of 10 The latter accumulation is found within the following area: T11N R14E: Sections: 1, 2, 11(N/2 and SE/4), 12, 13, 14(E/2), 23(NE/4), 24, 25(N/2) T11N R15E: Sections: 6, 7, 8, 17, 18, 19, 20, 29(N/2), 30(N/2) T12N R14E: Sections 35, 36 Umiat Meridian. Rule 2 Well Spacing There shall be no restrictions as to well spacing except that no pay shall be opened in a well closer than 500 feet to the boundary of the affected area. Rule 3 Casing and Cementing Requirements (a) Conductor casing shall be set at least 75 feet below the surface and sufficient cement shall be used to fill the annulus behind the pipe to the surface. Rigid high -density polyurethane foam may be used as an alternate to cement, upon approval by the AOGCC. The AOGCC may also administratively approve other sealing materials upon application and presentation of data which show the alternate is appropriate based on accepted engineering principles. (b) Surface casing to provide proper anchorage for equipment, to prevent uncontrolled flow, to withstand anticipated internal pressure, and to protect the well from the effects of permafrost thaw -subsidence or freeze -back loading shall be set at least 500 feet, measured depth, below the base of the permafrost but not below 5000 feet true vertical depth. Sufficient cement shall be used to fill the annulus behind the casing to the surface. The surface casing shall have minimum axial strain properties of 0.5% in tension and 0.7% in compression. (c) Alternate casing programs may be administratively approved by the AOGCC upon application and presentation of data, which show the alternatives, are appropriate, based upon accepted engineering principles. Rule 4 Blowout Prevention Equipment and Practice (Revoked C.O.341D Rule 5 Automatic Shut-in Equipment (Revoked Other Order 66) Rule 6 Pressure Surveys (a) Prior to regular production, a static bottom hole or transient pressure survey shall be taken on at least one in three wells drilled from a common drilling site. (b) An annual pressure surveillance plan shall be submitted to the AOGCC in conjunction with the Annual Prudhoe Pool Reservoir Surveillance Report by April 1, each year. The plan will contain the number of pressure surveys anticipated for the next calendar year and be subject to approval by the AOGCC by May 1. These surveys are needed to effectively monitor reservoir pressure in the Prudhoe Oil Pool. The surveys required in (a) of this rule may be used to fulfill the minimum requirements. (c) Data from the surveys required in (a) and (b) of this rule shall be submitted with the Annual Prudhoe Oil Pool Reservoir Surveillance Report by April 1 each year. Data submitted shall include rate, pressure, time depths, temperature, and any well condition Conservation Order 341F • October 15, 2015 Page 6 of 10 necessary for the complete analysis of each survey. The datum for the pressure surveys is 8800 feet subsea. Transient pressure surveys obtained by a shut in buildup test, an injection well pressure fall -off test, a multi rate test or an interference test are acceptable. Other quantitative methods may be administratively approved by the AOGCC. (d) Results and data from any special reservoir pressure monitoring techniques, tests, or surveys shall also be submitted as prescribed in (c) of this rule. Rule 7 Gas -Oil Contact Monitoring (a) Prior to initial sustained production, a cased or open hole neutron log shall be run in each well. This requirement is waived for waterflood/EOR areas encompassed by the expanded Prudhoe Bay Miscible Gas Project outlined in C.O. 290, and for those areas not expected to have significant GOC movement or gas encroachment from the gravity drainage area defined by the AOGCC through Administrative Approval. (b) A minimum of 40 repeat cased hole neutron log surveys shall be run annually. (c) The neutron logs run on any well and those required in (a) and (b) of this rule shall be filed with the AOGCC by the last day of the month following the month in which the logs were run. Rule 8 Productivity Profiles (a) A spinner flow meter or tracer survey shall be run in each well during the first six months the well is on production. This requirement is waived for wells completed with a single perforated interval, or with perforations in a single reservoir zone including highly deviated (greater than 65 degrees) and horizontal wells. (b) Follow-up surveys shall be performed on a rotating basis so that a new production profile is obtained on each well periodically. Nonscheduled surveys shall be run in wells which experience an abrupt change in water cut, gas -oil ratio, or productivity. (c) The complete spinner flow meter or tracer data and results shall be recorded and filed with the AOGCC by the last day of the month following the month in which each survey is taken. Rule 9 Pool Off -Take Rates (Revised this order) The maximum annual average oil offtake rate is 1.5 million barrels per day plus condensate production. The maximum annual average gas offtake rate is 3.6 billion standard cubic feet per day, which contemplates an annual average rate of 2.7 billion standard cubic feet per day shipped to the proposed AK LNG GTP and additional capacity to account for production upsets at other fields that feed the proposed AK LNG GTP. Daily offtake rates in excess of these amounts are permitted only as required to sustain these annual average rates. The annual average offtake rates as specified shall not be exceeded without the prior written approval of the AOGCC. Annual average offtake rates mean the daily average rate calculated by dividing the total volume produced in a calendar year by the number of days in that year. However, in the first calendar year that large gas offtake rates are initiated, following the completion of a large gas sales pipeline, the annual average offtake rate for gas shall be determined by dividing the total volume Conservation Order 341F • • October 15, 2015 Page 7 of 10 of gas produced in the calendar year by the number of days remaining in the year following initial delivery to the large gas sales pipeline. Rule 10 Facility Gas Flaring (Revoked CO 3410 Rule 11 Annual Surveillance Reporting An annual Prudhoe Oil Pool surveillance report will be required by April 1 of each year. The report shall include but is not limited to the following: 1. Progress of enhanced recovery project(s) implementation and reservoir management summary including engineering and geotechnical parameters. 2. Voidage balance by month of produced fluids, oil, water and gas, and injected fluids, gas, water, low molecular weight hydrocarbons, and any other injected substances (which can be filed in lieu of monthly Forms 10-413 for each FOR project). 3. Analysis of reservoir pressure surveys within the field. 4. Results and where appropriate, analysis of production logging surveys, tracer surveys and observation well surveys. 5. Results of gas movement and gas -oil contact surveillance efforts including a summary of wells surveyed and analysis of gas movement within the reservoir. The analysis shall include map(s) and/or tables showing the locations of various documented gas movement mechanisms as appropriate. 6. Progress of the Gas Cap Water Injection project with surveillance observations including; (a) volume of water injected, (b) reservoir pressure results, maps, and analysis (in conjunction with (3.) of this rule), (c) water movement and zonal conformance maps derived from surveillance (such as Pulsed Neutron Logs and 4-D gravity surveys) (d) results of reservoir evaluations of performance (such as material balance and reservoir simulation studies), (e) surveillance plans for the upcoming year, and (f) any plans for change in project operation. Rule 12 Prudhoe Bay Miscible Gas Proiect (PBMGP) (a) Expansion of the PBMGP and infill expansion of miscible gas injection in the NWFB is approved for the 59,740 acre portion of the Prudhoe Oil Pool defined in the record. (b) An annual report must be submitted to the AOGCC detailing performance of the PBMGP and outlining compositional information for the current miscible injectant (MI) necessary to maintain miscibility under anticipated reservoir conditions. (c) The minimum miscibility pressure (MMP) of the Miscible Injectant must be maintained at least 100 psi below the average reservoir pressure in the Prudhoe Bay Miscible Project area. When the Operator demonstrates that the reservoir pressure is no longer declining within the Prudhoe Bay Miscible Project Area (as evidenced by reservoir Conservation Order 341 F • October 15, 2015 Page 8 of 10 pressure measurements), the MMP may be maintained at or below the average reservoir pressure in the Prudhoe Bay Miscible Project area. Rule 13 Waiver of GOR Limitation The AOGCC waives the requirements of 20 AAC 25.240(b) for all oil wells in the Prudhoe Oil Pool of the Prudhoe Bay Field so long as the gas from the wells is being returned to the pool, or so long as the additional recovery project is in operation. Rule 14 Waiver of "Application for Sundry Approval" Requirement for Workover Operations The requirements of 20 AAC 25.280(a) are waived for development wells in the Prudhoe Oil Pool of the Prudhoe Bay Field. Sundry work application and reporting requirements shall be done in accordance with the "Well Work Operations and Sundry Notice/Reporting Requirements for Pools Subject to Sundry Waiver Rules" matrix maintained by the AOGCC Rule 15 Waterflooding The AOGCC approves the December 1980 additional recovery application for water -flooding in the Prudhoe Oil Pool subject to the requirements listed in Rule 11 above. Any proposed changes must be submitted to the AOGCC for approval. Rule 16 Orders Revoked (Revised this Order) The following Conservation Orders and associated Administrative Approvals and letter approvals are hereby revoked. Conservation orders 78, 83B, 85, 87, 88, 96, 97, 98B, 117, 117A, 118, 130, 137, 138, 139, 140, 141, 143, 145, 145A, 148, 155, 160, 164, 165, 166, 167, 169, 174, 178, 180, 181, 183, 184, 185, 186, 188, 189, 192, 194, 195, 195.1, 195.2, 195.4, 197, 199, 200, 204, 208, 213, 214, 219, 220, 223, 224, 238, 258, 259, 279, 290 and 333, and March 20, 1981 and August 22, 1986 letter approvals. Additionally, conservation orders 341, 341A, 341B, 341C, 341D, and 341E and all associated administrative approvals (except CO 341 D.001 and CO 341 E.003, which remain in effect) are hereby revoked. The hearing records of these orders are made part of the record for this order. Rule 17 Gas Cap Water Iniections The Gas Cap Water Injection Project as described in the operator's application and testimony is approved. Ongoing reservoir surveillance is required to determine that water movement within the reservoir is confined as intended and does not negatively impact overall hydrocarbon recovery, and to determine that the project has resulted in stabilization of reservoir pressure. Rule 18 Commingling of Production in the Same Wellbore (Source: CO 341E.005) Commingling production from the Aurora and Prudhoe Oil Pools in Well S-26 is approved on the condition that BPXA allocates production to the separate pools using the geochemical test, production log, and regular well test results outlined below: (a) Prior to commingling production in Well S-26, a bottom -hole static reservoir pressure and production test must be obtained and geochemical sampling and analysis must be Conservation Order 341 F • • October 15, 2015 Page 9 of 10 performed on oil from the Aurora Oil Pool (in isolation from the Prudhoe Oil Pool). (b) For the first six months after commingled production starts, geochemical sampling and analyses must occur monthly at the time stabilized production tests are performed. Thereafter, geochemical sampling and analysis must occur at least twice per year and not less frequently than once every seven months. (c) Production logs must be obtained and compared to the geochemical and regular well test results within the first two months and again six months after commingled production starts. Thereafter, production logs or isolated well tests of each pool must be obtained when major changes in production characteristics occur which could result in less accuracy in allocation of gas or water to the separate pools. (d) In addition to the other requirements of Rule 4 of CO 457B, the monthly reports required by Rule 4(e) of CO 457B must identify the Well S-26 production allocated to the Aurora Oil Pool and Prudhoe Oil Pool. (e) The volumes reported on Form 10-405—i.e., in accordance with 20 AAC 25.230(b)— must identify the Well S-26 production allocated to the Aurora Oil Pool and Prudhoe Oil Pool. (f) A summary report documenting the results and effectiveness of the commingled production allocation must be provided to the AOGCC within 9 months after the start of commingled production and shall include the results of the production allocated to the Aurora and Prudhoe Oil Pools, along with the analyses of the geochemical tests, production logs, and regular well tests. Rule 19 CO2 Utilization Study (New this order) By December 31, 2020, the WIOs shall complete a study and submit a report to the AOGCC detailing the best use of the effluent gas stream projected to come from the AK LNG GTP to maximize total hydrocarbon recovery. The study and report shall evaluate the suitability of using CO2 for enhanced recovery purposes in the oil pools on the North Slope in which any of the four main WIOs (BPXA, ExxonMobil, CPAI, or Chevron) have an ownership interest. The study and report shall look at the benefits to using CO2, and mixtures containing CO2, for enhanced recovery purposes (including miscible injection, viscosity reducing, and pressure maintenance type projects as appropriate) and include estimates of additional recovery that would be attributable to CO2 injection. The report shall also evaluate challenges to implementing CO2 injection in these pools. Rule 20 Liquid Hydrocarbon Recovery Maximization Report (New this order) By June 30, 2021, the WIOs shall submit a report to the AOGCC that provides detailed information about the results of projects and operations undertaken from the effective date of this order through December 31, 2020, as well as information about projects underway or planned at that time to accelerate liquid hydrocarbon production to maximize recovery in advance of the proposed major gas sales associated with the AK LNG project. Conservation Order 341F • • October 15, 2015 Page 10 of 10 Rule 21 Administrative Relief (New this order) Upon proper application, or its own motion, and unless notice and public hearing are otherwise required, the AOGCC may administratively waive the requirements of any rule stated herein or administratively amend this order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater. DONE at Anchorage, Alaska and dated October 15, 2015. Cathy V. Foerster Chair, Commissioner Daniel T. Seamount, Jr. 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. Singh, Angela K (DOA) From: Carlisle, Samantha J (DOA) Sent: Thursday, October 15, 2015 3:32 PM To: AKDCWellIntegrityCoordinator, Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew VanderJack; Anna Raff; Barbara F Fullmer, bbritch; bbohrer@ap.org; Bob Shavelson; Brian Havelock, Bruce Webb; Burdick, John D (DNR); Carrie Wong; Cliff Posey; Colleen Miller, Crandall, Krissell; D Lawrence; Dave Harbour; David Boelens; David Duffy; David House; David McCaleb; David Steingreaber; David Tetta; Davide Simeone; ddonkel@cfl.rr.com; Dean Gallegos; Delbridge, Rena E (LAS); DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Frank Molli; Gary Oskolkosf, George Pollock, ghammons; Gordon Pospisil; Gregg Nady; gspfoff, Jacki Rose; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Williams, Jennifer L (LAW); Jerry Hodgden; Jerry McCutcheon; Solnick, Jessica D (LAW); Jim Watt; Jim White; Joe Lastufka; Joe Nicks; John Adams; Easton, John R (DNR); Jon Goltz; Juanita Lovett; Judy Stanek, Houle, Julie (DNR); Julie Little; Kari Moriarty; Kazeem Adegbola; Keith Wiles; Kelly Sperback; Gregersen, Laura S (DNR); Leslie Smith; Lisa Parker, Louisiana Cutler; Luke Keller, Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Kremer, Marguerite C (DNR); Mary Cocklan-Vendl; Michael Calkins; Michael Duncan; Michael Moora; Mike Bill; mike@kbbi.org; Mikel Schultz; MJ Loveland; mkm7200; Morones, Mark P (DNR); Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nick W. Glover, Nikki Martin; NSK Problem Well Supv; Oliver Sternicki; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Renan Yanish; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Moothart, Steve R (DNR); Suzanne Gibson; sheffield@aoga.org; Tania Ramos; Ted Kramer, Davidson, Temple (DNR); Terence Dalton; Teresa Imm; Terry Templeman; Thor Cutler Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater, Anne Hillman; Brian Gross; Bruce Williams; Bruno, Jeff 1 (DNR); Caroline Bajsarowicz; Casey Sullivan; Diane Richmond; Don Shaw; Donna Vukich; Eric Lidji; Gary Orr, Smith, Graham O (PCO); Greg Mattson; Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Holly Pearen; Hyun, James J (DNR); Jason Bergerson; jill.a.mcleod@conocophillips.com; Jim Magill; Joe Longo; John Martineck, Josh Kindred; Kenneth Luckey; King, Kathleen J (DNR); 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); Pat Galvin; Bettis, Patricia K (DOA); Pete Dickinson; Peter Contreras; Richard Garrard; Robert Province; Ryan Daniel; Sandra Lemke; Sarah Baker, Peterson, Shaun (DNR); Pollard, Susan R (LAW); Talib Syed; Terence Dalton; Tina Grovier (tmgrovier@stoel.com); Todd, Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster, William Van Dyke; Ballantine, Tab A (LAW); Bender, Makana K (DOA); Bixby, Brian D (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Cook, Guy D (DOA); Crisp, John H (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Herrera, Matthew F (DOA); Hill, Johnnie W (DOA); Jones, Jeffery B (DOA); Kair, Michael N (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqua[, Maria (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) Subject: Conservation Order 341F (Prudhoe Bay Unit) Attachments: co341f.pdf Please see attached. Samantha CarCisCe Executive Secretary II .ACas(a OiCandGas Conservation Commission 333 West 7" .Avenue .Anchorage, AX99501 (907) 793-1223 (yhone) (907) 276-7542 (fax) CONFIDENTIALTIY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Samantha Carlisle at (907) 793-1223 or Samantha.Carhsle@alaska.gov. James Gibbs Jack Hakkila Bernie Karl K8:K Recycling Inc. P.O. Box 1597 P.O. Box 190083 Soldotna, AK 99669 Anchorage, AK 99519 P.O. Box 58055 Fairbanks, AK 99711 Gordon Severson Penny Vadla George Vaught, Jr. 3201 Westmar Cir. 399 W. Riverview Ave. P.O. Box 13557 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Dave P. Lachance Richard Wagner Darwin Waldsmith Vice President, Reservoir Development P.O. Box 60868 P.O. Box 39309 BP Exploration (Alaska), Inc. Fairbanks, AK 99706 Ninilchik, AK 99639 P.O. Box 196612 Anchorage, AK 99508 CL---�S� Angela K. Singh Ati �� THE STATE • ofALASKA GOVERNOR BILL WALKER Aias a On and Cas Conservation Commission ADMINISTRATIVE APPROVAL CONSERVATION ORDER NO. 50513.001 CONSERVATION ORDER NO.457B.005 CONSERVATION ORDER NO.341F.001 CONSERVATION ORDER NO.471.008 CONSERVATION ORDER NO. 452.003 CONSERVATION ORDER NO.484A.003 CONSERVATION ORDER NO.559.011 CONSERVATION ORDER NO.570.009 CONSERVATION ORDER NO.329B.004 Ms. Diane Richmond Performance and Data Management Lead, Alaska Reservoir Development BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.olaska.gov Re: Docket Number: CO-15-013 Request for administrative approval to waive the monthly production allocation reporting requirement for the Schrader Bluff Oil Pool, Aurora Oil Pool, Prudhoe Oil Pool, Borealis Oil Pool, Midnight Sun Oil Pool, Polaris Oil Pool, Put River Oil Pool, Raven Oil Pool, and PBU Well NK-43 which is completed in the Niakuk and Raven Oil Pools in the Prudhoe Bay Unit. Dear Ms. Richmond: By letter dated November 2, 2015, and email date December 16, 2015, BP Exploration (Alaska) Inc. (BPXA) requested administrative approval to waive the requirement for monthly reporting of daily allocation and test data contained in the following rules: - Rule 4(f) of Conservation Order No. (CO) 50513; - Rule 4(e) of CO 45713; - Rule 18(d) of CO 34117; - Rule 4(g) of CO 471; - Rule 7(d) of CO 452; CO 505B.001, CO 457B.005, *41F.001, CO 471.008, CO 452.003, CO 4840, CO 559.011, CO 570.009, CO 329B.004 January 7, 2016 Page 2 of 3 - Rule 4(d) of CO 484A1; - Rule 4(f) of CO 559; - Rule 6(d) of CO 570; and - The first sentence of Rule 4 of CO 32913.003 In accordance with Rule 13 of CO 505B, Rule 10 of CO 45713, Rule 21 of CO 341 F, Rule 10 of CO 471, Rule 13 of CO 452, Rule 13 of CO 484A, Rule 11 of CO 559, Rule 14 of CO 570, and Rule 5 of CO 32913.003, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS BPXA's request for administrative approval to waive the requirement to submit monthly reports of daily allocation and test data. BPXA requested to waive only the first sentence of Rule 4 CO 32913.003, which states: The operator shall submit a monthly report and file(s) containing daily allocation data, daily test data, results of geochemical analysis and results of production logs used for purposes of allocation. BPXA requested to waive the following rules in their entirety. Rule 4(d) of CO 484A states: The Operator must submit a monthly report (in printed and electronic form) including well tests, daily -allocated production and allocation factors for the Pool. Rule 18(d) of CO 341F states: In addition to the other requirements of Rule 4 of CO 45713, the monthly reports required by Rule 4(e) of CO 457B must identify the Well S-26 production allocated to the Aurora Oil Pool and Prudhoe Oil Pool. Rule 4(f) of CO 505B, Rule 4(e) of CO 457B, Rule 4(g) of CO 471, Rule 7(d) of CO 452, Rule 4(f) of CO 559, and Rule 6(d) of CO 570 states: The operator shall submit a monthly report and electronic file(s) containing daily allocation data and daily test data for agency surveillance and evaluation. Each of the affected pools is required to submit an annual reservoir surveillance report, providing a summary report on the production allocation and well test data in this annual report and retaining the ability to review the daily data if necessary allows the AOGCC to verify the performance of the well testing and allocation system without the need for monthly reports on the same data. BPXA's application requested to amend CO 484, however CO 484 was replaced by CO 484A on November 30, 2005. Therefore, the AOGCC is treating BPXA's application as an application to amend CO 484A. CO 505B.001, CO 457B.005, Ca041F.001, CO 471.008, CO 452.003, CO 484A0, CO 559.011, CO 570.009, CO 329B.004 January 7, 2016 Page 3 of 3 Now therefore it is ordered that: Part (d) of Rule 18 of CO 341F, part(d) of Rule 7 of CO 452, part (e) of Rule 4 of CO 45713, part (g) of Rule 4 of CO 471, part (d) of Rule 4 of CO 484A, Part (f) of Rule 4 of CO 505B, part (f) of Rule 4 of CO 559, and part (d) of Rule 6 of CO 570are revised as follows: The operator shall submit a review of pool production allocation factors and issues over the prior year with the annual reservoir surveillance report and retain electronic file(s) containing daily allocation data and daily test data for a minimum of five years. Rule 4 of CO 329B.003 is revised as follows: The operator shall submit a review of pool production allocation factors and issues over the prior year with the annual reservoir surveillance report and retain electronic file(s) containing daily allocation data and daily test data for a minimum of five years. Volumes reported on Form 10-405 in accordance with 20 AAC 25.230 (b) must break out Sag River Undefined Oil Pool and Niakuk Oil Pool allocated production within NK-43. DONE at Anchorage, Alaska and dated January 7, 2016. 5�, OIL,�o Cathy . Foerster Daniel T. Se ount, Jr. 0- Chair, Commissioner Commissioner 0�1, 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. Carlisle, Samantha J (DOA) From: Carlisle, Samantha J (DOA) Sent: Friday, January 08, 2016 12:51 PM To: Ballantine, Tab A (LAW) (tab.ballantine@alaska.gov); Bender, Makana K (DOA) (makana.bender@alaska.gov); Bettis, Patricia K (DOA) (patricia.bettis@alaska.gov); Bixby, Brian D (DOA); Brooks, Phoebe L (DOA) (phoebe.brooks@alaska.gov); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA) oody.colombie@alaska.gov); Cook, Guy D (DOA); Crisp, John H (DOA) oohn.crisp@alaska.gov); Davies, Stephen F (DOA) (steve.davies@alaska.gov); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA) (cathy.foerster@alaska.gov); Frystacky, Michal (michal.frystacky@alaska.gov); Grimaldi, Louis R (DOA) (lou.grimaldi@alaska.gov); Guhl, Meredith (DOA sponsored) (meredith.guhl@alaska.gov); Herrera, Matthew F (DOA); Hill, Johnnie W (DOA); Jones, Jeffery B (DOA) (Jeff Jones@alaska.gov); Kair, Michael N (DOA); Link, Liz M (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored) ooseph.mumm@alaska.gov); Noble, Robert C (DOA) (bob.noble@alaska.gov); Paladijczuk, Tracie L (DOA) (tracie.palad ijczuk@alaska.gov); Pasqual, Maria (DOA) (maria.pasqual@alaska.gov); Regg, James B (DOA) oim.regg@alaska.gov); Roby, David S (DOA) (dave.roby@alaska.gov); Scheve, Charles M (DOA) (chuck.scheve@alaska.gov); Schwartz, Guy L (DOA) (guy.schwartz@alaska.gov); Seamount, Dan T (DOA) (dan.seamount@alaska.gov); Singh, Angela K (DOA) (angela.singh@alaska.gov); Wallace, Chris D (DOA) (chris.wallace@alaska.gov); AKDCWellIntegrityCoordinator; Alan Bailey; Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew VanderJack; Anna Raff; Barbara F Fullmer, bbritch; Becky Bohrer; Bob Shavelson; Brian Havelock; Bruce Webb; Burdick, John D (DNR); Caleb Conrad; Carrie Wong; Cliff Posey; Colleen Miller; Crandall, Krissell; D Lawrence; Dave Harbour; David Boelens; David Duffy; David House; David McCaleb; David Steingreaber; David Tetta; Davide Simeone; ddonkel@cfl.rr.com; Dean Gallegos; Delbridge, Rena E (LAS); DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Frank Molli; Gary Oskolkosf; George Pollock; Gordon Pospisil; Gregg Nady; gspfoff, Hyun, James J (DNR); Jacki Rose; Jdarlington oarlington@gmail.com); Jeanne McPherren; Jennifer Williams; Jerry Hodgden; Jerry McCutcheon; Jim Watt; Jim White; Joe Lastufka; Joe Nicks; John Adams; John Easton; Jon Goltz; Juanita Lovett; Judy Stanek; Julie Houle; Julie Little; Kari Moriarty; Kazeem Adegbola; Keith Wiles; Kelly Sperback; Laney Vazquez; Laura Silliphant (laura.gregersen@alaska.gov); Leslie Smith; Lisa Parker; Louisiana Cutler; Luke Keller; Marc Kovak; Mark Dalton; Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Marquerite kremer (meg.kremer@alaska.gov); Mary Cocklan-Vendl; Michael Calkins; Michael Duncan; Michael Moora; Mike Bill; Mike Mason; Mikel Schultz; MJ Loveland; mkm7200; Morones, Mark P (DNR); Munisteri, Islin W M (DNR); nelson; Nichole Saunders; Nick W. Glover; Nikki Martin; NSK Problem Well Supv; Oliver Sternicki; Patty Alfaro; Paul Craig; Paul Decker (paul.decker@alaska.gov); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Renan Yanish; Richard Cool; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Skutca, Joseph E (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Stephen Hennigan; Steve Moothart (steve.moothart@alaska.gov); Suzanne Gibson; Tamera Sheffield; Tania Ramos; Ted Kramer; Temple Davidson; Terence Dalton; Teresa Imm; Thor Cutler; Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater; Anne Hillman; Brian Gross; Bruce Williams; Bruno, Jeff J (DNR); Caroline Bajsarowicz; Casey Sullivan; Diane Richmond; Don Shaw; Donna Vukich; Eric Lidji; Gary Orr; Graham Smith; Greg Mattson; Hak Dickenson; Heusser, Heather A (DNR); Holly To: Peat, Jason Bergerson; Jim Magill; Joe Longo; & Martineck; Josh Kindred; Kenneth Luckey; King, Kathleen J (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Marie Steele; Matt Armstrong; Mike Franger; Morgan, Kirk A (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Richard Garrard; Robert Province; Ryan Daniel; Sandra Lemke; Sarah Baker; Susan Pollard; Talib Syed; Terence Dalton; Tina Grovier (tmgrovier@stoel.com); Todd, Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster, William Van Dyke Subject: CO 505B.001, CO 457B.005, CO 341F.001, CO 471.008, CO 452.003, CO 484A.003, CO 559.011, CO 570.009, CO 329B.004 (PBU) Attachments: co505b-001.pdf, co457b-005.pdf, co341f-001.pdf; co471-008.pdf; co452-003.pdf; co484a-003.pdf, co559-011.pdf, co570-009.pdf; co329b-004.pdf Please see attached. Conservation Order 505B.001 Conservation Order 457B.005 Conservation Order 341F.001 Conservation Order 471.008 Conservation Order 452.003 Conservation Order 484A.003 Conservation Order 559.011 Conservation Order 570.009 Conservation Order 329B.004 Thank you, Samantha Carlisle I.�c=.cu€tic `cx la't+ir�� II:I Alaska Oil and Gas C'omse Miticm Cc>rnrnissi.ojtl 33.E West 7't' Avenue A.tzcho.ra�,e, AK 99501. i9o7) 793-12" 3 CONFIDENTIALITY NOTICE: This e-An:ail message, including any attachments, contains information from the :Alaska Oil. and Gas Conservation Conunission (AOCCC), State of Alaska and is for the sole use of the intended recipient(s). it inay contain confidential and/or privileged inforination. 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. AOCCC is aware of the .mistake in sending it to you, contact Sainantlia Carlisle at (907) 793-1223 or Samantha Carlislei2 alaska.Zov. • James Gibbs P.O. Box 1597 Soldotna, AK 99669 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 Jack Hakkila P.O. Box 190083 Anchorage, AK 99519 Penny Vadla 399 W. Riverview Ave. Soldotna, AK 99669-7714 Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Ms. Diane Richmond Darwin Waldsmith Performance and Data Management Lead, P.O. Box 39309 Alaska Reservoir Development Ninilchik, AK 99639 BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Angela K. Singh THE STATE °fALASKA GOVERNOR BILL WALKER Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL CONSERVATION ORDER NO.341F.001 Ms. Diane Richmond Performance and Data Management Lead Alaska Reservoir Development, BPXA BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Re: Docket Number: CO 16-013 Request for revisions to pressure survey and gas oil contact monitoring requirements, Rules 6(c) and 7(b) respectively, of Conservation Order 341F Prudhoe Bay Unit Prudhoe Oil Pool Dear Ms. Richmond; By letter dated May 24, 2016, BP Exploration (Alaska) Inc. (BPXA) requested amendment of conservation order 341 F (CO 341 F) to modify rules 6(c) and 7(b), which apply to bottom -hole pressure surveys and gas oil contact monitoring respectively. Specifically, BPXA requested authority to calculate bottom -hole pressures from surface data for wells on water injection and to use results of all neutron logs run, not just cased hole logs as currently required, for purposes of gas oil contact monitoring. BPXA's request is hereby granted. Rule 6(c) of CO 341 F currently states: Data from the surveys required in (a) and (b) of this rule shall be submitted with the Annual Prudhoe Oil Pool Reservoir Surveillance Report by April 1 each year. Data submitted shall include rate, pressure, time depths, temperature, and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 8800 feet subsea. Transient pressure surveys obtained by a shut in buildup test, an injection well pressure fall -off test, a multi rate test or an interference test are acceptable. Other quantitative methods may be administratively approved by the AOGCC. Extrapolating bottom -hole pressures from surface readings of shut in water injection wells will provide accurate information because water is a relatively incompressible fluid and the wellbore would contain a single phase. The proposed change will allow BPXA to gather reservoir performance data more readily and will aid in reservoir management. CO 341F.001 July 18, 2016 Page 2 of 3 Rule 7 of CO 341 F states: (a) Prior to initial sustained production, a cased or open hole neutron log shall be run in each well. This requirement is waived for waterflood/EOR areas encompassed by the expanded Prudhoe Bay Miscible Gas Project outlined in C.O. 290, and for those areas not expected to have significant GOC movement or gas encroachment from the gravity drainage area defined by the AOGCC through Administrative Approval. (b) A minimum of 40 repeat cased hole neutron log surveys shall be run annually. (c) The neutron logs run on any well and those required in (a) and (b) of this rule shall be filed with the AOGCC by the last day of the month following the month in which the logs were run. BPXA proposes to allow open hole neutron logs obtained under part (a) of this rule also to be used to meet the requirements of part (b) of the rule because open hole neutron logs acquired on new drill wells provide a more accurate data point than a cased hole log run on an active producer. Since the Prudhoe Oil Pool is a mature development a cased hole neutron log in an existing well would not provide as accurate a result as an open hole neutron log in a newly drilled well. Many wells completed near the gas oil contact are coning gas and when these wells are logged it is difficult to determine where the gas oil contact actually is. Logging across perforated intervals or when gas incursion into the wellbore exists can affect the accuracy of the tool, again impacting the ability to accurately determine the location of the gas oil contact. A gas oil contact monitoring requirement has been in place, in one form or another, since production began from the Prudhoe Oil Pool and the requirements of the program have been relaxed on numerous occasions as previous results have shown that a strict adherence to then existing requirements were no longer necessary to meet the intent of the gas oil contact monitoring program. After nearly 40 years of production, the movement of the gas oil contact is well understood and the requirement to conduct repeat cased hole neutron logs on 40 wells in addition to requiring a neutron log on all new wellbores prior to first production does not appreciably add to the understanding of the performance of the reservoir, especially given the suspect results of these. Therefore, granting BPXA's request to require 40 neutron logs per year and not requiring repeat cased hole neutron logs allows for adequate monitoring of gas oil contact movement. Rule 21 of CO 341F allows the AOGCC to administratively amend the order when the proposed changes do not promote waste, jeopardize correlative rights, are based on sound engineering and geoscience principles, and will not result in increased risk of fluid movement into freshwater. BPXA's proposed changes address only data gathering requirements and will not promote waste, jeopardize correlative rights, or risk contamination of fresh water. The proposed changes are based on sound engineering and geoscience principles. CO 34117.001 July 18, 2016 Page 3 of 3 Now therefore it is ordered: Rules 6(c) and 7(b) of conservation order 341 F are amended to read as follows: Rule 6(c): Data from the surveys required in (a) and (b) of this rule shall be submitted with the Annual Prudhoe Oil Pool Reservoir Surveillance Report by April 1 each year. Data submitted shall include rate, pressure, time depths, temperature, and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 8800 feet subsea. Transient pressure surveys obtained by a shut in buildup test, an injection well pressure fall -off test, a multi rate test or an interference test are acceptable. Calculation of bottom -hole pressures from surface data will be permitted for water injection wells. Other quantitative methods may be administratively approved by the AOGCC. Rule 7(b): A minimum of 40 neutron log surveys shall be run annually. Logs prescribed in (a) of this rule may be used to fulfill the minimum requirements. All other rules in C0341F remain unchanged. DONE at Anchorage, Alaska and dated July 18, 2016. Cathy . Fo ster Daniel T. �Seamount, Jr. Chair, Commissioner Commissioner TION 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. Colombie, Jody J (DOA) From: Colombie, Jody 1 (DOA) Sent: Monday, July 18, 2016 12:56 PM To: Ballantine, Tab A (LAW); Bender, Makana K (DOA); Bettis, Patricia K (DOA); Bixby, Brian D (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Cook, Guy D (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Herrera, Matthew F (DOA); Hill, Johnnie W (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); Pasqua[, 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); AKDCWellIntegrityCoordinator; Alan Bailey; Alex Demarban; Alexander Bridge; Allen Huckabay; Amanda Tuttle; Andrew VanderJack; Anna Raff; Barbara F Fullmer; bbritch; bbohrer@ap.org; Bill Bredar; Bob Shavelson; Brian Havelock; Bruce Webb; Burdick, John D (DNR); Caleb Conrad; Candi English; Colleen Miller, Crandall, Krissell; D Lawrence; Dale Hoffman; Dave Harbour; David Boelens; David Duffy, David House; David McCaleb; David Tetta; ddonkel@cfl.rr.com; Dean Gallegos; Delbridge, Rena E (LAS); DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Frank Molli; Gary Oskolkosf, George Pollock; Gordon Pospisil; Greeley, Destin M (DOR); Gregg Nady; gspfoff, Hyun, James J (DNR); Jacki Rose; Jdarlington oar[ington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jerry McCutcheon; Jim Watt; Jim White; Joe Lastufka; Radio Kenai; Easton, John R (DNR); Jon Goltz; Juanita Lovett; Judy Stanek; Julie Houle; Julie Little; Karen Thomas; Kari Moriarty; Kazeem Adegbola; Keith Torrance; Keith Wiles; Kelly Sperback; Gregersen, Laura S (DNR); Leslie Smith; Louisiana Cutler; Luke Keller, Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Kremer, Marguerite C (DNR); Mary Cocklan-Vendl; Mealear Tauch; Michael Calkins; Michael Moora; MJ Loveland; mkm7200; Morones, Mark P (DNR); Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nick W. Glover; Nikki Martin; NSK Problem Well Supv; Oliver Sternicki; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Renan Yanish; Richard Cool; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Skutca, Joseph E (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Stephen Hennigan; Moothart, Steve R (DNR); Steve Quinn; Suzanne Gibson; sheffie[d@aoga.org; Ted Kramer; Davidson, Temple (DNR); Teresa Imm; Thor Cutler; Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; /o=SOA/ou=First Administrative Group/cn=Recipients/cn=kjking; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater; Anne Hillman; Assmann, Aaron A; Bajsarowicz, Caroline J; Brian Gross; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Don Shaw; Eric Lidji; Garrett Haag; Smith, Graham O (DNR); Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Holly Pearen; Jason Bergerson; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Kenneth Luckey; 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); 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 726 and CO 341F-001 Attachments: co726.pdf, co341f.001.pdf Please see attached: CO 726 The application of Hilcorp Alaska, LLC for a waiver of the requirement to provide complete separation of flow streams from separate pools as specified in 20 AAC 25.210 and authorization under 20 AAC 25.215(b) for downhole commingling of production in the Beaver Creek Unit 23 well (PTD 214-093). CO 341 F-001 Request for revisions to pressure survey and gas oil contact monitoring requirements, Rules 6(c) and 7(b) respectively, of Conservation Order 341F Prudhoe Bay Unit, Prudhoe Oil Pool. Jody,l. Co��m6ie A()O(iCC Specia( Assistant _;Alaska Oi(a11d(jas Coiiservation Conimissioll 333 West 7"' -Avenue 411c(orage, Alaska gg5o1 Off ice: (907) 793-1221 ,J`ax: (,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. Jack Hakkila Bernie Karl Gordon Severson P.O. Box 190083 K&K Recycling Inc. 3201 Westmar Cir. Anchorage, AK 99519 P.O. Box 58055 Anchorage, AK 99508-4336 Fairbanks, AK 99711 Penny Vadla 399 W. Riverview Ave. Soldotna, AK 99669-7714 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Ms. Diane Richmond Richard Wagner Performance and Data Management Lead P.O. Box 60868 Alaska Reservoir Development, BPXA Fairbanks, AK 99706 BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 �:<co_ L ol,t \-c, 2.c.)\l- 031- Sc* - Angela K. Singh THE STATE ''ALASKA GOVERNOR BILL WALKER Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL CONSERVATION ORDER NO.341F.002 (Corrected) Ms. Diane Richmond Performance and Data Management Lead Alaska Reservoir Development, BPXA BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Number: CO 16-013 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Request for revisions to pressure survey and gas oil contact monitoring requirements, Rules 6(c) and 7(b) respectively, of Conservation Order 341 F Prudhoe Bay Unit Prudhoe Oil Pool Dear Ms. Richmond: By letter dated May 24, 2016, BP Exploration (Alaska) Inc. (BPXA) requested amendment of conservation order 341 F (CO 341 F) to modify rules 6(c) and 7(b), which apply to bottom -hole pressure surveys and gas oil contact monitoring respectively. Specifically, BPXA requested authority to calculate bottom -hole pressures from surface data for wells on water injection and to use results of all neutron logs run, not just cased hole logs as currently required, for purposes of gas oil contact monitoring. BPXA's request is hereby granted. Rule 6(c) of CO 341 F currently states: Data from the surveys required in (a) and (b) of this rule shall be submitted with the Annual Prudhoe Oil Pool Reservoir Surveillance Report by April 1 each year. Data submitted shall include rate, pressure, time depths, temperature, and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 8800 feet subsea. Transient pressure surveys obtained by a shut in buildup test, an injection well pressure fall -off test, a multi rate test or an interference test are acceptable. Other quantitative methods may be administratively approved by the AOGCC. Extrapolating bottom -hole pressures from surface readings of shut in water injection wells will provide accurate information because water is a relatively incompressible fluid and the wellbore would contain a single phase. The proposed change will allow BPXA to gather reservoir performance data more readily and will aid in reservoir management. CO 34117.002 (Corrected) July 20, 2016 Page 2 of 3 Rule 7 of CO 341F states: (a) Prior to initial sustained production, a cased or open hole neutron log shall be run in each well. This requirement is waived for waterflood/EOR areas encompassed by the expanded Prudhoe Bay Miscible Gas Project outlined in C.O. 290, and for those areas not expected to have significant GOC movement or gas encroachment from the gravity drainage area defined by the AOGCC through Administrative Approval. (b) A minimum of 40 repeat cased hole neutron log surveys shall be run annually. (c) The neutron logs run on any well and those required in (a) and (b) of this rule shall be filed with the AOGCC by the last day of the month following the month in which the logs were run. BPXA proposes to allow open hole neutron logs obtained under part (a) of this rule also to be used to meet the requirements of part (b) of the rule because open hole neutron logs acquired on new drill wells provide a more accurate data point than a cased hole log run on an active producer. Since the Prudhoe Oil Pool is a mature development a cased hole neutron log in an existing well would not provide as accurate a result as an open hole neutron log in a newly drilled well. Many wells completed near the gas oil contact are coning gas and when these wells are logged it is difficult to determine where the gas oil contact actually is. Logging across perforated intervals or when gas incursion into the wellbore exists can affect the accuracy of the tool, again impacting the ability to accurately determine the location of the gas oil contact. A gas oil contact monitoring requirement has been in place, in one form or another, since production began from the Prudhoe Oil Pool and the requirements of the program have been relaxed on numerous occasions as previous results have shown that a strict adherence to then existing requirements were no longer necessary to meet the intent of the gas oil contact monitoring program. After nearly 40 years of production, the movement of the gas oil contact is well understood and the requirement to conduct repeat cased hole neutron logs on 40 wells in addition to requiring a neutron log on all new wellbores prior to first production does not appreciably add to the understanding of the performance of the reservoir, especially given the suspect results of these. Therefore, granting BPXA's request to require 40 neutron logs per year and not requiring repeat cased hole neutron logs allows for adequate monitoring of gas oil contact movement. Rule 21 of CO 341F allows the AOGCC to administratively amend the order when the proposed changes do not promote waste, jeopardize correlative rights, are based on sound engineering and geoscience principles, and will not result in increased risk of fluid movement into freshwater. BPXA's proposed changes address only data gathering requirements and will not promote waste, jeopardize correlative rights, or risk contamination of fresh water. The proposed changes are based on sound engineering and geoscience principles. CO 34117.002 (Corrected) July 20, 2016 Page 3 of 3 Now therefore it is ordered: Rules 6(c) and 7(b) of conservation order 341F are amended to read as follows: Rule 6(c): Data from the surveys required in (a) and (b) of this rule shall be submitted with the Annual Prudhoe Oil Pool Reservoir Surveillance Report by April 1 each year. Data submitted shall include rate, pressure, time depths, temperature, and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 8800 feet subsea. Transient pressure surveys obtained by a shut in buildup test, an injection well pressure fall -off test, a multi rate test or an interference test are acceptable. Calculation of bottom -hole pressures from surface data will be permitted for water injection wells. Other quantitative methods may be administratively approved by the AOGCC. Rule 7(b): A minimum of 40 neutron log surveys shall be run annually. Logs prescribed in (a) of this rule may be used to fulfill the minimum requirements. All other rules in C0341 F remain unchanged. DONE at Anchorage, Alaska and ted July P2, 2016. Cath P. Foerster Daniel T. Seamo nt, Jr. Chair, Commissioner Commissione 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. Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Wednesday, July 20, 201611:00 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); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Herrera, Matthew F (DOA); Hill, Johnnie W (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); AKDCWellIntegrityCoordinator, Alan Bailey; Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew VanderJack; Anna Raff; Barbara F Fullmer; bbritch; bbohrer@ap.org; Bill Bredar; Bob Shavelson; Brian Havelock; Bruce Webb; Burdick, John D (DNR); Caleb Conrad; Candi English; Colleen Miller, Crandall, Krissell; D Lawrence; Dale Hoffman; Dave Harbour, David Boelens; David Duffy; David House; David McCaleb; David Tetta; ddonkel@cfl.rr.com; Dean Gallegos; Delbridge, Rena E (LAS); DNROG Units (DNR sponsored); Donna Ambruz, Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Frank Molli; Gary Oskolkosf, George Pollock; Gordon Pospisil; Greeley, Destin M (DOR); Gregg Nady; gspfoff; Hyun, James 1 (DNR); Jacki Rose; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jerry McCutcheon; Jim Watt; Jim White; Joe Lastufka; Radio Kenai; Easton, John R (DNR); Jon Goltz; Juanita Lovett; Judy Stanek; Julie Little; Kari Moriarty; Kazeem Adegbola; Keith Torrance; Keith Wiles; Kelly Sperback; Gregersen, Laura S (DNR); Leslie Smith; Louisiana Cutler, Luke Keller; Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Kremer, Marguerite C (DNR); Mary Cocklan-Vendl; Mealear Tauch; Michael Calkins; Michael Moora; MJ Loveland; mkm7200; Morones, Mark P (DNR); Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nikki Martin; NSK Problem Well Supv; Oliver Sternicki; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Renan Yanish; Richard Cool; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; 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; Moothart, Steve R (DNR); Steve Quinn; Suzanne Gibson; sheffield@aoga.org; Ted Kramer; Davidson, Temple (DNR); Teresa Imm; Thor Cutler; Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; /o=SOA/ou=First Administrative Group/cn=Recipients/cn=kjking; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Anne Hillman; Assmann, Aaron A; Bajsarowicz, Caroline J; Brian Gross; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Don Shaw; Eric Lidji; Garrett Haag; Smith, Graham O (DNR); Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Holly Pearen; Jamie M. Long; Jason Bergerson; 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); 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: Corrected CO 341F-002 Attachments: co341f.002.pdf Please see attached: Docket Number: CO 16-013 Request for revisions to pressure survey and gas oil contact monitoring requirements, Rules 6(c) and 7(b) respectively, of Conservation Order 341 F Prudhoe Bay Unit Prudhoe Oil Pool _Iot.h/ J. C 01,11hic _A (jCC , pecia( Assistant Ahaska Orand ('as Conservation Commission 333 -Nest 7"` _Avenue Anctiorage, .;Alaska gg5oi 011 ice: (907) 793-1221 _fax:: (9)07) 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.cgov. Jack Hakkila Bernie Karl Gordon Severson P.O. Box 190083 K&K Recycling Inc. 3201 Westmar Cir. Anchorage, AK 99519 P.O. Box 58055 Anchorage, AK 99508-4336 Fairbanks, AK 99711 Penny Vadla 399 W. Riverview Ave. Soldotna, AK 99669-7714 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Ms. Diane Richmond Richard Wagner Performance and Data Management Lead P.O. Box 60868 Alaska Reservoir Development, BPXA Fairbanks, AK 99706 BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 Angela K. Singh THE STATE 'ALASKA GOVERNOR BILL WALKER Ms. Diane Richmond Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL CONSERVATION ORDER NO.341F.003 Reservoir Development Performance Team Leader BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Number: CO- 16-021 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.claska.gov Request for administrative waiver of neutron logging requirement for coil sidetrack well Prudhoe Bay Unit 15-16C (PTD 2161540) Prudhoe Bay Unit Prudhoe Oil Pool Dear Ms. Richmond: By letter dated December 8, 2016, BP Exploration (Alaska) Inc. (BPXA) requested an administrative waiver of the requirement of Rule 7(a) of Conservation Order (CO) No. 341 F, which requires an open- or cased -hole neutron log to be run, in certain portions of the pool, on newly drilled wells prior to sustained production for the purpose of gas oil contact (GOC) monitoring in the Prudhoe Oil Pool (POP). This request is DENIED. Permit to drill (PTD) 216-154 was issued on November 17, 2016 and authorized the drilling of coil sidetrack PBU 15-16C. The kickoff point for PBU 15-16C is at 13,300' MD in the existing PBU 15-16B wellbore. This kickoff point is in the cemented 4.5" production liner portion of the wellbore and is located approximately 1,000' MD below the 7" intermediate liner shoe. Since there is only one pipe string between the tool and the formation, a cased -hole neutron log run prior to drilling, or prior to completing, PBU 15-16C should provide acceptable results for determining the current location of the GOC in this wellbore. The 7" liner shoe in PBU 15-16B is located at approximately 8,170' TVDSS with a hole inclination of approximately 35°. The kick off point for PBU 15-16C is 8,612' TVDSS at a hole inclination of approximately 80°. Based on the GOC last observed in 2010 at 8,586' TVDSS prior to production from the PBU 15-16B well, the current GOC can be expected to be encountered at about 13,150' MD, which has a hole inclination of approximately 80°. Although 80' is too great for a conventional wireline run, a cased -hole neutron logging tool could be run on wireline with a tractor or run using coiled tubing to obtain an updated GOC for this portion of the pool. CO 341F.003 December 27, 2016 Page 2 of 2 Since it is possible to obtain a neutron log across the GOC for the proposed well, and since this portion of the pool appears to not have any direct measurements of the GOC within the past 6 years, BPXA's request for a waiver of the requirements of Rule 7(a) of CO 341 F is hereby' d. nn .. DONE at Anchorage, Alaska and dated December 27 2016. �• ` `1 4Cath Foerster Daniel T. amount Jr. Hollis French �Y Commissioner, Chair Commissioner Commissioner 00N rvo 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. ALASKA Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 aogcc.alaska.gov Ms. Diane Richmond ADMINISTRATIVE APPROVAL CONSERVATION ORDER NO.341F.003 Reservoir Development Performance Team Leader BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Number: CO- 16-021 Request for administrative waiver of neutron logging requirement for coil sidetrack well Prudhoe Bay Unit 15-16C (PTD 2161540) Prudhoe Bay Unit Prudhoe Oil Pool Dear Ms. Richmond: By letter dated December 8, 2016, BP Exploration (Alaska) Inc. (BPXA) requested an administrative waiver of the requirement of Rule 7(a) of Conservation Order (CO) No. 34117, which requires an open- or cased -hole neutron log to be run, in certain portions of the pool, on newly drilled wells prior to sustained production for the purpose of gas oil contact (GOC) monitoring in the Prudhoe Oil Pool (POP). This request is DENIED. Permit to drill (PTD) 216-154 was issued on November 17, 2016 and authorized the drilling of coil sidetrack PBU 15-16C. The kickoff point for PBU 15-16C is at 13,300' MD in the existing PBU 15-16B wellbore. This kickoff point is in the cemented 4.5" production liner portion of the wellbore and is located approximately 1,000' MD below the 7" intermediate liner shoe. Since there is only one pipe string between the tool and the formation, a cased -hole neutron log run prior to drilling, or prior to completing, PBU 15-16C should provide acceptable results for determining the current location of the GOC in this wellbore. The 7" liner shoe in PBU 15-16B is located at approximately 8,170' TVDSS with a hole inclination of approximately 35°. The kick off point for PBU 15-16C is 8,612' TVDSS at a hole inclination of approximately 80°. Based on the GOC last observed in 2010 at 8,586' TVDSS prior to production from the PBU 15-16B well, the current GOC can be expected to be encountered at about 13,150' MD, which has a hole inclination of approximately 80°. Although 80' is too great for a conventional wireline run, a cased -hole neutron logging tool could be run on wireline with a tractor or run using coiled tubing to obtain an updated GOC for this portion of the pool. CO 341F.003 December 27, 2016 Page 2 of 2 Since it is possible to obtain a neutron log across the GOC for the proposed well, and since this portion of the pool appears to not have any direct measurements of the GOC within the past 6 years, BPXA's request for a waiver of the requirements of Rule 7(a) of CO 341 F is hereby denied. OIL DONE at Anchorage, Alaska and dated December 27, 2016. G //signature on file// //signature on file// //signature on file// �ON Cathy P. Foerster Daniel T. Seamount, Jr. Hollis French Commissioner, Chair Commissioner Commissioner AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Tuesday, December 27, 2016 10:47 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, 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; 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, Hyun, James J (DNR); Jacki Rose; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; 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, Julie Little; 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; 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; Rena Delbridge; Renan Yanish; Richard Cool; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; 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; Davidson, Temple (DNR); Teresa Imm; Thor Cutler, Tim Jones; Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Umekwe, Maduabuchi P (DNR); Vinnie Catalano; Weston Nash; Whitney Pettus; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Assmann, Aaron A; Bajsarowicz, Caroline J; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Catie Quinn; Don Shaw; Eric Lidji; Garrett Haag; Smith, Graham O (DNR); Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Fair, Holly S (DNR); Holly Pearen; Jamie M. Long; Jason Bergerson; Jesse Chielowski; Jim Magill; Joe Longo; John Martineck, Josh Kindred; Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Franger, James M (DNR); Morgan, Kirk A (DNR); Umekwe, Maduabuchi P (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); Tostevin, Breck C (LAW); Wayne Wooster; William Van Dyke Subject: co341F-003 Attachments: co341F.003.pdf Re: Docket Number: CO- 16-021 Request for administrative waiver of neutron logging requirement for coil sidetrack well Prudhoe Bay Unit 15- 16C (PTD 2161540) Prudhoe Bay Unit Prudhoe Oil Pool Jodi/ _1. Cotolubie .AOG('C special _Assistalat Atask a 0it- and (jas Colasei,i)atlola Coimvissioii 333 141"est 7"' 'Avelaue -Ai achoi-age, .Ataska ORi('e: (�)07) 7.93-1221 .JCIX: (c)07) 276-7542 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jody Colombie at 907.793.1221 or iody.colombie@alaska.gov. Bernie Karl K&K Recycling Inc. Gordon Severson Penny Vadla P.O. Box 58055 3201 Westmar Cir. 399 W. Riverview Ave. Fairbanks, AK 99711 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 George Vaught, Jr. Darwin Waldsmith Richard Wagner P.O. Box 13557 P.O. Box 39309 P.O. Box 60868 Denver, CO 80201-3557 Ninilchik, AK 99639 Fairbanks, AK 99706 THE STATE fALASKA Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVAL CONSERVATION ORDER NO. 341F.003 (Reconsideration) Ms. Diane Richmond Reservoir Development Performance Team Leader BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Number: CO- 16-021 Application for reconsideration of Conservation Order No. 341 F.003 Prudhoe Bay Unit 15-16C (PTD 2161540) Prudhoe Bay Unit Prudhoe Oil Pool Dear Ms. Richmond: By letter dated and received January 17, 2017, BP Exploration (Alaska) Inc. (BPXA) requested the Alaska Oil and Gas Conservation Commission (AOGCC) reconsider Conservation Order No. (CO) 341F.003, which denied BPXA's request for a waiver, for the subject well, of the neutron logging requirements of Rule 7(a) of CO No. 341 F. Rule 7(a) requires an open- or cased -hole neutron log to be run, in certain portions of the pool, on newly drilled wells prior to sustained production for the purpose of gas -oil contact (GOC) monitoring in the Prudhoe Oil Pool. BPXA'S REQUEST for reconsideration is GRANTED. BPXA made a good faith effort to run a neutron log in PBU 15-16C as the AOGCC required when the waiver request was denied by CO 341F.003, but BPXA received no useful data due to tool failure. Requiring BPXA to attempt to rerun a neutron log in PBU 15-16C would be a large burden with little benefit. Therefore, BPXA's request for reconsideration is granted and its request for a waiver of the requirements of Rule 7(a) of CO 341F for well PBU 15-16C is hereby granted. DONE at Anchorage, Alaska and dated January 26, 2017. Cath P. Foerster Daniel T. Seamount, Jr. Commissioner, Chair Commissioner Hollis French Commissioner CO 341F.003 January 26, 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. T`I "I l S'I'A`1'I °'ALASKA Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 aogcc.alaska.gov ADMINISTRATIVE APPROVAL CONSERVATION ORDER NO. 341F.003 (Reconsideration) Ms. Diane Richmond Reservoir Development Performance Team Leader BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Number: CO- 16-021 Application for reconsideration of Conservation Order No. 341F.003 Prudhoe Bay Unit 15-16C (PTD 2161540) Prudhoe Bay Unit Prudhoe Oil Pool Dear Ms. Richmond: By letter dated and received January 17, 2017, BP Exploration (Alaska) Inc. (BPXA) requested the Alaska Oil and Gas Conservation Commission (AOGCC) reconsider Conservation Order No. (CO) 341F.003, which denied BPXA's request for a waiver, for the subject well, of the neutron logging requirements of Rule 7(a) of CO No. 341F. Rule 7(a) requires an open- or cased -hole neutron log to be run, in certain portions of the pool, on newly drilled wells prior to sustained production for the purpose of gas -oil contact (GOC) monitoring in the Prudhoe Oil Pool. BPXA'S REQUEST for reconsideration is GRANTED. BPXA made a good faith effort to run a neutron log in PBU 15-16C as the AOGCC required when the waiver request was denied by CO 341F.003, but BPXA received no useful data due to tool failure. Requiring BPXA to attempt to rerun a neutron log in PBU 15-16C would be a large burden with little benefit. Therefore, BPXA's request for reconsideration is granted and its request for a waiver of the requirements of Rule 7(a) of CO 341F for well PBU 15-16C is hereby granted. DONE at Anchorage, Alaska and dated January 26, 2017. //signature on file// //signature on file// //signature on file// Cathy P. Foerster Daniel T. Seamount, Jr. Hollis French Commissioner, Chair Commissioner Commissioner CO 341 F.003 January 26, 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. Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Thursday, January 26, 2017 3:21 PM To: DOA AOGCC Prudhoe Bay; Richmond, Diane M; 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; Dave Harbour, David Boelens; David Duffy; David House; David McCaleb; David McCraine; David Tetta; ddonkel@cfl.rr.com; DNROG Units (DNR sponsored); Donna Ambruz, Ed Jones; Elizabeth Harball; Elowe, Kristin; Evan Osborne; Evans, John R (LDZX); Gary Oskolkosf, George Pollock; Gordon Pospisil; Greeley, Destin M (DOR); Gretchen Stoddard; gspfoff, Hurst, Rona D (DNR); Hyun, James J (DNR); Jacki Rose; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jill Simek; Jim Watt; Jim White; Joe Lastufka; Radio Kenai; Burdick, John D (DNR); Easton, John R (DNR); Larsen, John M (DOR); John Stuart; Jon Goltz; Chmielowski, Josef (DNR); Juanita Lovett; Judy Stanek; Kari Moriarty; Kasper Kowalewski; Kazeem Adegbola; Keith Torrance; Keith Wiles; Kelly Sperback; Frank, Kevin J (DNR); Kruse, Rebecca D (DNR); Gregersen, Laura S (DNR); Leslie Smith; Lori Nelson; Louisiana Cutler, Luke Keller, Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Mealear Tauch; Michael Bill; Michael Calkins; Michael Moora; MJ Loveland; mkm7200; Mueller, Marta R (DNR); Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nikki Martin; NSK Problem Well Supv; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Renan Yanish; Richard Cool; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shahla Farzan; Shannon Donnelly, Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Skutca, Joseph E (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Stephanie Klemmer; Stephen Hennigan; Sternicki, Oliver R; Moothart, Steve R (DNR); Steve Quinn; Suzanne Gibson; sheffield@aoga.org; Ted Kramer, Temple Davidson; Teresa Imm; Thor Cutler, Tim Jones; Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Umekwe, Maduabuchi P (DNR); Vinnie Catalano; Well Integrity; Well Integrity, Weston Nash; Whitney Pettus; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Assmann, Aaron A; Bajsarowicz, Caroline J; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Catie Quinn; Don Shaw; Eric Lidji; Garrett Haag; Smith, Graham O (DNR); Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Fair, Holly S (DNR); Holly Pearen; Jamie M. Long; Jason Bergerson; Jesse Chielowski; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Franger, James M (DNR); Morgan, Kirk A (DNR); Umekwe, Maduabuchi P (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Richard Garrard; 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: Reconsideration CO 341F-003 Attachments: co341F.003.reconsideration.pdf Please see attached. Re: Docket Number: CO- 16-021 Application for reconsideration of Conservation Order No. 341 F.003 Prudhoe Bay Unit 15-16C (PTD 2161540) Prudhoe Bay Unit Prudhoe Oil Pool To�y_I. Co(ombie AO(�CC spec tat assistant A(as(a Oit aml (;as Conservation Commission 333 West 7"` .A)enue -AticHorage, Ataska 99501 Off i( e: (9)07) 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. 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. Darwin Waldsmith Richard Wagner P.O. Box 13557 P.O. Box 39309 P.O. Box 60868 Denver, CO 80201-3557 Ninilchik, AK 99639 Fairbanks, AK 99706 THE STATE 'ALASKA GOVERNOR BILL WALKER Ms. Diane Richmond Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL CONSERVATION ORDER 341F.004 Reservoir Development Performance Team Leader BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Number: CO- 16-023 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Request for administrative waiver of neutron logging requirement for coil sidetrack well Prudhoe Bay Unit 07-15B (PTD 2161230) Prudhoe Bay Unit Prudhoe Oil Pool Dear Ms. Richmond: By letter dated December 14, 2016, BP Exploration (Alaska) Inc. (BPXA) requested an administrative waiver of the requirement of Rule 7(a) of Conservation Order (CO) No. 341 F, which requires an open- or cased -hole neutron log to be run, in certain portions of the pool, on newly drilled wells prior to sustained production for the purpose of gas -oil contact (GOC) monitoring in the Prudhoe Oil Pool (POP). This request is APPROVED. Permit to Drill (PTD) 216-123, issued on October 10, 2016, authorized the drilling of coil sidetrack PBU 07-15B. The well was drilled, and regular production began November 17, 2016. A slickline neutron tool was not able to reach the GOC in this well, but the recorded log did establish gas down to 8827 feet true vertical depth subsea (TVDSS). There are four recent neutron logs recorded in wells surrounding the subject well at distances ranging from about 2,400 feet to about 5,800 feet. The GOC observed in these four wells ranges in depth from 8,925 to 8,905 feet TVDSS. These recent, nearby data points agree closely on GOC depth, so requiring another neutron log in the subject well would not add significant engineering or geologic knowledge for this area. Now therefore it is ordered that the neutron logging requirements of Rule 7(a) of CO 341F for the PBU 07-15B well are hereby waived. CO 341F.004 March 10, 2017 Page 2 of 2 DONE at Anchorage, Alaska and dated March 10, 2017. —datq P. Foerster Commissioner, Chair 'Daniel T. Seamount, Jr. Commissioner 0 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. THE STATE 'ALASKA GOVERNOR BILL. WALKER ADMINISTRATIVE APPROVAL CONSERVATION ORDER 341F.004 Ms. Diane Richmond Reservoir Development Performance Team Leader BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Number: CO- 16-023 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 aogcc.alaska.gov Request for administrative waiver of neutron logging requirement for coil sidetrack well Prudhoe Bay Unit 07-15B (PTD 2161230) Prudhoe Bay Unit Prudhoe Oil Pool Dear Ms. Richmond: By letter dated December 14, 2016, BP Exploration (Alaska) Inc. (BPXA) requested an administrative waiver of the requirement of Rule 7(a) of Conservation Order (CO) No. 341 F, which requires an open- or cased -hole neutron log to be run, in certain portions of the pool, on newly drilled wells prior to sustained production for the purpose of gas -oil contact (GOC) monitoring in the Prudhoe Oil Pool (POP). This request is APPROVED. Permit to Drill (PTD) 216-123, issued on October 10, 2016, authorized the drilling of coil sidetrack PBU 07-15B. The well was drilled, and regular production began November 17, 2016. A slickline neutron tool was not able to reach the GOC in this well, but the recorded log did establish gas down to 8827 feet true vertical depth subsea (TVDSS). There are four recent neutron logs recorded in wells surrounding the subject well at distances ranging from about 2,400 feet to about 5,800 feet. The GOC observed in these four wells ranges in depth from 8,925 to 8,905 feet TVDSS. These recent, nearby data points agree closely on GOC depth, so requiring another neutron log in the subject well would not add significant engineering or geologic knowledge for this area. Now therefore it is ordered that the neutron logging requirements of Rule 7(a) of CO 341 F for the PBU 07-15B well are hereby waived. CO 341 F.004 March 10, 2017 Page 2 of 2 DONE at Anchorage, Alaska and dated March 10, 2017. //signature on file// Cathy P. Foerster Commissioner, Chair //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 neat 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 3-\0- 2c�\� Singh, Angela K (DOA) From: Carlisle, Samantha J (DOA) Sent: Friday, March 10, 2017 8:07 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; Darci Horner; 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; Elwood Brehmer; Evan Osborne; Evans, John R (LDZX); George Pollock, Gordon Pospisil; Greeley, Destin M (DOR); Gretchen Stoddard; gspfoff, Hurst, Rona D (DNR); Hyun, James 1 (DNR); Jacki Rose; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jill Simek; Jim Watt; Jim White; Joe Lastufka; Radio Kenai; Burdick, John D (DNR); Easton, John R (DNR); Larsen, John M (DOR); John Stuart; Jon Goltz, Chmielowski, Josef (DNR); Juanita Lovett; Judy Stanek; Kari Moriarty, Kasper Kowalewski; Kazeem Adegbola; Keith Torrance; Keith Wiles; Kelly Sperback; Frank, Kevin J (DNR); Kruse, Rebecca D (DNR); Gregersen, Laura S (DNR); Leslie Smith; Lori Nelson; Louisiana Cutler, Luke Keller, Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Mealear Tauch; Michael Bill; Michael Calkins; Michael Moora; MJ Loveland; mkm7200; Motteram, Luke A; 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; 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; 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 1; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Catie Quinn; Corey Munk; 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 341F.004 (Prudhoe Bay Unit) Attachments: co341f.004.pdf Request for administrative waiver of neutron logging requirement for coil sidetrack well Prudhoe Bay Unit 07-15B (PTD 2161230). Samantha Carlisle Executive Secretary III Alaska Oil and Gas Conservation Commission 333 West 7h Avenue Anchorage, AK 99501 (907) 793-1223 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Samantha Carlisle at (907) 793-1223 or Samantha.Carhsle@alaska.&ov. THE STATE 'ALASKA GOVERNOR BILL WALKER Ms. Diane Richmond Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL CONSERVATION ORDER NO.341F.005 Reservoir Development Performance Team Leader BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Number: CO-16-024 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Request for administrative waiver of neutron logging requirement for coil sidetrack well Prudhoe Bay Unit 07-29E (PTD 2130010) Prudhoe Bay Unit Prudhoe Oil Pool Dear Ms. Richmond: By letter dated December 14, 2016, BP Exploration (Alaska) Inc. (BPXA) requested an administrative waiver of the requirement of Rule 7(a) of Conservation Order (CO) No. 341F, which requires an open- or cased -hole neutron log to be run, in certain portions of the pool, on newly drilled wells prior to sustained production for the purpose of gas -oil contact (GOC) monitoring in the Prudhoe Oil Pool (POP). This request is APPROVED. Permit to Drill (PTD) 213-001, issued January 11, 2013, authorized drilling of PBU 07-29E. The well was drilled and put on regular production in March 2013. The kickoff point for this redrilled well was estimated to be 48 feet true vertical depth subsea (TVDSS) below the regional GOC. A neutron log was attempted in the well, but it ran into an obstruction approximately 600 feet measured depth above the expected GOC. This obstruction was encountered in the original wellbore, above the kick-off point for the PBU 07-29E redrill. Due to the risk of getting a radioactive -sourced logging tool stuck in the well, BPXA made the decision not to make further attempts to acquire a neutron log in the subject. Since PBU 07-29E kicked off below the GOC and the entire target formation is below the GOC, obtaining a neutron log in PBU 07-29E to confirm the exact location of the GOC will be of no use determining where this well will be perforated, and it will not add significant engineering or geological knowledge for this area. Now therefore it is ordered that the neutron logging requirements of Rule 7(a) of CO 341 F for the PBU 07-29E well are hereby waived. CO 341F.004 May 10, 2017 Page 2 of 2 DONE at Anchorage, Alaska and dated May 10, 2017. Cathy . Foerster Ho 11 renc Commissioner, Chair 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. ,, A L A S K__A_ GOVERNOR BILL NVALKER. Ms. Diane Richmond Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL CONSERVATION ORDER NO.341F.005 Reservoir Development Performance Team Leader BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Number: CO-16-024 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 aogcc.alaska.gov Request for administrative waiver of neutron logging requirement for coil sidetrack well Prudhoe Bay Unit 07-29E (PTD 2130010) Prudhoe Bay Unit Prudhoe Oil Pool Dear Ms. Richmond: By letter dated December 14, 2016, BP Exploration (Alaska) Inc. (BPXA) requested an administrative waiver of the requirement of Rule 7(a) of Conservation Order (CO) No. 341 F, which requires an open- or cased -hole neutron log to be run, in certain portions of the pool, on newly drilled wells prior to sustained production for the purpose of gas -oil contact (GOC) monitoring in the Prudhoe Oil Pool (POP). This request is APPROVED. Permit to Drill (PTD) 213-001, issued January 11, 2013, authorized drilling of PBU 07-29E. The well was drilled and put on regular production in March 2013. The kickoff point for this redrilled well was estimated to be 48 feet true vertical depth subsea (TVDSS) below the regional GOC. A neutron log was attempted in the well, but it ran into an obstruction approximately 600 feet measured depth above the expected GOC. This obstruction was encountered in the original wellbore, above the kick-off point for the PBU 07-29E redrill. Due to the risk of getting a radioactive -sourced logging tool stuck in the well, BPXA made the decision not to make further attempts to acquire a neutron log in the subject. Since PBU 07-29E kicked off below the GOC and the entire target formation is below the GOC, obtaining a neutron log in PBU 07-29E to confirm the exact location of the GOC will be of no use determining where this well will be perforated, and it will not add significant engineering or geological knowledge for this area. Now therefore it is ordered that the neutron logging requirements of Rule 7(a) of CO 341 F for the PBU 07-29E well are hereby waived. CO 341F.004 May 10, 2017 Page 2 of 2 DONE at Anchorage, Alaska and dated May 10, 2017. //signature on file// Cathy P. Foerster Commissioner, Chair //signature on file// Hollis French Commissioner RECONSIDERATION AND APPEAL NOTICE 0 `2 770N CV 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 nm is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Bernie Karl K&K Recycling Inc. Gordon Severson Penny Vadla P.O. Box 58055 3201 Westmar Cir. 399 W. Riverview Ave. Fairbanks, AK 99711-0055 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 George Vaught, Jr. Darwin Waldsmith Richard Wagner P.O. Box 13557 P.O. Box 39309 P.O. Box 60868 Denver, CO 80201-3557 Ninilchik, AK 99639-0309 Fairbanks, AK 99706-0868 M-8 (: e CL 5- \2- 2C)17 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Thursday, May 11, 2017 10:34 AM To: DOA AOGCC Prudhoe Bay; 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; David Tetta; 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; MJ Loveland; mkm7200; Motteram, Luke A; 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; 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; 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; Bajsarowicz, Caroline J; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Catie Quinn; 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; 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; Bettis, Patricia K (DOA); 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; Bender, Makana 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) Subject: CO 341F-005 and CO 341F-006 (BPXA) Attachments: co341F.006.pdf; co341F.005.pdf Please see attached. Re: Docket Number: CO-16-024 Request for administrative waiver of neutron logging requirement for coil sidetrack well Prudhoe Bay Unit 07- 29E (PTD 2130010) Prudhoe Bay Unit Prudhoe Oil Pool Re: Docket Number: CO- 16-025 Request for administrative waiver of neutron logging requirement for coil sidetrack well Prudhoe Bay Unit G-27B (PTD 2150760) Prudhoe Bay Unit Prudhoe Oil Pool Jody J. CoCombie .AOGCC SpeciaCAssistant .ACaska OiCand Gas Conservation Commission 333 West 7" .Avenue Anchorage, .ACaska 995oi 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 GOVERNOR BILL WALKER Ms. Diane Richmond Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL CONSERVATION ORDER NO.341F.006 Reservoir Development Performance Team Leader BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.claska.gov Re: Docket Number: CO- 16-025 Request for administrative waiver of neutron logging requirement for coil sidetrack well Prudhoe Bay Unit G-27B (PTD 2150760) Prudhoe Bay Unit Prudhoe Oil Pool Dear Ms. Richmond: By letter dated December 14, 2016, BP Exploration (Alaska) Inc. (BPXA) requested an administrative waiver of the requirement of Rule 7(a) of Conservation Order (CO) No. 341F, which requires an open- or cased -hole neutron log to be run, in certain portions of the pool, on newly drilled wells prior to sustained production for the purpose of gas -oil contact (GOC) monitoring in the Prudhoe Oil Pool (POP). This request is APPROVED. Permit to Drill (PTD) 215-07, issued May 8, 2015, authorized the drilling of PBU G-27B. The well was drilled and put on regular production in September 2015. BPXA did not attempt to run a neutron log upon completion of this redrilled well for several reasons. First, the kick-off point for this redrill was estimated to be 40 feet true vertical below the regional GOC. Second, the GOC was expected to be encountered at a point in the original wellbore that is behind three strings of pipe, so it is doubtful that the neutron tool would record any reliable data. Finally, this redrilled well encountered oil over its entire length. Accordingly, it is unlikely that a neutron log in this well would provide reliable data, aid in identifying the GOC, or add significant engineering or geologic knowledge for this area. Now therefore it is ordered that the neutron logging requirements of Rule 7(a) of CO 341F for the PBU G- 27B well are hereby waived. DONE at Anchorage, Alaska and dated May 11, 2017. Cathy P. Foerster Hollis French Commissioner, Chair Commissioner CO 341F.004 May 11, 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. THE S`I'AT1.: A LASKA GOVERNOR BILL NVALKER ADMINISTRATIVE APPROVAL CONSERVATION ORDER NO.341F.006 Ms. Diane Richmond Reservoir Development Performance Team Leader BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 aogcc.alaska.gov Re: Docket Number: CO- 16-025 Request for administrative waiver of neutron logging requirement for coil sidetrack well Prudhoe Bay Unit G-27B (PTD 2150760) Prudhoe Bay Unit Prudhoe Oil Pool Dear Ms. Richmond: By letter dated December 14, 2016, BP Exploration (Alaska) Inc. (BPXA) requested an administrative waiver of the requirement of Rule 7(a) of Conservation Order (CO) No. 341 F, which requires an open- or cased -hole neutron log to be run, in certain portions of the pool, on newly drilled wells prior to sustained production for the purpose of gas -oil contact (GOC) monitoring in the Prudhoe Oil Pool (POP). This request is APPROVED. Permit to Drill (PTD) 215-07, issued May 8, 2015, authorized the drilling of PBU G-27B. The well was drilled and put on regular production in September 2015. BPXA did not attempt to run a neutron log upon completion of this redrilled well for several reasons. First, the kick-off point for this redrill was estimated to be 40 feet true vertical below the regional GOC. Second, the GOC was expected to be encountered at a point in the original wellbore that is behind three strings of pipe, so it is doubtful that the neutron tool would record any reliable data. Finally, this redrilled well encountered oil over its entire length. Accordingly, it is unlikely that a neutron log in this well would provide reliable data, aid in identifying the GOC, or add significant engineering or geologic knowledge for this area. Now therefore it is ordered that the neutron logging requirements of Rule 7(a) of CO 341 F for the PBU G- 27B well are hereby waived. DONE at Anchorage, Alaska and dated May 11, 2017. //signature on file// //signature on file// Cathy P. Foerster Hollis French Commissioner, Chair Commissioner CO 341 F.004 May 11, 2017 Page 2 of 2 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Bernie Karl K&K Recycling Inc. Gordon Severson Penny Vadla P.O. Box 58055 3201 Westmar Cir. 399 W. Riverview Ave. Fairbanks, AK 99711-0055 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 George Vaught, Jr. 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, May 11, 2017 10:34 AM To: DOA AOGCC Prudhoe Bay; 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; David Tetta; 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; MJ Loveland; mkm7200; Motteram, Luke A; 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, 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; 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; Bajsarowicz, Caroline J; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Catie Quinn; 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; 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; Bettis, Patricia K (DOA); 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; Bender, Makana 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) Subject: CO 341F-005 and CO 341F-006 (BPXA) Attachments: co341F.006.pdf, co341F.005.pdf Please see attached. Re: Docket Number: CO-16-024 Request for administrative waiver of neutron logging requirement for coil sidetrack well Prudhoe Bay Unit 07- 29E (PTD 2130010) Prudhoe Bay Unit Prudhoe Oil Pool Re: Docket Number: CO- 16-025 Request for administrative waiver of neutron logging requirement for coil sidetrack well Prudhoe Bay Unit G-27B (PTD 2150760) Prudhoe Bay Unit Prudhoe Oil Pool Jody J. Co(ombie AO(CC Specia(Assistant .Alaska 0ifandgas Conservation Commission 333 West 7" Avenue Anchorage, Afaska 99501 Office: (907) 7,93-1221 Fax: (907) 276-7542 CONFIDENTIALITY NOTICE. This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jody Colombie at 907.793.1221 or iody.colombie@alaska.gov. THE STATE °fALASKA GOVERNOR BILL WALKER Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL CONSERVATION ORDER NO. 341F.007 Ms. Diane Richmond Performance and Data Management Lead Alaska Reservoir Development, BPXA BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Number: CO -17-017 Request for revisions to Rules 6, Prudhoe Bay Unit Prudhoe Oil Pool Dear Ms. Richmond: 333 west Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1 433 Fax 907.276.7542 www.00gcc.alaska.gov 7, 8, and 13 of Conservation Order 341 F By letter dated August 28, 2017, BP Exploration (Alaska) Inc. (BPXA) requested amendment of Conservation Order 341 F (CO 341 F) to modify rules 6, 7, 8, and 13, which apply to bottom -hole pressure surveys, gas -oil contact (GOC) monitoring, production logging, and gas -oil ratio (GOR) limits respectively. BPXA's request is hereby granted. Rule 6, Pressure Surveys, of CO 341F currently states: (a) Prior to regular production, a static bottom hole or transient pressure survey shall be taken on at least one in three wells drilled from a common drilling site. (b) An annual pressure surveillance plan shall be submitted to the AOGCC in conjunction with the Annual Prudhoe Pool Reservoir Surveillance Report by April 1, each year. The plan will contain the number of pressure surveys anticipated for the next calendar year and be subject to approval by the AOGCC by May 1. These surveys are needed to effectively monitor reservoir pressure in the Prudhoe Oil Pool. The surveys required in (a) of this rule may be used to fulfill the minimum requirements. (c) Data from the surveys required in (a) and (b) of this rule shall be submitted with the Annual Prudhoe Oil Pool Reservoir Surveillance Report by April 1 each year. Data submitted shall include rate, pressure, time depths, temperature, and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 8800 feet subsea. Transient pressure surveys obtained by a shut in buildup test, an injection well pressure fall-off test, a multi rate test or an interference test are acceptable. Calculation of bottom -hole pressures from surface data will be permitted for water injection wells. Other quantitative methods may be administratively approved by the AOGCC. CO 341 F.007 January 9, 2018 Page 2 of 5 (d) Results and data from any special reservoir pressure monitoring techniques, tests, or surveys shall also be submitted as prescribed in (c) of this rule. BPXA proposes eliminating part (a) and modifying the current part (b) to indicate that a minimum of five percent of the total number of pressure surveys conducted each year must be taken in each of the seven major development areas' within the Prudhoe Oil Pool. The Prudhoe Oil Pool is a mature development that has been under production for more than 40 years, and has multiple mature enhanced oil recovery (EOR) projects. The reservoir has been penetrated by, and logged within, more than 2,400 wells, has been extensively studied, and is well understood. A high-quality reservoir simulation model is used to evaluate development options. As such, there is little need for the pressure -survey data that are now collected primarily to meet the requirements of Rule 6 of CO 341F and are not relevant for effectively monitoring pool performance. At present, focusing BPXA's pressure -survey program on EOR project management is more important for minimizing waste and maximizing ultimate recovery than is routine collecting of field -wide pressure information. BPXA's requested modifications to Rule 6 of CO 341F should be adopted. Rule 7, Gas -Oil Contact Monitoring, of CO 341F currently states: (a) Prior to initial sustained production, a cased or open hole neutron log shall be run in each well. This requirement is waived for waterflood/EOR areas encompassed by the expanded Prudhoe Bay Miscible Gas Project outlined in C.O. 290, and for those areas not expected to have significant GOC movement or gas encroachment from the gravity drainage area defined by the AOGCC through Administrative Approval. (b) A minimum of 40 neutron log surveys shall be run annually. Logs prescribed in (a) of this rule may be used to fulfill the minimum requirements. (c) The neutron logs run on any well and those required in (a) and (b) of this rule shall be filed with the AOGCC by the last day of the month following the month in which the logs were run. BPXA proposes eliminating part (a) of Rule 7 and modifying part (b) to require a neutron logging plan to be submitted as part of the Annual Surveillance Report that is required under Rule 11 of CO 341 F. BPXA's reason for requesting to eliminate part (a) is that, after decades of production and injection activities, identifying a single gas -oil contact within the reservoir --or even within a given well --is difficult. This difficulty arises because sand layers within the reservoir are swept at different rates, and intervening shale layers within the pool can act as barriers to vertical flow. These two factors may result in multiple gas -oil contacts within the same area, and sometimes within the same wellbore. BPXA's proposal to eliminate the requirement to collect neutron logs in a minimum of 40 wells is based on the desire to move away from a requirement to collect neutron logs in an arbitrarily set number of wells and instead have flexibility to collect neutron logs at more appropriate locations within the pool to facilitate better reservoir management. ' The seven development areas are the gas cap, gravity drainage, Flow Station 2 water/MI flood (MWAG) project, eastern peripheral wedge zone MWAG project, western peripheral wedge zone MWAG project, Eileen west end waterflood project, and the northwest fault block MWAG project. CO 341F.007 January 9, 2018 Page 3 of 5 After 40 years of development, data collection, analysis, and reservoir modelling, the continued requirement to collect neutron logs on all wells drilled within the pool does not provide much meaningful information. In undisturbed portions of the pool, neutron logs recorded in newly drilled wells will provide useful information; however, the vast majority of current drilling within the pool occurs in areas of long-term production and injection activity. Additionally, a large portion of current wells are high -angle or horizontal redrills of existing wells. The presence of multiple casing strings in these redrilled wells may impact the ability of the neutron log to obtain useful information. Given these facts, the requirement to collect a minimum of 40 neutron logs per year no longer serves its intended purposes. Replacing the requirement to record a neutron log in all newly drilled wells and to collect a minimum of 40 neutron logs per year with a new requirement for annual AOGCC approval of an operator -submitted neutron logging plan for the Prudhoe Oil Pool will allow more accurate data collection and provide better reservoir management. Rule 8, Productivity Profiles, of CO 341F currently states: (a) A spinner flow meter or tracer survey shall be run in each well during the first six months the well is on production. This requirement is waived for wells completed with a single perforated interval, or with perforations in a single reservoir zone including highly deviated (greater than 65 degrees) and horizontal wells. (b) Follow-up surveys shall be performed on a rotating basis so that a new production profile is obtained on each well periodically. Nonscheduled surveys shall be run in wells which experience an abrupt change in water cut, gas -oil ratio, or productivity. (c) The complete spinner flow meter or tracer data and results shall be recorded and filed with the AOGCC by the last day of the month following the month in which each survey is taken. BPXA proposes to eliminate parts (a) and (b) of Rule 8 and to slightly modify current part (c). BPXA's reasoning is twofold. First, the Prudhoe Oil Pool as the only pool in the Prudhoe Bay Unit where these types of production profile surveys are required for every well. Second, due to the maturity of the field, BPXA believes spinner surveys provide little useful information for managing pool development. Regular well testing for production allocation purposes enables an operator to determine if the flow characteristics of a well have changed. If so, the operator can undertake diagnostic testing (e.g., spinner surveys, tracer survey, or setting plugs and testing zones by difference) to determine whether a given sand layer within the pool is the cause of the change. The operator can then take remedial action to improve flow from that layer. At this point running production profile surveys provides little meaningful data for managing pool development. Eliminating the requirement to conduct initial and periodic production -profile surveys in all wells and instead conducting them on an as -needed basis will provide more efficient pool management. Rule 13, Waiver of GOR Limitation, of CO 341 F currently states: The AOGCC waives the requirements of 20 AAC 25.240(b) for all oil wells in the Prudhoe Oil Pool of the Prudhoe Bay Field so long as the gas from the wells is being returned to the pool, or so long as the additional recovery project is in operation. CO 341 F.007 January 9, 2018 Page 4 of 5 In support of its request to amend Rule 13, BPXA notes that several wells in the Prudhoe Oil Pool can produce at rates exceeding 100,000 scf/stb but that these wells would not be defined as oil wells under 20 AAC 25.990(45). BPXA requested Rule 13 be modified to define oil wells for the Prudhoe Oil Pool as wells that may produce up to 200,000 scf/stb? BPXA states: "[P]rudent management to optimize liquid production within the capacities and constraints in the system will best occur with a higher GOR limit." This request is mainly an administrative one since operationally there are no constraints on producing the higher GOR wells due to the existing GOR waiver for the pool. In order to avoid confusion about whether or given well in the Prudhoe Oil Pool should be classified as an oil well or a gas well it is prudent to redefine the maximum GOR that an oil well can have in this pool. Now therefore it is ordered: Rules 6, 7, 8, and 13 of conservation order 341F are amended to read as follows: Rule 6 Pressure Surveys (Revised this Administrative Approval) (a) An Annual Pressure Surveillance Plan shall be submitted to the AOGCC in conjunction with the Annual Prudhoe Pool Reservoir Surveillance Report by April 1 of each year. This plan will contain the number and approximate location of pressure surveys anticipated for the next calendar year, and it will be subject to approval by the AOGCC by May 1 of that year. These surveys are needed to effectively monitor reservoir pressure within the Prudhoe Oil Pool. A minimum of 5% of the total pressure surveys acquired each year shall be from each of the following development areas: Gas Cap, Gravity Drainage, Flow Station 2 Water/MI Flood (MWAG) Project, Eastern Peripheral Wedge Zone MWAG Project, Western Peripheral Wedge Zone MWAG Project, Eileen West End Waterflood Project, and the Northwest Fault Block MWAG Project. (b) Data from the surveys required in (a) of this rule shall be submitted with the Annual Prudhoe Oil Pool Reservoir Surveillance Report by April 1 of each year. Data submitted shall include rate, pressure, time depths, temperature, and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 8800 true vertical feet subsea. Transient pressure surveys obtained by a shut-in buildup test, an injection well pressure fall-off test, a multi -rate test, or an interference test are acceptable. Calculation of bottom -hole pressures from surface data will be permitted for water injection wells. Other quantitative methods may be administratively approved by the AOGCC. (c) Results and data from any special reservoir pressure monitoring techniques, tests, or surveys shall also be submitted as prescribed in (b) of this rule. Rule 7 Gas -Oil Contact Monitoring (Revised this Administrative Approval) (a) An Annual GOC Monitoring Surveillance Plan shall be submitted to the AOGCC in conjunction with the Annual Prudhoe Reservoir Surveillance Report by April 1 of each Z The acronym for scf/stb means standard cubic feet per stock tank barrel. CO 341F.007 January 9, 2018 Page 5 of 5 year. This plan will contain the number and approximate locations of neutron log surveys anticipated for the next calendar year and be subject to approval by the AOGCC by May 1 of that same year. The neutron logs obtained shall be distributed across Gas Cap, Gravity Drainage, Gravity Drainage Waterflood Interaction, and downdip areas affected by gas and conducted using good engineering practice. (b) The neutron logs run on any well shall be filed with the AOGCC by the last day of the month following the month in which the logs were run. Rule 8 Productivity Profiles (Revised this Administrative Approval A complete copy of any spinner flow meter or tracer surveys obtained on wells, together with the data and results from the surveys, shall be recorded and filed with the AOGCC by the last day of the month following the month in which a survey is finalized. Rule 13 Waiver of GOR Limitation (a) The AOGCC waives the requirements of 20 AAC 25.240(b) for all oil wells in the Prudhoe Oil Pool of the Prudhoe Bay Field so long as the gas from the wells is being returned to the pool, or so long as the additional recovery project is in operation. (b) For the Prudhoe Oil Pool "oil well" means a well that produces oil at a gas -oil ratio of 200,000 scf/stb or lower. All other rules in C0341 F remain unchanged. DONE at Anchorage, Alaska and dated January 9, 2018. Hollis S. French Dan"Scamount,. Chair, Commissioner Commissioner AND 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 m the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determinedby it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to ran is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day THE STATE ALASKA GOVERNOR BILL WALKER Ms. Diane Richmond Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL CONSERVATION ORDER NO. 341F.007 Performance and Data Management Lead Alaska Reservoir Development, BPXA BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Number: CO -17-017 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 oogcc.alaska.gov Request for revisions to Rules 6, 7, 8, and 13 of Conservation Order 341F Prudhoe Bay Unit Prudhoe Oil Pool Dear Ms. Richmond: By letter dated August 28, 2017, BP Exploration (Alaska) Inc. (BPXA) requested amendment of Conservation Order 341F (CO 341F) to modify rules 6, 7, 8, and 13, which apply to bottom -hole pressure surveys, gas -oil contact (GOC) monitoring, production logging, and gas -oil ratio (GOR) limits respectively. BPXA's request is hereby granted. Rule 6, Pressure Surveys, of CO 341F currently states: (a) Prior to regular production, a static bottom hole or transient pressure survey shall betaken on at least one in three wells drilled from a common drilling site. (b) An annual pressure surveillance plan shall be submitted to the AOGCC in conjunction with the Annual Prudhoe Pool Reservoir Surveillance Report by April 1, each year. The plan will contain the number of pressure surveys anticipated for the next calendar year and be subject to approval by the AOGCC by May 1. These surveys are needed to effectively monitor reservoir pressure in the Prudhoe Oil Pool. The surveys required in (a) of this rule may be used to fulfill the minimum requirements. (c) Data from the surveys required in (a) and (b) of this rule shall be submitted with the Annual Prudhoe Oil Pool Reservoir Surveillance Report by April 1 each year. Data submitted shall include rate, pressure, time depths, temperature, and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 8800 feet subsea. Transient pressure surveys obtained by a shut in buildup test, an injection well pressure fall-off test, a multi rate test or an interference test are acceptable. Calculation of bottom -hole pressures from surface data will be permitted for water injection wells. Other quantitative methods may be administratively approved by the AOGCC. CO 341F.007 January 9, 2018 Page.2 of 5 (d) Results and data from any special reservoir pressure monitoring techniques, tests, or surveys shall also be submitted as prescribed in (c) of this rule. BPXA proposes eliminating part (a) and modifying the current part (b) to indicate that a minimum of five percent of the total number of pressure surveys conducted each year must be taken in each of the seven major development areas' within the Prudhoe Oil Pool. The Prudhoe Oil Pool is a mature development that has been under production for more than 40 years, and has multiple mature enhanced oil recovery (EOR) projects. The reservoir has been penetrated by, and logged within, more than 2,400 wells, has been extensively studied, and is well understood. A high-quality reservoir simulation model is used to evaluate development options. As such, there is little need for the pressure -survey data that are now collected primarily to meet the requirements of Rule 6 of CO 341F and are not relevant for effectively monitoring pool performance. At present, focusing BPXA's pressure -survey program on EOR project management is more important for minimizing waste and maximizing ultimate recovery than is routine collecting of field -wide pressure information. BPXA's requested modifications to Rule 6 of CO 341F should be adopted. Rule 7, Gas -Oil Contact Monitoring, of CO 341 F currently states: (a) Prior to initial sustained production, a cased or open hole neutron log shall be run in each well. This requirement is waived for waterflood/EOR areas encompassed by the expanded Prudhoe Bay Miscible Gas Project outlined in C.O. 290, and for those areas not expected to have significant GOC movement or gas encroachment from the gravity drainage area defined by the AOGCC through Administrative Approval. (b) A minimum of 40 neutron log surveys shall be run annually. Logs prescribed in (a) of this rule may be used to fulfill the minimum requirements. (c) The neutron logs run on any well and those required in (a) and (b) of this rule shall be filed with the AOGCC by the last day of the month following the month in which the logs were run. BPXA proposes eliminating part (a) of Rule 7 and modifying part (b) to require a neutron logging plan to be submitted as part of the Annual Surveillance Report that is required under Rule 11 of CO 341F. BPXA's reason for requesting to eliminate part (a) is that, after decades of production and injection activities, identifying a single gas -oil contact within the reservoir --or even within a given well --is difficult. This difficulty arises because sand layers within the reservoir are swept at different rates, and intervening shale layers within the pool can act as barriers to vertical flow. These two factors may result in multiple gas -oil contacts within the same area, and sometimes within the same wellbore. BPXA's proposal to eliminate the requirement to collect neutron logs in a minimum of 40 wells is based on the desire to move away from a requirement to collect neutron logs in an arbitrarily set number of wells and instead have flexibility to collect neutron logs at more appropriate locations within the pool to facilitate better reservoir management. ' The seven development areas are the gas cap, gravity drainage, Flow Station 2 water/MI flood (MWAG) project, eastern peripheral wedge zone MWAG project, western peripheral wedge zone MWAG project, Eileen west end waterflood project, and the northwest fault block MWAG project. CO 341F.007 January 9, 2018 Page 3 of 5 After 40 years of development, data collection, analysis, and reservoir modelling, the continued requirement to collect neutron logs on all wells drilled within the pool does not provide much meaningful information. In undisturbed portions of the pool, neutron logs recorded in newly drilled wells will provide useful information; however, the vast majority of current drilling within the pool occurs in areas of long-term production and injection activity. Additionally, a large portion of current wells are high -angle or horizontal redrills of existing wells. The presence of multiple casing strings in these redrilled wells may impact the ability of the neutron log to obtain useful information. Given these facts, the requirement to collect a minimum of 40 neutron logs per year no longer serves its intended purposes. Replacing the requirement to record a neutron log in all newly drilled wells and to collect a minimum of 40 neutron logs per year with a new requirement for annual AOGCC approval of an operator -submitted neutron logging plan for the Prudhoe Oil Pool will allow more accurate data collection and provide better reservoir management. Rule 8, Productivity Profiles, of CO 341F currently states: (a) A spinner flow meter or tracer survey shall be run in each well during the first six months the well is on production. This requirement is waived for wells completed with a single perforated interval, or with perforations in a single reservoir zone including highly deviated (greater than 65 degrees) and horizontal wells. (b) Follow-up surveys shall be performed on a rotating basis so that a new production profile is obtained on each well periodically. Nonscheduled surveys shall be run in wells which experience an abrupt change in water cut, gas -oil ratio, or productivity. (c) The complete spinner flow meter or tracer data and results shall be recorded and filed with the AOGCC by the last day of the month following the month in which each survey is taken. BPXA proposes to eliminate parts (a) and (b) of Rule 8 and to slightly modify current part (c). BPXA's reasoning is twofold. First, the Prudhoe Oil Pool as the only pool in the Prudhoe Bay Unit where these types of production profile surveys are required for every well. Second, due to the maturity of the field, BPXA believes spinner surveys provide little useful information for managing pool development. Regular well testing for production allocation purposes enables an operator to determine if the flow characteristics of a well have changed. If so, the operator can undertake diagnostic testing (e.g., spinner surveys, tracer survey, or setting plugs and testing zones by difference) to determine whether a given sand layer within the pool is the cause of the change. The operator can then take remedial action to improve flow from that layer. At this point running production profile surveys provides little meaningful data for managing pool development. Eliminating the requirement to conduct initial and periodic production -profile surveys in all wells and instead conducting them on an as -needed basis will provide more efficient pool management. Rule 13, Waiver of GOR Limitation, of CO 341F currently states: The AOGCC waives the requirements of 20 AAC 25.240(b) for all oil wells in the Prudhoe Oil Pool of the Prudhoe Bay Field so long as the gas from the wells is being returned to the pool, or so long as the additional recovery project is in operation. CO 341F.007 January 9, 2018 Page 4 of 5 In support of its request to amend Rule 13, BPXA notes that several wells in the Prudhoe Oil Pool can produce at rates exceeding 100,000 scf/stb but that these wells would not be defined as oil wells under 20 AAC 25.990(45). BPXA requested Rule 13 be modified to define oil wells for the Prudhoe Oil Pool as wells that may produce up to 200,000 scf/stb.2 BPXA states: "[P]rudent management to optimize liquid production within the capacities and constraints in the system will best occur with a higher GOR limit." This request is mainly an administrative one since operationally there are no constraints on producing the higher GOR wells due to the existing GOR waiver for the pool. In order to avoid confusion about whether or given well in the Prudhoe Oil Pool should be classified as an oil well or a gas well it is prudent to redefine the maximum GOR that an oil well can have in this pool. Now therefore it is ordered: Rules 6, 7, 8, and 13 of conservation order 341F are amended to read as follows: Rule 6 Pressure Surveys (Revised this Administrative Approval) (a) An Annual Pressure Surveillance Plan shall be submitted to the AOGCC in conjunction with the Annual Prudhoe Pool Reservoir Surveillance Report by April 1 of each year. This plan will contain the number and approximate location of pressure surveys anticipated for the next calendar year, and it will be subject to approval by the AOGCC by May 1 of that year. These surveys are needed to effectively monitor reservoir pressure within the Prudhoe Oil Pool. A minimum of 5% of the total pressure surveys acquired each year shall be from each of the following development areas: Gas Cap, Gravity Drainage, Flow Station 2 Water/MI Flood (MWAG) Project, Eastern Peripheral Wedge Zone MWAG Project, Western Peripheral Wedge Zone MWAG Project, Eileen West End Waterflood Project, and the Northwest Fault Block MWAG Project. (b) Data from the surveys required in (a) of this rule shall be submitted with the Annual Prudhoe Oil Pool Reservoir Surveillance Report by April l of each year. Data submitted shall include rate, pressure, time depths, temperature, and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 8800 true vertical feet subsea. Transient pressure surveys obtained by a shut-in buildup test, an injection well pressure fall-off test, a multi -rate test, or an interference test are acceptable. Calculation of bottom -hole pressures from surface data will be permitted for water injection wells. Other quantitative methods may be administratively approved by the AOGCC. (c), Results and data from any special reservoir pressure monitoring techniques, tests, or surveys shall also be submitted as prescribed in (b) of this rule. Rule 7 Gas -Oil Contact Monitoring (Revised this Administrative Approval) (a) An Annual GOC Monitoring Surveillance Plan shall be submitted to the AOGCC in conjunction with the Annual Prudhoe Reservoir Surveillance Report by April 1 of each z The acronym for scf/stb means standard cubic feet per stock tank barrel. CO 341F.007 January 9, 2018 Page 5 of 5 year. This plan will contain the number and approximate locations of neutron log surveys anticipated for the next calendar year and be subject to approval by the AOGCC by May 1 of that same year. The neutron logs obtained shall be distributed across Gas Cap, Gravity Drainage, Gravity Drainage Waterflood Interaction, and downdip areas affected by gas and conducted using good engineering practice. (b) The neutron logs run on any well shall be filed with the AOGCC by the last day of the month following the month in which the logs were run. Rule 8 Productivity Profiles (Revised this Administrative Approval A complete copy of any spinner flow meter or tracer surveys obtained on wells, together with the data and results from the surveys, shall be recorded and filed with the AOGCC by the last day of the month following the month in which a survey is finalized. Rule 13 Waiver of GOR Limitation (a) The AOGCC waives the requirements of 20 AAC 25.240(b) for all oil wells in the Prudhoe Oil Pool of the Prudhoe Bay Field so long as the gas from the wells is being returned to the pool, or so long as the additional recovery project is in operation. (b) For the Prudhoe Oil Pool `oil well" means a well that produces oil at a gas -oil ratio of 200,000 scf/stb or lower. All other rules in C0341 F remain unchanged. DONE at Anchorage, Alaska and dated January 9, 2018. //signature on file// Hollis S. French Chair, Commissioner //signature on file// Daniel T. Seamount, Jr Commissioner //signature on file// Cathy P. Foerster 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 fiuthef 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 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Tuesday, January 09, 2018 1:47 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); Foerster, Catherine P (DOA); French, Hollis (DOA); Frystacky, Michal (DOA); Guhl, Meredith D (DOA); Kair, Michael N (DOA); Link, Liz M (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Erickson, Tamara K (DOA); Wallace, Chris D (DOA); AK, GWO Projects Well Integrity; AKDCWelllntegrityCoordinator, Alan Bailey; Alex Demarban; Alicia Showalter; Allen Huckabay; Andrew Vandedack; Ann Danielson; Anna Raff; Barbara F Fullmer; bbritch; bbohrer@ap.org; Ben Boettger; Bill Bredar; Bob Shavelson; Brandon Viator, Brian Havelock; Bruce Webb; Caleb Conrad; Candi English; Cocklan-Vendl, Mary E; Cody Gauer•, Colleen Miller, Connie Downing; Crandall, Krissell; D Lawrence; Dale Hoffman; Danielle Mercurio; Darci Horner, Dave Harbour; David Boelens; David Duffy; David House; David McCaleb; David McCraine; ddonkel@cfl.rr.com; Diemer, Kenneth J (DNR); DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elizabeth Harball; Elowe, Kristin; Elwood Brehmer; Evan Osborne; Evans, John R (LDZX); Brown, Garrett A (DNR); George Pollock; Gordon Pospisil; Greeley, Destin M (DOR); Gretchen Stoddard; gspfoff; Hurst, Rona D (DNR); Hyun, James J (DNR); Jacki Rose; Jason Brune; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jill Simek; Jim Shine; Jim Watt; Jim White; Young, Jim P (DNR); Joe Lastufka; Radio Kenai; Burdick, John D (DNR); Easton, John R (DNR); Larsen, John M (DOR); John Stuart; Jon Goltz; Chmielowski, Josef (DNR); Juanita Lovett; Judy Stanek; Kari Moriarty, Kasper Kowalewski; Kazeem Adegbola; Keith Torrance; Keith Wiles; Kelly Sperback; Frank, Kevin J (DNR); Kruse, Rebecca D (DNR); Kyla Choquette; Gregersen, Laura S (DNR); Leslie Smith; Lori Nelson; Luke Keller, Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Michael Bill; Michael Calkins; Michael Moora; Michael Quick, Michael Schoetz; Mike Morgan; MJ Loveland; mkm7200; Motteram, Luke A; Mueller, Marta R (DNR); Nathaniel Herz; knelson@petroleumnews.com; Nichole Saunders; Nick Ostrovsky; NSK Problem Well Supv; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Renan Yanish; Richard Cool; Robert Brelsford; Robert Warthen; Sara Leverette; Scott Griffith; Shahla Farzan; Shannon Donnelly; Sharon Yarawsky; Skutca, Joseph E (DNR); Smith, Kyle S (DNR); Stephanie Klemmer; Stephen Hennigan; Sternicki, Oliver R; Moothart, Steve R (DNR); Steve Quinn; Suzanne Gibson; sheffield@aoga.org; Tanisha Gleason; Ted Kramer, Teresa Imm; Tim Jones; Tim Mayers; Todd Durkee; Tom Maloney, trmjrl; Tyler Senden; Umekwe, Maduabuchi P (DNR); Vinnie Catalano; Well Integrity, Well Integrity; Weston Nash; Whitney Pettus; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andy Bond; Bajsarowicz, Caroline J; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Corey Munk, Don Shaw, Eppie Hogan; Eric Lidji; Garrett Haag; Smith, Graham O (DNR); Heusser, Heather A (DNR); Fair, Holly S (DNR); Jamie M. Long; Jason Bergerson; Jesse Chielowski; Jim Magill; Joe Longo; John Martineck, Josh Kindred; Keith Lopez, Laney Vazquez, Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Melonnie Amundson; Franger, James M (DNR); Morgan, Kirk A (DNR); Umekwe, Maduabuchi P (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Rachel Davis, Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); William Van Dyke Subject: CO 341F.007 (Administrative Approval) Attachments: co341f.007.pdf Re: Docket Number: CO -17-017 Request for revisions to Rules 6, 7, 8, and 13 of Conservation Order 341F Prudhoe Bay Unit Prudhoe Oil Pool Jody J. CoCombie AOGCC SpeeiaCAssistant .Alaska OiCandGas Conservation Commission 333 Ivest 7 h .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.gov. Bernie Karl Gordon Severson Penny Vadla K&K Recycling Inc. 3201 Westmar Cir. 399 W. Riverview Ave. P.O. Box 58055 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Fairbanks, AK 99711 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 Ib f INDEXES 17 RECEIVED AUG 302017 AOGCC August 28, 2017 Via Email and US Mail Hollis French Commission Chair Alaska Oil and Gas Conservation Commission 333 West Th Avenue, Suite 100 Anchorage, AK 99501 BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Boz 196612 AnrAorage, AK 99519-6612 (907)561-5111 Re: Application for Administrative Approval Amendments to Conservation Order 341F Rules 6, 7, 8, and 13 Prudhoe Oil Pool Dear Chair French, BP Exploration (Alaska) Inc. (BPXA), as the operator of the Prudhoe Bay Unit (PBU), respectively requests that the Commission administratively approve the following amendments to Rules 6, 7, 8, and 13 of Conservation Order 341F. This administrative relief is sought under Rule 21 of the Conservation Order. These amendments are proposed with the goal of bringing the rules in tune with the Prudhoe Oil Pool's mature state, 40 years into field production. For the reasons discussed below, the rules do not align with current conditions in the reservoir, and in some cases are carry-overs from early field development that are no longer a good fit for a mature field. BP acknowledges and appreciates that the commission has periodically modified the Prudhoe Oil Pool's pool rules as field conditions have changed over the past 40 years. CO 341F was most recently modified in July, 2016. Proposed Amendments to Rule 6 Pressure Surveys BPXA proposes that the pressure survey requirement in Rule 6(a) be eliminated. The Prudhoe Pool is a mature field with a stabilized and predictable reservoir pressure, based on active ongoing offtake and injection management. The current requirement to obtain a pressure survey for "at least one in three wells drilled from a common drilling site" is often spread out over multiple years, and as a result it is not a useful means of informing the commission of reservoir pressures. A more beneficial approach would be to allow pressure surveys to be obtained as needed in support of reservoir management and drilling planning. Application for Administrative Approval Amendment of CO 341F Rules 6, 7, 8 and 13 August 28, 2017 With the proposed revision, the commission would still have the opportunity to review and approve the annual pressure surveillance plan submitted in the Annual Surveillance Report pursuant to Rule 6(b). BPXA therefore requests that the commission approve the following amendments to Rule 6 (requested deletions in strikethrough text and additions in underlined text): Rule 6 Pressure Surveys (ba) An annual pressure surveillance plan shall be submitted to the AOGCC in conjunction with the Annual Prudhoe Pool Reservoir Surveillance Report by April 1, each year. The plan will contain the number of pressure surveys anticipated for the next calendar year and be subject to approval by the AOGCC by May 1. These surveys are needed to effectively monitor reservoir pressure in the Prudhoe Oil Pool. A minimum of 5% of the total pressure surveys acquired each year shall be from each of the following field depletion areas: Gas Cap, Gravity Drainage, FS2, EPWZ, WPWZ, EWE, NWFB. in (a) ef-this Me may be use to fulfill the encs (el) Data from the surveys required in (a) of this rule shall be submitted with the Annual Prudhoe Oil Pool Reservoir Surveillance Report by April 1 each year. Data submitted shall include rate, pressure, time depths, temperature, and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 8800 feet subsea. Transient pressure surveys obtained by a shut in buildup test, an injection well pressure fall-off test, a multi rate test or an interference test are acceptable. Calculation of bottom -hole pressures from surface data will be permitted for water injection wells. Other quantitative methods may be administratively approved by the AOGCC. (dc) Results and data from any special reservoir pressure monitoring techniques, tests, or surveys shall also be submitted as prescribed in (b) of this rule. Proposed Amendments to Rule 7 Gas -Oil Contact Monitoring BPXA proposes that Rule 7(a) be eliminated. As mentioned in the 2016 PBU Annual Surveillance Report submitted to the commission, it has become increasingly difficult after 40 years of PBU production to define a single current gas -oil contact in most parts of the field. The gas -oil contact surface is commonly broken into a series of oil lenses and gas underruns beneath shales. While newly drilled wells offer the opportunity to acquire data under less disturbed conditions, there are many situations where the prescriptive language of Rule 7(a) would require an attempt to obtain a neutron log where data indicate no gas -oil contact is Page 2 of 5 Application for Administrative Approval Amendment of CO 341F Rules 6, 7, 8 and 13 August 28, 2017 anticipated, or where obtaining a gas -oil contact would require the well be shut-in longer than otherwise necessary with little to no benefit. Encroachment of gas into the waterflood/EOR area has occurred, thus obtaining some discretionary neutron logs in the waterflood/EOR area will help delineate the gas oil contact boundaries. In addition, while requiring a neutron log prior to initial sustained production in every new gravity drainage or gravity drainage waterflood interaction might be optimal, there are numerous situations at this stage of field life where this requirement does not provide new information about the area. Obtaining a reasonable number of neutron logs with areal distribution across the pool to support reservoir management, as well as in selected new wells, seems prudent. BPXA therefore requests that the commission approve the following amendments to Rule 7 (requested deletions in strikethrough text and additions in underlined text): Rule 7 Gas -Oil Contact Monitoring (Na) An annual GOC monitoring Surveillance plan shall be submitted to the AOGCC in conjunction with the Annual Prudhoe Reservoir Surveillance Report by April 1 each year. The plan will contain the number of neutron log surveys anticipated for the next calendar year and be subject to approval by the AOGCC by May 1. The logs obtained shall be distributed across the Gas Cap, Gravity Drainage, Gravity Drainage Waterflood Interaction- and downdip areas affected by gas using engineeringpractice. , � fninif•-..-.- of -40 ..,...,_ea log ,..,f.eys .,hall be fun a. mall.. Logs p .-ibe.7 :.. (a) of tlAs «..le may be used to fulfill the e..t.. vbo Yrvovaawu a (eb) The neutron logs run on any well and these required in (a) and (b` ert,a., nale shall be filed with the AOGCC by the last day of the month following the month in which the logs were run. Proposed Amendments to Rule 8 Productivity Profiles Conservation Order 341 F is the only PBU pool rule order that requires production profiles. While prescribed spinner flow meter surveys were useful during early field development, in the current phase of development they have reduced value for well and reservoir management. The right well conditions need to exist to obtain data of useful quality under representative flowing conditions. As production liners have slimmed, they have Page 3 of 5 .• . .. (Na) An annual GOC monitoring Surveillance plan shall be submitted to the AOGCC in conjunction with the Annual Prudhoe Reservoir Surveillance Report by April 1 each year. The plan will contain the number of neutron log surveys anticipated for the next calendar year and be subject to approval by the AOGCC by May 1. The logs obtained shall be distributed across the Gas Cap, Gravity Drainage, Gravity Drainage Waterflood Interaction- and downdip areas affected by gas using engineeringpractice. , � fninif•-..-.- of -40 ..,...,_ea log ,..,f.eys .,hall be fun a. mall.. Logs p .-ibe.7 :.. (a) of tlAs «..le may be used to fulfill the e..t.. vbo Yrvovaawu a (eb) The neutron logs run on any well and these required in (a) and (b` ert,a., nale shall be filed with the AOGCC by the last day of the month following the month in which the logs were run. Proposed Amendments to Rule 8 Productivity Profiles Conservation Order 341 F is the only PBU pool rule order that requires production profiles. While prescribed spinner flow meter surveys were useful during early field development, in the current phase of development they have reduced value for well and reservoir management. The right well conditions need to exist to obtain data of useful quality under representative flowing conditions. As production liners have slimmed, they have Page 3 of 5 Application for Administrative Approval Amendment of CO 341F Rules 6, 7, 8 and 13 August 28, 2017 been less conducive to running flow meters due to restriction imposed in high fluid and gas rates. In addition, in slim horizontal completions, testing by difference with plugs is often a more reliable measurement. Sundries are submitted to the commission for this work as the plug is often planned to leave in place as a profile modification if the rate change is beneficial. A more beneficial approach for managing the reservoir would be to allow spinner flow meters or tracer surveys to be obtained when needed to support profile modification and reservoir management decisions. BPXA therefore requests that the commission approve the following amendments to Rule 8 (requested deletions in strikethrough text and additions in underlined text): Rule 8 Productivity Profiles !te...... .re . _. _ _ - (e)—A complete copy of any spinner flow meter or tracer surveys obtained on wells, together with the data and results from the surveys, shall be recorded and filed with the AOGCC by the last day of the month following the month in which eaeka survey is finalized. Rule 13 Revision of GOR Limitation for an Oil Well As mentioned to senior petroleum engineer Dave Roby in December, 2015 and subsequently, BP is intermittently producing a few wells whose GORs exceed 100,000 scf/bbl. Looking to the future, as the field continues to mature, GORs will continue to rise. Prudent management to optimize liquid production within capacities and constraints in the system will best occur with a higher GOR limit. BP respectfully requests the commission approve the following amendments to Rule 13 (additions in underlined text): (a) The AOGCC waives the requirements of 20 AAC 25.240(b) for all oil wells in the Prudhoe Oil Pool of the Prudhoe Bay Field so long as the gas from the wells is being returned to the pool, or so long as the additional recovery project is in operation. Page 4 of 5 Application for AdmimaLfative Approval Amendment of CO 341 F Rules 6, 7, 8 and 13 August 28, 2017 (b) `oil well' means a well that produces oil at a gas -oil ratio of 200.000 scf/stb or lower. BPXA therefore respectfully requests that the commission administratively approve the requested amendments to Conservation Order 341F Rules 6, 7, 8, and 13. Should you have any questions regarding this application please contact Bill Bredar at 907-564-5348, William.bredar@bp.com. Sincerely, L� Diane Richmond Performance Manager Alaska Reservoir Development, BPXA cc: Mr. Eric Reinhold, ConocoPhillips Alaska, Inc Mr. Gerry Smith, ExxonMobil Alaska Production, Inc. Mr. Dave White, Chevron USA Page 5 of 5 16 December 16, 2016 Cathy P Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Ave, Suite 100 Anchorage, AK 99501 RECEIVED by DEC 2 1 2016 A0GG0 0 BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, AK 99519-6612 USA Main 907 564 5111 Re: Application For Administrative Waiver of Neutron Log Requirement Well G-2713, API 500292164602 Conservation Order 341 F (CO 341F) Rule 7 Prudhoe Oil Pool, Prudhoe Bay Unit Dear Chair Foerster: BP Exploration (Alaska), Inc. (BPXA), as operator of the Prudhoe Bay Unit and for the reasons addressed below in this application, respectfully requests that the commission waive the requirement to obtain a neutron log defining the gas -oil contact (GOC) for G-27B. BPXA requests that the commission exercise its authority under CO 341F Rule 21 to administratively grant the requested waiver. The neutron log requirement in CO 341 F Rule 7(a) states in part: "Prior to initial sustained production, a cased or open hole neutron log shall be run in each well." As the commission found in its July 20, 2016 Administrative Approval of CO 341 F.002 (Corrected): "A gas oil contact monitoring requirement has been in place, in one form or another, since production began from the Prudhoe Oil Pool and the requirements of the program have been relaxed on numerous occasions as previous results have shown that a strict adherence to then existing requirements were no longer necessary to meet the intent of the gas oil contact monitoring program". BPXA, in the course of a review of regulatory conformance, recently discovered that this well, which was put on production (POP'd) in September of 2015, did not attempt a neutron log. The reason was that: (1) the GOC was predicted to be well above the Kick Off Point (KOP) of the G-27B lateral, intersecting the parent well; and (2) the GOC in the parent well was expected at a location where there are three strings of casing where neutron response was predicted to be poor. Application For Administrative Waiver of Neutron Log Requirement CO 341F Rule 7, Coil Sidetrack Well G-27B December 16, 2016 Page 2 This application contains a 3D view of the pertinent wellbores with annotations, and the G- 27B Measured Depth Profile which shows the KOP (Kick off Point) approximately 40 vertical feet below the PGOC (Produced GOC, equivalent to regional GOC). The G-27B tagged HOT (Heavy Oil Tar) and logged oil over its entire length. The attached wellbore diagram also shows the approximate PGOC above the G-27B KOP. BPXA respectfully submits that obtaining a neutron log defining the GOC in this well is not technically justified, and requests that the commission administratively grant the waiver. Should you have any questions regarding this request please contact Bill Bredar at 907-564- 5348, William.bredar@bp.com. Sin rely, Diane Richmond Reservoir Development Performance Management Team Leader Application for Administrative Waiver of Neutron Log Requirement CO 341 F Rule 7, Coil Sidetrack Well G-27B API 500292164602 G-27B kicks out of parent wellbore G-27A @ 10,747.5' MD Estimated PGOC (from nearby analog wells):-8,934' TVDss (10,117' MD) by 8700 T 8750 I Zone 2C 8800 tom, a Zone 2BU G-27B Measured Depth Profile West Po�Ivnon —1 Zone 2C 2BU Fracture at 11,205' MD 8850 (-8,968.5' TVDss) Zone 261 Zone 281 .n Survey ------- Plan Psi Parent well G-27A PB2 Zone 2C Zone 2BU Zone 261 23SB 21TS East n Fault #1 Zone 2A 8900 11,626' MD (-8,957' TVDss) -15-20' DTN Throw, No Losses Associated I ? 893 - ------- - - - - - - Est.PGOC -- ------- - - - - - - t -�----- __ --- - -- 21N - ------- Est. PGOC - 8950 Parent Well G-27A Zone 2A KOP 2 @ 11,476' MD Zone 2A , ------- ----------- ---------- 21N �' o"�"-•._-,,. Cl- r"' T� 14M 3B .� �, .. ... .. .� .. HOT ... �..� ..A-— MOT _ — — — — 9000 14N Zone 1B Plugback 2 Zone iB TD @ 12,747' MD /-8,951' TVDss KOP @ 10,747.5' MD Zone 16 0 0 0 0 o O v oUcoo m s o O O O O o0 0 0 0 N ch V LL'1 0 0 0 0 0 0 0 (O f� m C. O O CC 0 O O O O O O O O CD Measured Depth Application for Administrative Waiver of Neutron Log Requirement CO 341F Rule 7, Coil Sidetrack Well G-27B API 500292164602 Application for Administrative Waiver of Neutron Log Requirement CO 341F Rule 7, Coil Sidetrack Well G-27B API 500292164602 •• - o-aia uW WEiLFfAU -- McEVOY ACTUATOR OTIS BB OKB, EL PV : 72 33' BF. E3IN = KOP= 2293' _ - CONDUCTOR, ? Max Angle = 97" @ 11568' # Datum MD 9254' ID -- DatumTVD= 88W'SS _— ESTIMATED TOC(05/17/15) ^2100' 13 3/8" CSG. 72#. L-8o, D= 12.347' 2693' 9-5/8" CSG, 47#, L-80 BUTT Xo TO NSCC 4214' 4-1/2' CMT SHEATH (05/31/15) 8136' - 8212' TUBNG PUNCH (04/24/15) $208' - 8210' Minimum ID = 1.81" @ 9934' 3-1/2" B K R LTP 5-112" TBGIPC, 17#, L-80, .0232 bpf, D = 4.892" - 8 7• TOP OF 5-1/2" LNR n-l--wnQ• �. L5/B�CSG, 47#, L-80 NSCC, NO= 8.681" $sJr6 ITDPOF LNR/ CEMENii:'i1 �-( e�n�• _ 151/2" EXTERNAL CSG PKR I- J�94d6_ TOP OF 2-3/8 LNR (CEMBJTED) �9946' _ 3- tl2" Ltd 9:i#, L-80 STL, .0087 bpt D = 2.992'10440• WHPSTOCK w/ RATAG @-10712' i 10702' 5-1/2" LNR, 17#, L-80, .0232 bpf,10 = 4.89Y-10702' aror 113 rwt Kt:H WHIPSTOCK w, RA TAG @ - 10747' 10752'(06/11/15) 1-3/16" LNR, 62#, L-80 TCA, .0076 bpf, D = 2.80' -10747 PERFORATION SUIWM iRY REF LOG: BKR HUGHES OH on 06/20/15 ANGLE AT TOP PERF: 89' @ 12270' Note: Refer to Production DB for historical pert data SIZE SPF NTBiVAL OPWSOZ DATE 1.56' 6 12210 - 12330 O 07/24/16 1.56" 6 12560 - 12680 C 09/06/15 1.56" 6 12680 - 12710 C 09/06/15 2-3/8" LNR, 4-7#, L-80 TH 511, .0039 bpf, to = 1.995' 127 [SAFETY NOT 1�GLE0�92990'- A1 G♦GL 207' S 1/2"0T6MNPD462 ? STr79607941i8 DEV TYPE VLV LATCH PORT DgTE 6 2 MCA DIY RK 0 09/06/10 5 1 CA DMY R< 0 04/07l13 4 1 CA DMY R< 0 01/02/92 3 7 CA DIY W 0 01/02/92 2 18 CA DIY RK 0 01/02/92 1 23 CA DMY RK 0 10/09/13 8184' 5-1/2" OTIS XA SLD SLV, D= 4.562" 8241' 9-518" x 5- 172" TM/ PKR w tSBR TBGSEALASSY, D=4.61" 8316' 5-1/2^ OTIS X NIP, D = 4.562" 8360' S 1/2" OTIS XN NP, D = 4.455" 8362' ELMD TT LOGGED 09/15/95 8407' BOT TIEBACK SLV W/O SEALS 8420' T X 51/2' LPSi XO, D = ' 9201' BTT TA83ACK SLV, D = 4.00(r 9207' 3.70' BOT DEPLOY SLV, D= 3.OW- - 9216' 31/2" HES X NP, D = 2.813' 9934' 31/2" BKR LTP, D = 1.81- (09/05/15) �^^ 2.70 DEPLOYMBVT SLV, D= 225" WIPER PLUG BUSI♦T1G @ 9957', W&LED TO 1.86-(09/04/15) 10440 3-112" X 3-3/16" XO, D= 2,786- (BEHMD L1 MILOUT MWOW (G-27A) 10703' - 10708' MILLOUT WDIDOW (G-278) 1074T - 10752'� approx PGOC 10,117' MD (-8,934' TVDss) 10939' 2-3/8"PUPJrw/RATAG G-27B KOP 10,747.5' MD (-8,978' TVDss) 12413' 2-3/8' PUP Jr w /RA TAG 12500' 2-318" BKRCBP(07/2 11161 I. 12710' I-i PBTD I DATE REV BY GOINHE ITS DATE REY BY JCF/JMDSET -- - OOMuENTS LTP& ADFERFS (09/05-06/15) CBPBADPERFS(07123-24/16) 09117/86 05I22107 ORIGINAL COMPLETION CTDSIDETRACK(G-27A) CTD(G-276) i 09109/151ATO/JMEISEr 07126/16 06122/15 1 06/23/15 JMD DRLG HO CORRECTDNS 06/24/15 09/09/15 KR(JMD ATO/J FI'JAL.ODEAPFROVAL _ tutd_L® WPQ2 PLUG (09/04/15) - PRUDHOE BAY UNIT WELL: G-27B PERMIT No: '2150760 AR No: 500.029-21646-02 Sec.12, T11N, R13E, 2541' FSL & 2368' FEL BP Exploration (Alaska) 15 December 14, 2016 Cathy P Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West 71 Ave, Suite 100 Anchorage, AK 99501 RECEIVED bp DEC 19 2016 AOGCC BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, AK 99519-6612 USA Main 907 564 5111 Re: Application For Administrative Waiver of Neutron Log Requirement Well 07-29E, API 500292178205 Conservation Order 341F (CO 341F) Rule 7 Prudhoe Oil Pool, Prudhoe Bay Unit Dear Chair Foerster: BP Exploration (Alaska), Inc. (BPXX), as operator of the Prudhoe Bay Unit and for the reasons addressed below in this application, respectfully requests that the commission waive the requirement to obtain a neutron log defining the gas -oil contact (GOC) for 07-29E. BPXA requests that the commission exercise its authority under CO 341F Rule 21 to administratively grant the requested waiver. The neutron log requirement in CO 341F Rule 7(a) states in part: "Prior to initial sustained production, a cased or open hole neutron log shall be run in each well." As the commission found in its July 20, 2016 Administrative Approval of CO 341F.002 (Corrected): "A gas oil contact monitoring requirement has been in place, in one form or another, since production began from the Prudhoe Oil Pool and the requirements of the program have been relaxed on numerous occasions as previous results have shown that a strict adherence to then existing requirements were no longer necessary to meet the intent of the gas oil contact monitoring program". BPXA, in the course of a review of regulatory conformance, recently discovered that this well, which was put on production (POP'd) in March of 2013, and kicked off below the regional GOC as established by the 07-29D, attempted a neutron log but experienced a very hard set down above the sidetracked subject wellbore, approximately 600' MD above the prognosed GOC, at approximately the junction of the upper liner and 2 3/8" liner. No damage was done to the tool, however due to risks associated with the sources in the hole, the possibility of the tool encountering issues again after a clean -out run, and the limited Zone I Application For Administrative Waiver of Neutron Log Requirement CO 341F Rule 7, Coil Sidetrack Well 07-29E December 14, 2016 Page 2 footage available (all of which would most likely be perfed no matter the fluid content), the decision was made to abandon further attempts to obtain the MCNL log. It is unknown if a waiver to not obtain the neutron log was submitted at the time, but BPXA is doing so now. This application contains the 07-29D well log showing the 07-29E kick off point (KOP) 48 vertical feet below the logged regional GOC depth. The 07-29E and 07-29D location map is also attached, with annotation. BPXA respectfully submits that further attempts to obtain a neutron log defining the GOC in this well were not justified at the time and are not now, and requests that the commission administratively grant the requested waiver. Should you have any questions regarding this request please contact Bill Bredar at 907-564- 5348, William.bredar@bp.com. Sincerely, Diane Richmond Reservoir Development Performance Management Team Leader Application for Administrative Waiver of Neutron Log Requirement CO 341 F Rule 7, Coil Sidetrack Well 07-29E API 500292178205 07-29D regional GOC depth 14N (11229' MD/8844' TVDss) Pcoc based on 2009 CNL [new drill neutron log] in Zone 1 B up 07-29E KOP 11448' MD in Zone 1A below regional GOC 07-29D [MDj GR SSTVD 0.00 hPi 150.04 _MII 1.656 Color fill 8722.7 11078 5 8741.6 11100 8786 11150 8824.2 11200 -----A20Ci 8857A 11250 8882.5) 1130Q= � G8897.11 11350 (8899.2) 11400 (8896.8) 11450 �.... (8M.6) 11550 (8892.9) 11568.4 14N -OF 48' TVD Application for Administrative Waiver of Neutron Log 8 Requirement CO 341 F Rule 7, Coil Sidetrack Well07-29E API g 500292178205 0 a 07-29E KOP 11448' MD in Zone 1A below regional GOC s btxM ., 675400 , 675600 . 675.M _ 676000 676M 676400 676M 676M iA f i 07 07-29E 67UM 675M 675600 676M 07-32A 678400 676800 676800 0 100 200 300 400 50 fMJS 13436 by 67nW 677400 677600 677s00 678M .BI 07116A 14 15-13A w a g w pNA O 677400 677600 677800 678000 Perforation Cbsed Open 2 14 BE January 17, 2017 Via Hand Delivery Cathy P. Foerster Commission Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 0 BP Exploration (Alaska) Inc. 900 E. Benson Boulevard Anchorage, AK 99508 P.O. Box 196612 Anchorage, AK 99519-6612 JAN 17 2017 Re: Docket Number: CO 16-021- Application for Reconsideration Denial of application for administrative waiver of neutron logging requirement Coil Sidetrack Well Prudhoe Bay Unit 15-16C (PTD 2161540) Prudhoe Oil Pool, Prudhoe Bay Unit Dear Chair Foerster: BP Exploration (Alaska) Inc. (BPXA), as operator of the Prudhoe Bay Unit (PBU), respectfully submits this Application for Reconsideration in the referenced matter. For the reasons discussed in this application, we respectfully submit that the commission's decision was in error. Chronology On November 17, 2016, the commission issued Permit to Drill Number 216-154, permitting referenced Well 15-16C as a sidetrack of Well 15-16B. On December 8, 2016, BPXA submitted an application for administrative waiver of the neutron log requirement for Well 15-16C (the Application for Waiver). A copy of the Application for Waiver is enclosed. BPXA's justification for the waiver was, in part, that the kick-off point for Well 15-16C was below the regional gas oil contact (GOC). On December 27, 2016, the commission issued the referenced order denying BPXA's Application for Waiver. On December 30, 2016, an attempt was made to obtain a neutron log while the coil drilling unit was on location. A memory neutron tool was run to TD of 15-16C. The tool came out of the hole with no data due to an internal logging tool failure. On January 12, 2017 the commission granted an extension of the time to file an application for reconsideration until January 23rd, 2017. Application for Reconsideration Docket Number: CO 16-021 Denial of application for administrative waiver of neutron logging requirement Coil Sidetrack Well Prudhoe Bay Unit 15-16C (PTD 2161540) January 17, 2017 Page 2 Discussion Regional GOC Context The gas oil contact (GOC) in the Ivishak Formation is no longer a planar horizontal interface extending across the Prudhoe Oil Pool. For the subject well, permeability contrast between Zone 1 and Zone 2 has had a significant influence on the level of the GOC. As the cross section in BPXA's Application for Waiver shows, the regional pre -production GOC displays a 58 foot total vertical depth (TVD) difference between Well 15-16B (parent well for Well 15-16C) and Well 15-27A. The 15-16C prospect's viability is based on the presence of oil in Zone 1A strata beneath a dipping (non -planar horizontal) regional GOC and regardless of what cones or gas breakouts may be present in offset produced wells. The GOC in producing Ivishak wells is subject to local cone/gas breakout. In fact, a neutron log was run in October, 2013 in the cased hole wellbore for Well 15-16B. However, BPXA determined that those log results were suspect, likely representing a local cone/gas breakout as is discussed below. BPXA's opinion is that the 2013 log did not provide regional GOC control. The Well 15-16C play concept and reservoir understanding are independent of local measurements of GOCs due to coning or gas breakout in offset wells. The PBU owners have invested in a play concept involving permeability contrast between Zone 1 and Zone 2 as the key controlling factor for the GOC level. This play concept is well documented in Prudhoe Bay in 2017, approximately 40 years after production began. Neutron Log Regulation Rule 7 of Conservation Order No. 341F (CO 341F) requires that a neutron log be obtained in new wellbores prior to initial sustained production. Rule 7(b) initially required a "minimum of 40 repeat cased hole neutron logs" be run annually. (Emphasis added.). Rule 7(b) was modified by the commission on July 20, 2016, in CO 341F.002, to delete the "repeat cased hole" requirement. The commission included the following statement in support of its decision: After nearly 40 years of production, the movement of the gas oil contact is well understood and the requirement to conduct repeat cased hole neutron logs on 40 wells in addition to requiring a neutron log on all new wellbores prior to first production does not appreciably add to the understanding of the performance of the reservoir, especially given the suspect results of these. (Emphasis added.) The subject Well 15-16C is a sidetrack of parent Well 15-16B. As noted, BPXA acquired a cased hole neutron log on Well 15-16B in October 2013. A copy of that log was previously provided to the commission in accordance with AOGCC regulations. Application for Reconsideration Docket Number: CO 16-021 Denial of application for administrative waiver of neutron logging requirement Coil Sidetrack Well Prudhoe Bay Unit 15-16C (PTD 2161540) January 17, 2017 Page 3 The 2013 Neutron Log The commission in its Order denying BPXA's Application for Waiver, states that this portion of the Prudhoe Oil Pool appears to not have any direct measurements of the GOC within the past 6 years. While it is true that the Regional GOC information is of 2010 vintage, as noted a neutron log was run in the 15-16B wellbore in October 2013 and logged a non -regional GOC of 8618' TVDss, (13,339' MD). That is essentially the same depth as the kick-off point (intended 13,300' MD, 8612' TVDss, actual 13,289' MD, 8610' TVDss) of Well 15-16C. This more recent data was not included in the Application for Waiver because BPXA determined that the results were not reflective of the regional GOC due to production, and are therefore suspect. BPXA's opinion is that acquisition of the required log is not germane to the goal of having control on the level of the regional GOC level. It does, however, bolster BPXA's opinion that repeat neutron logs in cased hole wells that have had offtake and associated gas breakout have suspect results, and such logs have no utility with respect to determination of the regional GOC. 15-16B Shut In History and Effect on GOC level A question was asked by AGOCC staff as to whether healing of the gas breakout/cone documented above in Well 15-16B may have occurred. The well has had intermittent production since April of 2015 but was on production as recently as October of 2016. It is BPXA's opinion that due to this recent production, a return to the original Regional GOC level will not have happened and therefore a new log will still obtain a cone GOC. Justification for Reconsideration BPXA respectfully submits the following as justification for this Application for Reconsideration: 1. The commission's Order requires BPXA to obtain a neutron log at a location outside of the Permit to Drill for Well 15-16C (i.e. in the parent well - Well 15-16B). 2. The commission's Order effectively requires BPXA to obtain a repeat cased hole neutron log (i.e. a repeat of the 2013 cased hole neutron log). The commission in CO 341F.002 eliminated the requirement to obtain repeat cased hole logs due to their inherent suspect nature. 3. It is impossible for BPXA to obtain a neutron log depicting the GOC in Well 15-16C, as the wellbore for Well 15-16C does not cross the Regional GOC boundary of -8586' TVDss. 4. The 2013 neutron log results in parent Well 15-16B are suspect as an indicator of the Regional GOC, and a repeat cased hole neutron log in the parent well would also be suspect. Application for Reconsideration Docket Number: CO 16-021 Denial of application for administrative waiver of neutron logging requirement Coil Sidetrack Well Prudhoe Bay Unit 15-16C (PTD 2161540) January 17, 2017 Page 4 5. In light of points 1-4 above, and in light of BPXA's good faith but unsuccessful attempt to obtain a neutron log on this well on December 30, 2016, it would be economically wasteful to require another attempt to obtain a neutron log. BPXA is planning another attempt to obtain a neutron log on the subject well in the very near future. BPXA therefore respectfully requests that the commission reconsider its order, on an expedited basis, and grant BPXA's application to waive the neutron log requirements for Well 15-16C. Sincerely, 14'� Aitwt-o Diane Richmond Reservoir Development Performance Management Team Leader BP Exploration (Alaska) Inc. Enclosure: BPXA Application for Waiver (amended for Confidentiality request for figures) Colombie, Jody J (DOA) From: Colombie, Jody 1 (DOA) Sent: Thursday, January 12, 2017 8:55 AM To: 'Bredar, William L' Subject: RE: co341F-003 On behalf of the Commissioners your request is GRANTED. Your application for reconsideration is due January 23, 2017. Jody From: Bredar, William L [ma ilto:William.Breda r@bp.com] Sent: Wednesday, January 11, 2017 4:29 PM To: Colombie, Jody J (DOA) <jody.colombie@alaska.gov> Subject: RE: co341F-003 Hi Jody, Further to this Administrative Approval, due to the fact that this notification was released on December 27, 2016 during a time when involved BP staff were not in the office due to the holiday season, BP requests an extension of the time to file an application for reconsideration until Monday, January 23rd, 2017. Thank you, FEE Bill Bredar State of Alaska Interactions, Alaska Surveillance Champion Performance Management Team BP Exploration (Alaska) Inc (907) 564-5348 - office (907) 227-7252 - mobile From: Colombie, Jody J (DOA)[mailto:jody.colombie@alaska.gov] Sent: Tuesday, December 27, 2016 10:47 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; AK, GWO SUPT Well Integrity; Alan Bailey; Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew VanderJack; Danielson, Ann (SLR); Anna Raff; Fullmer, Barbara (ConocoPhillips); bbritch; bbohrer@ap.org; Ben Boettger; Bredar, William L; 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; ZZPospisil, Gordon; Greeley, Destin M (DOR); Gretchen Stoddard; gspfoff; Hyun, James J (DNR); Jacki Rose; Jdarlington (jarlington(&gmail.com); Jeanne McPherren; Jerry Hodgden; Jim Watt; Jim White; Lastufka, Joseph N; Radio Kenai; Burdick, John D (DNR); Easton, John R (DNR); Larsen, John M (DOR); John Stuart; Goltz, Jon (ConocoPhillips); Chmielowski, Josef (DNR); Juanita Lovett; Judy Stanek; Little, Julie (ConocoPhillips); 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(-aanadarko.com); Mark Landt; Mark Wedman; Mealear Tauch; Michael Bill; Michael Calkins; Michael Moora; MI Loveland; mkm7200; Munisteri, Islin W M (DNR); knelson ftetroleumnews.com; Nichole Saunders; Nikki Martin; NSK Problem Well Supv (ConocoPhillips); Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Kanady, Randall (ConocoPhillips); Rena Delbridge; Renan Yanish; Richard Cool; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Donnelly, Shannon M (ConocoPhillips); Vestal, Sharmaine V (Northern Solutions); 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; Davidson, Temple (DNR); Teresa Imm; Thor Cutler; Tim Jones; Tim Mayers; Todd Durkee; trmjrl; Senden, Robert (ConocoPhillips); Umekwe, Maduabuchi P (DNR); Vinnie Catalano; Nash, Weston P; Pettus, Whitney; Aaron Gluzman; Sorrell, Aaron L; Ajibola Adeyeye; Dennis, Alan; Assmann, Aaron A; Bajsarowicz, Caroline J; Williams, Bruce A.; Bruno, Jeff J (DNR); Casey Sullivan; Catie Quinn; Don Shaw; Eric Lidji; Garrett Haag; Smith, Graham 0 (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; Daniel, Ryan; Lemke, Sandra D (ConocoPhillips); Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier(&stoel.com); Tostevin, Breck C (LAW); Wayne Wooster; William Van Dyke Subject: co341F-003 Re: Docket Number: CO- 16-021 Request for administrative waiver of neutron logging requirement for coil sidetrack well Prudhoe Bay Unit 15- 16C (PTD 2161540) Prudhoe Bay Unit Prudhoe Oil Pool .Iocil/ J. Coto mbie .AO( CC special Assistant -A(kllska oil-cani"t (jas Conservation Commission 333 11'est 7"'>>ent�e ,An fiol-age, _Alaska gg50a 01fiCe: (�)07) 7�)3-1221 ,fax: (907) 276-7542 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jody Colombie at 907.793.1221 or iody.colombie@alaska.gov. 13 by DECEIVED DEC 15 2016 AO A G0 90 East Benson Boulevard Inc. U900 East Benson Boulevard P. 0. Box 196612 Anchorage, Alaska 99519-6612 (907)561-5111 December 14, 2016 Cathy P Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Re: Application for: Administrative Waiver of Neutron Log Requirement Coil Sidetrack Well 07-15B, API 50-029-20847-02-00 Conservation Order 341 F (CO 341 F) Rule 7 Prudhoe Oil Pool, Prudhoe Bay Unit Dear Chair Foerster: BP Exploration (Alaska), Inc. (BPXA), as operator of the Prudhoe Bay Unit and for the reasons addressed below in this application, respectfully requests that the commission waive the requirement to obtain a neutron log defining the gas -oil contact (GOC) for 07-15B. BPXA respectfully submits that further neutron log attempts are not justified for this well, and requests that the commission exercise its authority under CO 341F Rule 21 to administratively grant the requested waiver. The neutron log requirement in CO 341 F Rule 7(a) states in part: "Prior to initial sustained production, a cased or open hole neutron log shall be run in each well." As the commission found in its July 20, 2016 Administrative Approval of CO 341 F.002 (Corrected): "A gas oil contact monitoring requirement has been in place, in one form or another, since production began from the Prudhoe Oil Pool and the requirements of the program have been relaxed on numerous occasions as previous results have shown that a strict adherence to then existing requirements were no longer necessary to meet the intent of the gas oil contact monitoring program". BPXA believes that requiring further neutron logging in 07-15B should not be required as set forth below. Two figures and one table are attached in support of this application. (1) a well cross section in the direction of the well's trajectory; and (2) a map of well and relevant GOC control. The table presents 4 local control points for the level of the regional GOC. Application For Administrative Waiver of Neutron Log Requirement CO 341F Rule 7, Coil Sidetrack Well 07-15B December 14, 2016 Page 2 This well was drilled and Put on Production (POP'd) from perforations in its toe (green line on attached wellbore section) with an Incremental Oil Rate (IOR) of 855 BOPD on November 17a' 2016, after neutron log data were acquired demonstrating gas to a depth of -8827' TVDss. The slickline conveyed neutron logging tool was not able to get deep enough to log the "lens GOC" (red dashed line at approximately -8850' TVDss on section), however it did result in the Gas Down To (GDT) depth which provided upside oil lens thickness information for Zone 2B (shaded green on section). With respect to the deeper regional GOC (dashed red line at approximately -8935' TVDss on the section), BPXA believes there is adequate local and recently acquired control for this contact to not require additional neutron logging at this time. The table shows nearby regional GOC picks, date acquired, distance from the subject well, and the GOC logged. The map shows the locations of the control points. Three of the four wells are between 2409' and 3007' feet from the subject well, and the fourth is 5814' away. Additionally, the closest well, 07-38, was recently logged, on 2 September 2016 with a GOC level of -8925' TVDss. The GOC data in the table are closely distributed and average -8917' TVDss; the section contains a more conservative (from an oil thickness perspective) interpreted GOC of -8935' TVDss. BPXA therefore respectfully submits that further attempts to obtain a neutron log defining any GOC in this well are not justified at this time, and respectfully requests that the commission administratively grant the requested waiver. Should you have any questions regarding this request please contact Bill Bredar at 907-564- 5348, William.bredar@bp.com. Sincerely, Diane Richmond Reservoir Development Performance Management Team Leader 07-15B Waiver Application: Relevant GOC Control 01-150 Waiver Application: Relevant GOC Control orewu ara6w 673600 674400 675M 676M 676800 / 0728 U -29 Al 43B07-13A 07 7-28 1 07 2016 07 28 iBB PM 2016 {905' TVDss 07 70 07-09A RPM 2016 -38 81925'TVDss , 7 07-0 0-0 A 07-0 07- 671200 872000 87280p 673600 674400 67S200 676000 676600 are" 679200 680000 7-7—� 0 -16 07-3 07- B.1 07-08A 2014 1: 678400 6722M aannnn WELL LOG DATE LOGGED DISTANCE FROM 07-15B (ft) GOC 07-38 RPM 2-Sep-16 2409 8925 07-08B RPM 2-Feb-14 2881 8919 07-286 IRPM 21-Mar-16 3007 8905 B-27C RPM 26-Jan-16 5814 8920 0 50C 0 MC 1250161S I i'd2< Application for Administrative Waiver of Neutron Log Requirement CO 341 F Rule 7, Coil Sidetrack Well 07-15B API 50-029-20847-02-00 1 by 07-15B MD Profile View nrr ��Stu1e — — XVP5 — —HOT South Polygon 8700 Zone 2C KOP 8982' MD 8740 } Possible fracture at 10,192' MD 8780 No losses I r ]1362 le fractures at j III r ' 9424' MD. • — I _....., No losses — �.. — 8820 Zone 26 i— I CI 8860 Zone 2A� - 22N t _ . 8900 1 i 8940 14N �.16/ .._ . — Zone 16 2 N 4; j Zone lA � -14 ._ > TD 11766' MD (8959' TVDss) Perforations t f 9020 Kavik U o 0 0 Measured Depth Updated onilJ9/2016at0600hrs Application for Administrative Waiver of Neutron Log Requirement CO 341 F Rule 7, Coil Sidetrack Well 07-15B API 50-029-20847-02-00 1► 12 by RECEIVED DEC 14 2016 ,AOGCC BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 December 8, 2016 Cathy P Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West r Ave, Suite 100 Anchorage, AK 99501 Re: Application For Administrative Waiver of Neutron Log Requirement Coil Sidetrack Well 15-16C, Permit to Drill 216-154 Conservation Order 341F (CO 341F) Rule 7 Prudhoe Oil Pool, Prudhoe Bay Unit Dear Chair Foerster: BP Exploration (Alaska), Inc. (BPX.4), as operator of the Prudhoe Bay Unit and for the reasons addressed below in this application, respectfully requests that the commission waive the neutron log requirement of CO 341F Rule 7(a) for the referenced coil sidetrack well. This well is scheduled to spud on December 14, 2016. In light of the expected spud date, BPXA requests that the commission exercise its authority under CO 341F Rule 21 to administratively grant the requested waiver. The neutron log requirement in CO 341F Rule 7(a) states in part: "Prior to initial sustained production, a cased or open hole neutron log shall be run in each well." As the commission found in its July 20, 2016 Administrative Approval of CO 341F.002 (Corrected): "A gas oil contact monitoring requirement has been in place, in one form or another, since production began from the Prudhoe Oil Pool and the requirements of the program have been relaxed on numerous occasions as previous results have shown that a strict adherence to then existing requirements were no longer necessary to meet the intent of the gas oil contact monitoring program". BPXA believes that application of Rule 7(a) to the subject well operation would not provide information that the rule is intended to gather, as: • It's Kick Off Point will be below the locally confirmed regional gas oil contact. • The confidence in the level of the regional gas oil contact is key to the viability of the 15-16C prospect. Without that confidence, the prospect would not be drilled. Application For Administrative Waiver of Neutron Log Requirement CO 341F Rule 7, Coil Sidetrack Well 15-16C, Permit to Drill 216-154 December 8, 2016 Page 2 Two figures are attached in support of this application: (1) a well cross section in the direction of the well's trajectory; and (2) a structure contour map on the top of Zone 1B, Ivishak reservoir. Annotations explain the fluid contact, local geology and well control. Due to the short timeframe before the required neutron log would have to be acquired, (anticipated 12/25), BPXA requests expedited consideration of this Administrative Approval. Should you have any questions regarding this request please contact Bill Bredar at 907-564- 5348, William.bredar@bp.com. Sincerely, \ L;V-e Diane Richmond Reservoir Development Performance Management Team Leader App 'i,cation ForAdministrative Waiverof Neutron Log Requirement CO 341 F Ru 'e 7, COI "Sidetrack We " 15-16C, Permit to Drill 216-154 674000 674500 675000 f 675-' '0' 6'6000 " Top Zone 1 B with original GOC contour (8572'TVDss). Cl is 50ft l77 - P z C. C. V-45D 1 "' 5 1 Pr}37A d� 0)c� 674000 674500 675000 675500 676000 676500 677000 677500 670-1 C� 67S500 679000 679.500 680000 680500 681000 68500 682000 682500 683M 683500 684000 Application For Administrative Waiver of Neutron Log Requirement 15-16C- coil sidetrack well targeting Zone 1A and 1 B reserves CO 341FRule 7, Coil Sidetrack Well 15-16C, Permit to Drill216-154 • 15-16C will kick out 26' below regional GOC. Obtaining a gas saturation log in 15-16C will not provide useful information that the team will use to update the regional GOC understanding West -8400 -8s00 -8600 c� Relevant regional GOC data for 15-16C Well Regional GOC depth (TVDss) Data type Date 15-16B -8586 New drill -Neutron density logs 2010 15-27A -8644 New drill- neutron density logs 2010 TARGET POLYGON 15-27A pre Regional GOC tracks 22N roduction GOC permeability contrast 8644' TVDss between Zone 1 and Zone 2 ZONE 2A ------�— ZONE 1B ZONE 1A 15-16 W /1 TD (16100' MD) 15-2 APB1 0 200 400 600 800 1000ftUS 1:6711 1600 2000 2400 2800 3200 3600 4000 F_- 0 s Y 0 N L, N 4400 15-16B pre production GOC 8586' TVDss 3 0 s 0 N /KOP 13300'MD, 8612' TVDss) LL proposed wellbore 4800 52W 5600 N 15-h6BPB1 6000 6400 East 11 by RECEIVED MAY 2 6 2016 0 BP Exploration (Alaska) Inc. A P. O.Box 196612 (V1 900 East Bensonenson Boulevard Anchorage, AK 99519-6612 May 24, 2016 Cathy Foerster Commission Chair Alaska Oil & Gas Conservation Commission 333 West 7`" Avenue, Suite 100 Anchorage, AK 99501 Re: Request for Administrative Approval Revisions to Conservation Order 341F Rules 6c and 7b Prudhoe Bay Oil Pool Dear Chair Foerster, BP Exploration (Alaska) Inc. (BP), as the Operator of the Prudhoe Bay Unit (PBU), respectfully requests that the Commission administratively approve the following revisions to Rules 6c and 7b of Conservation Order 341F. CO 341F Rule 6c Pressure Surveys BP requests that calculation of bottom -hole pressures from surface data be permitted for water injectors as a quantitative pressure survey method. Conservation Orders for several other pools already allow for this pressure measurement technique (e.g. CO 432D Rule 8c for Kuparuk River Oil Pool, CO 452 Rule 8c for Midnight Sun Oil Pool, CO 570 Rule 7d for Raven Oil Pool). This technique has proven to yield quality quantitative data used for making reservoir management decisions. This change will enable reservoir pressure data on injectors to be obtained more readily following a shut-in period. It will also provide improved consistency in acceptable reservoir pressure measurements across the BP operated oil pools. We therefore respectfully request that the Commission administratively approve a revision to CO 341F Rule 6c to permit the calculation of water injection well bottom hole pressures from surface data, so that the rule reads (requested revision in underlined bold text): Data from the surveys required in (a) and (b) of this rule shall be submitted with the Annual Prudhoe Oil Pool Reservoir Surveillance Report by April 1 each year. Data submitted shall include rate, pressure, time, depths, temperature, and any well condition necessary for the Request for AOGCC Administrative Approval Revisions to CO 341F Rule 6c and 7b May 24, 2016 Page 2 complete analysis of each survey. The datum for the pressure surveys is 8800 feet subsea. Transient pressure surveys obtained by a shut in buildup test, an injection well pressure fall -off test, a multi rate test or an interference test are acceptable. Calculation of bottom -hole Pressures from surface data will be Permitted for water infection wells. Other quantitative methods may be administratively approved by the AOGCC. CO 341F Rule 7b Gas -Oil Contact Monitoring BP requests that the Commission permit the use of all neutron logs obtained, whether cased hole or open hole, to fulfill the requirement of a minimum of 40 neutron logs obtained annually. This would effectively allow for neutron logs obtained as prescribed in (a) of this rule to be used to fulfill the minimum requirement of Rule 7b. BP seeks to prudently monitor gas -oil contacts (GOC) with a broad coverage through the use of all available high -quality gas -saturation logs. Often the best quality neutron logs can be obtained on new drill wells. Obtaining quality data using "repeat" cased hole logs as required by Rule 7b is becoming increasingly challenging due to influences from near- wellbore coning, perforations, and gas incursion into wellbore during logging. Prudhoe is a mature oil pool with a long history of neutron log data, indicating minimal GOC change in recent years. More flexibility in selection of wells used to obtain neutron logs in meeting this annual requirement will allow for better distributed coverage and more efficient use of resources. We therefore respectfully request that the Commission administratively approve a revision to CO 341F Rule 7b by deleting the "repeat cased hole" neutron log limitation, so that the rule reads (requested revision in underlined and bracketed strike through text): (a) Prior to initial sustained production, a cased or open hole neutron log shall be run in each well. This requirement is waived for waterflood/EOR areas encompassed by the expanded Prudhoe Bay Miscible Gas Project outlined in C.O. 290, and for those areas not expected to have significant GOC movement or gas encroachment from the gravity drainage area defined by the AOGCC through Administrative Approval. (b) A minimum of 40 [r-epeat eased hole' neutron log surveys shall be run annually. Logs Prescribed in (a) of this rule may be used to fulfill the minimum requirements. Request for AOGCC Administrative Approval Revisions to CO 341 F Rule 6c and 7b May 24, 2016 Page 3 (c) The neutron logs run on any well and those required in (a) and (b) of this rule shall be filed with the AOGCC by the last day of the month following the month in which the logs were run. Please direct any questions you may have to the undersigned or to Danielle Ohms at 907-564-5759, Danielle.Ohms@bp.com. Sincerely, Diane Richmond Performance and Data Management Lead Alaska Reservoir Development, BPXA 907-564-4136, Diane.Richmond@bp.com cc via email: Gilbert Wong, EMAP (gilbert.wong@exxonmobil.com) Jon Schultz, CPAI (Jon.Schultz@conocophillips.com) Phil Ayer, CUSA (pmayer@chevron.com) 10 RECEIVED NOV 0 4 2015 S BP Exploration (Alaska) Inc. 1(�,Jj 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907)561-5111 November 2, 2015 Cathy Foerster Commission Chair Alaska Oil & Gas Conservation Commission 333 West 7`' Avenue, Suite 100 Anchorage, AK 99501 Re: Request for Administrative Waiver of Monthly Reporting of Daily Production Allocation Data Dear Chair Foerster, BP Exploration (Alaska) Inc., as the Operator of the Prudhoe Bay Unit, respectfully requests that the Commission administratively waive the requirement in the following Conservation Orders (CO) Pool Rules, for monthly reports and files containing daily production allocation data: Schrader Bluff Oil Pool - CO 505B Rule 4f Aurora Oil Pool - CO 457B Rule 4e Prudhoe Oil Pool — CO 341 F Rule 18d Borealis Oil Pool - CO 471 Rule 4g Midnight Sun Oil Pool - CO 452 Rule 7d Polaris Oil Pool - CO 484 Rule 4d Put River Oil Pool - CO 559 Rule 4f Raven Oil Pool - CO 570 Rule 6d Niakuk Oil Pool -43 — CO 32913.003 Rule 4b BP will continue to collect the daily production allocation data and will provide the data to the Commission at any time upon request. BP will also continue to submit required monthly production data to the Commission through the 10-405 forms. We simply seek relief from the cost and burden of preparing the reports on a monthly basis. We have attempted to include in this request all Prudhoe Bay Unit oil pool Conservation Orders that contain a requirement for monthly reporting of daily Request for AOGCC AdW9trative Waiver November 2, 2015 Page 2 allocation data. If the Commission is aware of additional Conservation Orders containing this requirement, BP respectfully requests the opportunity to add them to this request. Please direct any questions you may have to the undersigned or to Caroline Bajsarowicz at 907-564-4314, Caroline.Bajsarowicz@bp.com. Sincerely, &,- Diane Richmond Performance and Data Management Lead Alaska Reservoir Development, BPXA 564-4136 Carlisle, Samantha J (DOA) From: Roby, David S (DOA) Sent: Wednesday, December 30, 2015 2:53 PM To: Carlisle, Samantha J (DOA) Subject: FW: Monthly Reporting of Daily Production Allocation Data Sorry I forgot to forward this sooner. Dave Roby (907)793-1232 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 Dave Roby at (907)793-1232 or dave.robv@alaska.gov. From: Richmond, Diane M [mailto:Diane.Richmond@bp.com] Sent: Wednesday, December 16, 2015 2:05 PM To: Roby, David S (DOA) Cc: Sorrell, Aaron L; Bajsarowicz, Caroline 3 Subject: RE: Monthly Reporting of Daily Production Allocation Data Dave, Thanks for your note. Actually you are correct in that we want to waive the first part of Rule 4 which was Rule 6 in C032913. BP as operator is asking for a waiver of the monthly report and file(s) containing daily allocation data, daily test data, results of geochemical analysis and results of production logs used for purposes of allocation. However, we will continue to report volumes on Form 10-405. 6. The operator shall submit a monthly report and file(s) containing daily allocation data, daily test data, results of geochemical analysis and results of production logs used for purposes of allocation. Volumes reported on Form 10-405 in accordance with 20 AAC 25.230 (b) must break out Sag River Undefined Oil Pool and Niakuk Oil Pool allocated production within NK-43. Let me know if you need additional information. Thanks Diane From: Roby, David S (DOA) [mailto:dave.roby(�balaska.gov] Sent: Tuesday, December 15, 2015 6:11 PM To: Richmond, Diane M Cc: Sorrell, Aaron L; Bajsarowicz, Caroline 3 Subject: RE: Monthly Reporting of Daily Production Allocation Data Diane and/or Caroline, I I'm putting the finishing touches onOadmin approval for this request and 1 haSquestion for you. In the request you asking us to waive Rule 4b in CO 32913.003. However the way I read this order there is no 4b. CO 32913.003 states that Rule 6 (which dealt with reporting results during the pilot test) of CO 329b is to be renumbered as Rule 4, but Rule 6 in CO 329B does not contain a part b. I just want to clarify what you actually want waived in this order. I presume it is the entirety of C032913.003 Rule 4. Please confirm this or let me know if it is just a portion of that rule that you want waive and if so which portion. Below are links to the orders. http://doa.alaska.gov/ogc/orders/co/co300 399/co329b-3.pdf http://doa.alaska.gov/ogc/orders/co/co300 399/co329b.pdf Regards, Dave Roby (907)793-1232 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 Dave Roby at (907)793-1232 or dave.roby@alaska.aov. From: Richmond, Diane M [mailto:Diane.Richmond(�bbp.com] Sent: Thursday, December 03, 2015 10:20 AM To: Roby, David S (DOA) Cc: Sorrell, Aaron L; Bajsarowicz, Caroline J Subject: RE: Monthly Reporting of Daily Production Allocation Data Thanks Dave. We will go ahead and complete the report. From: Roby, David S (DOA) [mailto:dave.roby@alaska.gov] Sent: Thursday, December 03, 2015 10:15 AM To: Richmond, Diane M Cc: Sorrell, Aaron L; Bajsarowicz, Caroline J Subject: RE: Monthly Reporting of Daily Production Allocation Data Diane, Working on your request was actually on my to do list for today. That said, we won't have a quorum of commissioners until the week of the 131h, so it's unlikely an official action will be taken until that time. While I don't expect there to be any issues with approving your request I cannot guarantee what the commissioners might say/decide, so to be safe you should probably go ahead and complete the report. Regards, Dave Roby (907) 793-1232 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 Dave Roby at (907)793-1232 or dave.roby@alaska.gov. From: Richmond, Diane M [ma ilto:DoRich mondCcbbp.com] • Sent: Thursday, December 03, 2015 8:55 AM To: Roby, David S (DOA) Cc: Sorrell, Aaron L; Bajsarowicz, Caroline J Subject: Monthly Reporting of Daily Production Allocation Data Dave, We are getting ready to prepare the Monthly State Satellites production report. Before completing this report, I wanted to understand the status of our Request for Administrative Waiver of Monthly Reporting of Daily Production Allocation Data sent to the AOGCC on Nov 2, 2015. Should we complete this report for the month of November to stay in compliance? Thanks for all of your help as we look to streamline, but also stay compliant with AOGCC orders. Diane Diane M. Richmond BP AK Reservoir Development Compliance SPA 907-564-4136 907-440-0835 (Cell) 0 0 • Dave Lachance Vice President Alaska Reservoir Development September 8, 2015 Via Hand Delivery Cathy P. Foerster Commission Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, AK 99508 USA Direct 907 564 4855 Mobile 907 538 1719 Main 907 564 5111 dave.lachance@bp.com SEP 0 8 2015 AOGCC Re: Docket Numbers: AIO 15-032 AIO 15-033 and CO 15-09, Prudhoe Oil Pool BPXA Post -Hearing Written Response to Commission Requests Consolidated Application for Amendment of Prudhoe Oil Pool Rule 9 and Modification of Prudhoe Bay Unit Area Injection Orders AIO 3A and AIO 4F Dear Chair Foerster: BP Exploration (Alaska) Inc. (BPXA) submits, on behalf of itself and ExxonMobil Production Inc., as applicants in the above referenced matter, the enclosed written response to Commission requests directed to BPXA during the hearing on August 27, 2015. Please note that the portion of our response contained in the Confidential Appendix is confidential, and BPXA requests that such information be held confidential pursuant to AS 31.05.035(d), 20 AAC 25.537(b), and AS 45.50.910 et seq., as well as Section 11.4 of the Prudhoe Bay Unit Agreement. The Confidential Appendix is enclosed in a separate envelope and marked confidential. S' cerely, liwte-C Dave P. Lachance Vice President, Reservoir Development Attachment BPXA Post -Hearing Responto Commission Requests • Application to Amend POP Rule 9 and Modify AIOs Page 2 September 8, 2015 cc via email: Ernesto Daza, BPXA (ernesto.daza@bp.com) John Dittrich, BPXA Oohn.dittrich@bp.com) George Lyle, Guess & Rudd (glyle@guessrudd.com) Chris Wyatt, BPXA (chris.wyatt@bp.com) Gilbert Wong, EMAP (gilbert.wong@exxonmobil.com) Gerry Smith, EMAP (Gerry.b.smith@exxonmobil.com) Steve Luna, EMAP (charles.s.luna@exxonmobil.com) Brian Gross, EMAP o.brian.gross@exxonmobil.com) Jon Schultz, CPAI (Jon.Schultz@conocophillips.com) Eric Reinbold, CPAI (Eric.W.Reinbold@conocophillips.com) John Evans, CPAI (John.R.Evans@conocophillips.com) Phil Ayer, CUSA (pmayer@chevron.com) Angie Bible, CUSA (abible@chevron.com) RECEIVED SEP 0 8 2015 AOGCC AOGCC Docket Numbers: AIO 15-032, AIO 15-033 and CO 15-09, Prudhoe Oil Pool Consolidated Application for Amendment of Prudhoe Oil Pool Rule 9 and Modification of Prudhoe Bay Unit Area Injection Orders AIO 3A and AIO 4F Post -hearing Response to Commission Questions INTRODUCTION At the hearing on August 27, 2015, on the referenced application by BP Exploration (Alaska) Inc. (BPXA) to the Alaska Oil and Gas Conservation Commission (AOGCC or Commission), the Commission asked BPXA to submit, post -hearing, responses to Commission requests for the following: 1. Analysis of a full field model (FFM) run or runs depicting the optimal start-up time for Prudhoe Oil Pool (POP) major gas sales (MGS) that is indifferent to specific project considerations; and 2. Analysis of a FFM run depicting the point in time when the BTU value of fuel gas usage is greater than the BTU value of the oil it's producing. (BPXA interprets this request by the Commission as a request for a comparative analysis of incremental oil recovery and incremental fuel gas usage resulting from pushing back the start-up of major gas sales, expressed in barrels of oil equivalent.) This submittal addresses each of these requests. I. OPTIMAL MGS START-UP DATES INDIFFERENT TO SPECIFIC PROJECT CONSIDERATIONS INTRODUCTION The classic petroleum engineering text book approach to greater ultimate recovery of an oil field with an original gas cap is to first target the oil for development while re -injecting the produced gas to maintain reservoir pressure. In this text book approach to hydrocarbon recovery, it is only after oil production is no longer economically viable that the gas is produced from the reservoir and sold. The logic behind this text book approach to hydrocarbon recovery is that if gas is sold too early the reservoir will lose pressure before oil production is optimized, and as a result total hydrocarbon recovery will be less than otherwise. This is how development of the POP has proceeded for 38 years. The POP has recovered significantly more oil than it would have without gas re -injection. However, the POP is entering a stage in which this simple text book approach to hydrocarbon recovery no longer reflects the complexities of POP development. That's because field development needs to consider several significant factors uniquely applicable to the POP: (1) availability of necessary infrastructure to support a gas export project; (2) fuel gas consumption; (3) facility life considerations; and (4) that the POP has acted similar to a gas field for more than two decades. For example, in a scenario in which a gas export project is available before oil development becomes un- economic, but would not be available at a later date, greater ultimate hydrocarbon recovery can only be achieved by proceeding with gas sales. The Alaska LNG Project is moving forward on a timeline targeting gas production for major gas sales from the POP potentially in 2025. There are no other gas sales projects proposed for sales of POP BPXA Post -Hearing Submission Page 1 of 7 0 • gas sooner than that date or at a later date. Since oil production and gas re -injection consumes fuel gas that could otherwise be sold and contribute to hydrocarbon recovery, by adjusting for fuel gas consumption, if a major gas sales project moves forward in 2025 greater ultimate recovery will likely occur through gas sales prior to oil development becoming un-economic. POP operations currently consume —400 MMSCFD, or approximately 25 million barrels oil equivalent (BOE) per year, of fuel gas to sustain oil production, whereas fuel gas requirements will be substantially reduced during major gas sales. As facilities age, equipment performance and reliability are factors that can impact production and ultimate hydrocarbon recovery. Oil production began from the POP in 1977 and with a MGS start-up in 2025 much of the Prudhoe Bay Unit production facilities will have been in operation for 50 years. Additionally, the landscape of existing supporting infrastructure and delivery systems is likely to change with time. The Commission's approval of BPXA's application in this matter is a necessary and critical step in trying to make POP major gas sales, through a large project such as the Alaska LNG Project it would support, successful. SUMMARY AND CONCLUSIONS Depending on the assumptions that are made, ultimate hydrocarbon recovery from the POP could potentially increase by up to 100 million BOE (MMBOE), less than 1 % of ultimate hydrocarbon recovery, if a comparable MGS project were to commence operations in 2040 rather than 2025 in the reference case. This is premised on the assumption that a POP MGS project is available at that time and advances, and that all necessary facilities, infrastructure and delivery systems have the same remaining capability at project start-up as the 2025 MGS reference case. However, there are unknown factors that could significantly undercut these assumptions including that a MGS opportunity may not be available, which would reduce overall potential hydrocarbon recovery by approximately 3.6 billion BOE. As mentioned, the Alaska LNG Project timeline targets potentially beginning operations in 2025 and if so then gas sales from the POP are estimated to total 22.4 TCF of gas, increasing ultimate hydrocarbon recovery from the POP by between 3.5 and 3.6 billion BOE. Even though there is a potential for slightly greater hydrocarbon recovery with a later MGS date, the complexity and significant financial commitments required to advance a MGS project of this magnitude and the risk of significantly lower ultimate recovery more than offset any potential gain. A later MGS start-up also increases the uncertainty that the project can deliver a full 30-year project life due to declining oil production and revenues which underpin the project, and due to increasing project risk from aging facilities which could reduce project life and thus ultimate recovery, reducing the potential incremental recovery relative to a 2025 start-up. A. BPXA's FFM RUNS 1. ASSUMPTIONS AND RISKS BPXA (as an individual working interest owner and not as operator) used its proprietary FFM tool (FFM Tool) to build FFM runs to assess the impact of starting MGS from the POP within a range of start-up dates: 2025, 2030, 2035 and 2040. BPXA used the following assumptions in running each case: BPXA Post -Hearing Submission Page 2 of 7 • Assumption: A project similar to the current AK LNG project is available to start-up at each of the different 5 year increments. Risk: A gas sales project is not available for POP major gas sales at a later date. Therefore, any additional recovery that may be assumed to be recovered by pushing back the start date for a project (<0.1 billion BOE), must be balanced against the risk of not recovering any of the gas (>3.5 billion BOE). • Assumption: All PBU oil and gas process facilities and TAPS are fully available for oil transportation and gas production for the length of the total production period with a 30 year MGS project period in all cases. Risk: Facilities used to produce the oil and gas will age over time and typically operate outside optimum design basis parameters, reducing the ability to recover the oil and gas indicated in the profiles. While the FFM runs account for well breakage and repair, it does not account for impacts due to facility or pipeline availability or performance, including TAPS.' As the facilities age, it is more likely that major equipment performance and reliability will affect oil and gas production. Directionally, there will be an increasingly greater impact on the gas sales cases with later start-up dates. The production profiles provided are not adjusted for any performance reduction factors associated with later major gas sales dates. 2. MODEL RUN PROFILES a. GAS DELIVERIES PROFILES The POP gas sales profiles (excluding CO2) for the 2025 (Reference Case), 2030, 2035 and 2040 start-ups are shown in Figure 1 in the Confidential Appendix to this submittal. The shape of these gas delivery profiles are similar, however, as start-up dates are extended, the plateau length decreases, from 21.0 to 19.6 years. The cumulative amount of gas delivered for sales decreases with each increment of extended start-up, from 22.4 TCF (2025 Start-up) to 20.9 TCF (2040 start-up), due to increased fuel gas consumption (see Table 1). b. OIL PRODUCTION PROFILES The POP liquid hydrocarbons (oil + NGLs) profiles for the oil reference case, and the 2025 (gas reference case), 2030, 2035 and 2040 start-ups are shown in Figure 2 in the Confidential Appendix to this submittal. Due to the drop in reservoir pressure at the onset of gas sales, oil production profiles correspondingly decline at a faster rate at the onset of gas sales, followed by a period of slower rate of decline. Liquid hydrocarbon recovery for the various cases is detailed in Table 1 and Table 2. C. FUEL GAS USAGE PROFILES Fuel gas is mainly consumed in the POP to generate electricity, heat fluids and facilities, pump fluids, and most significantly, compress the dry residue gas for reinjection. When gas sales begin from the POP, fuel usage will decrease as less compression is needed to send gas to the GTP rather than to re -inject the gas. As reservoir pressure declines and active well counts decrease over time, less fluid will be heated, pumped and compressed, and fuel usage will decrease further. These effects are accounted for in the FFM run forecasts of fuel gas usage shown in Figure 3 in the Confidential The FFM Tool is capable of performing this analysis, but BPXA has not run such cases. BPXA Post -Hearing Submission Page 3 of 7 Appendix to this submittal. The figure shows that a later start of gas sales results in higher total fuel usage. Once gas is used for fuel it is no longer available for gas sales; therefore, later start of major gas sales results in lower gas sales volumes. Total Hydrocarbon Profiles Figure 4 in the Confidential Appendix to this submittal shows oil and gas sales profiles combined into total hydrocarbon BOE profiles, assuming 1 barrel of oil is equivalent to 5.8 thousand standard cubic feet (MSCF) of gas. The POP BOE rate profiles in Figure 4 are the same as the oil reference case until the start of major gas sales, when total BOE production increases dramatically. Although gas sales rates are on plateau for approximately 20 years, total BOE delivery declines over that period due to declining oil production rates. At the end of the major gas sales plateau period, total BOE delivery rates drop more rapidly as both oil and gas sales rates are declining. B. ASSESSMENT OF ULTIMATE RECOVERY 1 . END OF FIELD LIFE Two methods to evaluate the end of field life (EOFL) were used in this study to evaluate ultimate hydrocarbon recovery: 1. Common gas sales project length 2. Common minimum total hydrocarbon production rate Ultimate hydrocarbon recovery for the suite of MGS start-up dates sensitivities are evaluated against each of the EOFL methodologies. 2. FULL FIELD MODEL PRECISION The resolution of the model is —+/- 10 Million barrels of oil recovery, and —+/- 30 Million BOE on gas sales, and —+/- 40 Million BOE of hydrocarbon recovery. FFM model precision was determined by running a series of simulation runs that were identical, except for a small perturbation to the inputs. The model precision quoted was determined from the range of this series of results. If simulation results from model runs of different scenarios are within these ranges of recovery, the impact of the sensitivity is not discernible from the uncertainty, and should not be used to inform decisions or rank scenarios. 3. UNACCOUNTED FOR RISKS TO ULTIMATE RECOVERY The following analysis does not account for two significant risks. These risks have a greater probability of occurrence as a MGS project start-up extends beyond 2025. 1. A major gas sales project may not be available to ship gas from POP at a later date. Therefore, any additional recovery that may be assumed to be recovered by a later project (<0.1 billion BOE), must be balanced against the risk of not recovering and selling any of the gas (>3.5 billion BOE). 2. Facilities used to produce the oil and gas will age and operate outside of the maximum efficiency range which could affect performance and reliability over time, reducing the ability to recover both the oil and gas indicated in the profiles. Infrastructure and delivery systems BPXA Post -Hearing Submission Page 4 of 7 could also impact oil and gas deliverability later in POP field life. While the FFM Tool and the cases run by BPXA account for well breakage and repair, they do not account for impacts due to facility or pipeline availability or performance, including TAPS.2 Directionally, however, it is safe to say that there will be a disproportionately greater impact on the gas sales cases with later start-up dates. C. ULTIMATE RECOVERY COMPARISON 1. RECOVERY AT A COMMON PROJECT LENGTH Table 1 shows the recovery of oil and gas, fuel usage, and total hydrocarbon recovery assuming a 30- year MGS project life; for example, the 2025 start-up case has an EOFL in 2055 and the 2040 start-up case has an EOFL in 2070. The EOFL of the Oil reference case is 2055. The table shows that hydrocarbon recovery is fundamentally maximized by achieving an MGS project, as the remaining hydrocarbon recovery from 2025 forward increases by more than four -fold for all MGS scenarios relative to the Oil Reference case. Among the MGS scenarios, the table shows that oil recovery increases, with greater fuel gas consumption and less gas sales, with a later MGS project. In addition to greater oil recovery prior to start of major gas sales, additional oil recovery is achieved on the tail of the profile due to possible field life extension. This additional oil recovery is balanced against the additional fuel consumed during the oil production period and on the tail. These results assume that wells and facilities will last for the duration of production in each scenario. These un-risked recovery profiles show that the increase in ultimate total hydrocarbon recovery with later start-up of major gas sales from 2025 to 2030 is about 0.05 B BOE or 50 MMBOE. Extending the start of major gas sales from 2025 to 2040 increases total hydrocarbon recovery by approximately 0.1 B BOE or 100 MMBOE. A volume of 100 MMBOE is only about 0.5% of the total expected hydrocarbon recovery. TABLE 1: UNRISKED RECOVERY OF OIL, GAS, FUEL AND TOTAL HYDROCARBONS FROM THE POP FROM 2025 TO 30 YEARS AFTER THE MGS START-UP, SENSTIVITIES TO PBU MGS START-UP DATES. Unrisked Recovery from 2025 to 30 years after MGS Start -Up Case Oil Gas Saps Fuel Gas Total Hydrocarbons (Billion STB) (TCF) (TCF) (Billion BOE) Oil Reference 1.07 - 3.68 1.07 Gas Reference - 2025 MGS 0.79 22.43 2.40 4.65 2030 MGS 0.93 21.92 3.08 4.71 2035 MGS 1.05 21.35 3.61 4.73 2040 MGS 1.14 20.96 4.15 4.75 2. RECOVERY AT A COMMON TOTAL HYDROCARBON RATE Assessment of EOFL at a common total hydrocarbon production rate is often used to estimate the economic life of a project. The ultimate hydrocarbon recovery is determined by assessing the 2 As noted earlier, the FFM Tool is capable of performing this analysis, but BPXA has not run such cases. BPXA Post -Hearing Submission Page 5 of 7 cumulative hydrocarbon recovered at the same total hydrocarbon rate for each case, instead of a fixed date. The cut-off rate assumed for this evaluation is 100 MBOE/D, and does not represent BPXA's view of the actual field economic limit which will depend on oil and gas prices and other future economic conditions which cannot be accurately predicted now. This total hydrocarbon rate is consistent with the rate limit used in the 2007 Blaskovich report commissioned by the AOGCC. Figure 5 in the Confidential Appendix to this submittal shows the total hydrocarbon production rate as a function of the total cumulative hydrocarbon recovery. The optimal recovery case is the one achieving the highest cumulative recovery at a given cut-off rate. However, Figure 5 indicates that after the field comes off plateau, the recovery curves lie on top of each other. This means that after gas plateau ends, the cases have similar ultimate hydrocarbon recovery for almost any common hydrocarbon production rate cut-off. Table 2 shows the recovery of oil and gas, fuel usage, and total hydrocarbon recovery assuming a common hydrocarbon rate cut-off of 100 MBOE/D. The data indicates that oil production is greater with MGS than the oil reference case by about 60 million barrels (MMbbls) using the common rate cut-off, rather than -280 MMbbls with a common end date, due to a significant extension of field life. The data in Table 2 also shows that the maximum difference in ultimate hydrocarbon recovery between the 2025 start-up case and other cases is 70 MMBOE, which approaches the resolution of the model for total hydrocarbon recovery (—+/- 40 MMBOE), without making any adjustments for facility life and project availability risks. According to the common total hydrocarbon rate EOFL metric, there is little discernible difference in total hydrocarbon recovery between the different MGS start dates cases, within the resolution of the FFM runs. TABLE 2: UNRISKED RECOVERY OF OIL, GAS, FUEL AND TOTAL HYDROCARBONS FROM THE POP FROM 2025 TO 100 MBOE, SENSTIVITIES TO PBU MGS START-UP DATES. Unrisked Recoveryfrom 2025 to 100 MBOE/D Cut -Off Case Oil Gas Sales Fuel Gas Total Hydrocarbons (Billion STB) (TCF) (TCF) (Billion BOE) Oil Reference 0.72 - 1.91 0.72 Gas Reference - 2025 MGS 0.78 22.16 2.35 4.60 2030 MGS 0.93 21.72 3.04 4.67 2035 MGS 1.05 21.03 3.55 4.68 2040 MGS 1.13 20.35 4.03 4.64 OIL RECOVERY VERSUS FUEL GAS USAGE Using the data in Table 1, the comparative incremental oil recovery and incremental fuel gas burned by pushing back the start-up of MGS, can be approximated. Figure 6 shows that the incremental oil recovered by a later start of MGS from 2025 to 2030 is —140 MMBOE, and the corresponding additional fuel burned is about —120 MMBOE. If POP MGS start-up occurs from 2035 to 2040 the BOE increase in fuel gas consumption surpasses the additional oil recovery. BPXA Post -Hearing Submission Page 6 of 7 h • • 4,000,000 3,500,000 3,000,000 O m 2,500,000 v U2,000,000 0 1,500,000 E a 1,000,000 500,000 160,000 tao,0cx1 tJ 120.000 o m 100,000 z m 80,000 y ' 60,000 0 V V ovC 40,000 20,000 x afQ+ C Gl E 4J PBU MGS Recovery 2025 to 2030 Incremental Recovery Due to Five Year Delay of MGS 2025 to 2030 ■ Oil ■ Fuel (BDE) IPBU FFM unceeamty 2030 to 2035 2035 to 2040 2030 to 2035 2035 to 2040 FIGURE 1: INCREMENTAL OIL RECOVERY AND FUEL GAS BURNED BY EXTENDING THE START OF MGS FOR FIVE YEAR PERIODS. ERROR BARS REPRESENT PRECISION OF FFM RUN PREDICTIONS FOR ULTIMATE RECOVERY. BPXA Post -Hearing Submission Page 7of7 by ! • BP Exploration (Alaska) Inc. 900 E. Benson Boulevard Anchorage, AK 99508 P.O. Box 196612 Anchorage, AK 99519-6612 September 8, 2015 Via Hand Delivery RECEIVED SEP 0 8 2015 Cathy P. Foerster Commission Chair AOGCC Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: Docket Numbers: AIO 15-032, AIO 15-033 and CO 15-09, Prudhoe Oil Pool BPXA Post -Hearing Comment to Commission regarding a Sunset Provision Consolidated Application for Amendment of Prudhoe Oil Pool Rule 9 and Modification of Prudhoe Bay Unit Area Injection Orders AIO 3A and AIO 4F Dear Chair Foerster: BP Exploration (Alaska) Inc. (BPXA) submits the following comment for the Commission's consideration in this matter. The Commission's announcement during the hearing on August 27 that it is inclined to include a Sunset provision in its final order in this matter came as a surprise and source of concern for BPXA and Exxon Mobil. While our companies are aware of similar provisions in some parts of our lower 48 operations', the inclusion of a Sunset clause in an AOGCC Order for a pool rule order approving the request for a modification to the existing gas offtake rate is unprecedented and would undermine the certainty of supply from the Prudhoe Bay field that is needed to progress the Alaska LNG Project by BPXA, the State of Alaska, and the other parties. As we testified at the hearing, the Alaska LNG project is not expected to begin operations until approximately 2025. The reason a rate increase is being requested at this time is to provide certainty of supply amongst the parties, the export market, and the lending community. An order with a limited term -of any duration could significantly hinder the progress of the Alaska LNG Project because the long-term basis for gas sale contracts would be uncertain. As we presented in both the written materials and verbally during the hearing, the best way for the Commission to help ensure greater ultimate recovery of oil 1 For example, it is not uncommon in states similar to Kansas for its Conservation Commission Orders to include a termination clause such as the following in its orders: "This Order shall remain in effect until amended, changed, or modified by order of the Commission." However, a more specific Sunset provision generally would be based on operational considerations versus a simple time limit. For instance, certain Orders might terminate "at that point in time when no remaining well in the field is capable of producing in excess of 'Y' Mcf/d of gas or "y" bbls/d of crude oil, unless modified by further order of the Commission to terminate sooner". BPXA Post -Hearing CorriTRent to Commission Regarding a Sunset Claus Application to Amend POP Rule 9 and Modify AIOs Page 2 September 8, 2015 and gas from the Prudhoe Bay Unit Prudhoe Oil Pool is to exercise its statutory authority to facilitate the project moving forward to the fullest extent possible. Moreover, it is important to note that the inclusion of a Sunset provision in the Commission's order is not necessary because the Commission has the existing statutory power to call an investigation to re-evaluate any existing Order and either issue an emergency suspension of that provision or undertake a full hearing on the issue. Therefore, inclusion of a Sunset clause would provide little or no benefit to the Commission at the considerable cost of stifling certainty for long-term gas supply commitments. Sincerely, 141, Dave n uyl Regional Manager BP Exploration (Alaska) Inc. • Dave Lachance Vice President Alaska Reservoir Development September 8, 2015 Via Hand Delivery Cathy P. Foerster Commission Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, AK 99508 USA Direct 907 564 4855 Mobile 907 538 1719 Main 907 564 5111 dave.lachance@bp.com RECEIVED SEP 0 8 2015 AOGCC Re: Docket Numbers: AIO 15-032 AIO 15-033 and CO 15-09, Prudhoe Oil Pool BPXA Post -Hearing Submission of Redacted Confidential Presentation for Public Record Consolidated Application for Amendment of Prudhoe Oil Pool Rule 9 and Modification of Prudhoe Bay Unit Area Injection Orders AIO 3A and AIO 4F Dear Chair Foerster: BP Exploration (Alaska) Inc. (BPXA) submits, on behalf of itself and ExxonMobil Production Inc., as applicants in the above referenced matter, the enclosed redacted version of BPXA's confidential presentation to the Commission during the hearing on August 27, 2015. The enclosed presentation has been redacted to remove confidential data, consistent with our discussion with the Commission during the hearing, so that it may be included in the public record in this matter. Si cerely, Dave P. Lachance Vice President, Reservoir Development Attachment BPXA Post -Hearing Submis7on of Redacted Confidential Presentation f0o ublic Record Application to Amend POP Rule 9 and Modify AIOs Page 2 September 8, 2015 cc via email: Ernesto Daza, BPXA (ernesto.daza@bp.com) John Dittrich, BPXA Oohn.dittrich@bp.com) George Lyle, Guess & Rudd (glyle@guessrudd.com) Chris Wyatt, BPXA (chris.wyatt@bp.com) Gilbert Wong, EMAP (gilbert.wong@exxonmobil.com) Gerry Smith, EMAP (Gerry.b.smith@exxonmobil.com) Steve Luna, EMAP (charles.s.luna@exxonmobil.com) Brian Gross, EMAP O.brian.gross@exxonmobil.com) Jon Schultz, CPAI (Jon. Schultz@conocophillips.com) Eric Reinbold, CPAI (Eric.W.Reinbold@conocophillips.com) John Evans, CPAI (John.R.Evans@conocophillips.com) Phil Ayer, CUSA (pmayer@chevron.com) Angie Bible, CUSA (abible@chevron.com) Redacted Version for Public Record CONFIDENTIAL PRESENTATION The data in the following presentation contains BPXAs own engineering, geological and geophysical analysis and interpretation of PBU data, as well as other sensitive commercial information. BPXA requests that this information be held confidential pursuant to AS 31.05.035(d), 20 AAC 25.537(b) and AS 45.50.910 et seq., as well as Section 11.4 of the Prudhoe Bay Unit Agreement. (Please note that the slides also include some non - confidential narrative carried over from the public session for presentative purposes.) SEP 08 2015 27 August 2015 • E Support Rule 9 Application for amendment of CO 341 D Rule 9 for the Prudhoe Oil Pool (POP) Technical justification for increasing the maximum allowable gas offtake from 2.7 to 4.1 BCFD ,� Address several topics of interest for the AOGCC Support Application for AlO Modification of AlO 3A and AlO 4F :# Technical justification for request to inject CO2-byproduct into the POP for Enhanced Recovery and Pressure Maintenance • by OW, The Major Gas Sales (MGS) Reference Case (3.3 BSCFD) and the Maximum Allowable Gas (MAG) Sensitivity Case (4.1 BSCFD) both demonstrate significant additional hydrocarbon recovery from POP as a result of gas as sales J Results of the MGS reference case demonstrate that POP is capable of delivering: Approximately 22 Trillion Standard Cubic Feet (TSCF) of hydrocarbon sales gas or 3.8 billion Barrels of Oil Equivalent (BOE) A gas sales plateau length of 20+ years Continued oil development and production The MAG sensitivity case produces an equivalent ultimate hydrocarbon recovery of between 17.7 and 17.8 billion BOE's An increase in Rule 9 gas offtake to an annual average of 4.1 billion standard cubic feet per day (BSCFD) is consistent with good oil field engineering practices,- and positions the Prudhoe Bay Unit working interest owners to access of the MGS opportunity afforded by the Alaska LNG Project, and therefore should be approved Parallel, Compositional VIP Model Integrated subsurface, well, pipeline and facility model World class history match from 1977 to Present Examples of Uses: Facility optimization Activity planning Lean and Miscible gas injection Gas Cap Water Injection (GCWI) Gas Sales Development planning Reservoir Model Grid Redacted Confidential Information Map is Oil, Water, Gas Saturation 4 !7 • by 1) Oil Reference Case a) Active development drilling program b) Rig workovers for well repair c) Continued Gas Cap Water Injection (GCWI) d) Normal annual TAR events and facility downtime 2) MGS Reference Case and MAG Sensitivity Case a) Same drilling program as Oil reference case b) Rig workovers for well repair c) Continued Gas Cap Water Injection (GCWI) d) 1/1/2025 gas sales startup with a 1 year ramp e) Annual average supply to AKLNG GTP inlet (w/CO2): MGS Reference Case J MAG Sensitivity Case 2.7 BCF/D 1 3.6 BCF/D f) Normal annual TAR events and facility downtime g) GTP by-product (CO2) injected into Eileen West End (EWE) h) Convert apex gas injectors to producers i) Add gas perforations j) Project length 30 years 5 a .7 by • Forecasted liquid volumes reflect ongoing development activity • Field production continues to decline with substantial development and optimization • Recovery approaches 4.5 billion stb's more than originally predicted in 1977 of 9.7 billion stb's Redacted Confidential Information 11 10000 9000 8000 a E 7000 of A z 6000 0 Ti '0 5000 a 2 4000 d 9 3000 d LL 2000 1000 0 Ja POP Voidage (Oil, Water, Gas) ®Qol nwh+d �Qg, nvbfd �Qw, nwbld — MCPVD PRES • POP has acted like a gas field from early in its development • 85% of reservoir volume produced is gas. • Objective of gas sales is to turn the dominant remaining phase into recovered hydrocarbons. x 1500 V 0 a �o x 000 a 0 0 ,a o' 500 'o Y_ D00 M v 500 • Alaska LNG Project has advised gas supply to the GTP must be maintained, under normal operations, at rate of —3.5 BSCFD annual average untreated gas GTP feed rate of —3.5 BSCFD rate allows for 0.4 - 0.5 BSCFD for in -State demand and —2.7 BSCFD LNG facility inlet demand 0 POP's total gas offtake would also include lease fuel and minor North Slope sales sales and Miscible Injectant NO used outside of the POP in Prudhoe Bay Unit satellites. 4.1 BSCFD allows PBU flexibility - to supply the full GTP feed rate in the event of supply disruptions from other fields, to accommodate improved Alaska LNG Project facility performance and to allow operational flexibility Gas Offtake Requirements POP Offtake - POP Offtake - MGS Reference MAG Sensitivity Case (Normal Case Operations) .. ► -2.7 -3.6* * Higher supply rate due to higher CO2 concentrations in POP than in other fields • Gas OfFtake Produce gas from existing well stock Optimize offtake with: Targeted re -completion for gas Injector to producer conversions Two redundant offtake points at Central Gas Facility (CGF) Upgrade select equipment to ensure reliable gas delivery AKLNG Project participants are designing the GTP to return the CO2 byproduct to PBU Conceptual COZ receipt and distribution system / miles 3 miles 2 miles WPZ WP W CO2 Control Module 0 CGF 0.5 miles CO2 from GTP APEX PL (- 1 miles) GC-2 GC-1 3 miles 2 miles 5 miles GC-3 x .VALVE [ q�Y MlLdk k. MODUI.�` t.N -Y ALMODULC37 sr w,Y, � ••y�y `. lot ..� , CO2 Receipt and Injection EWE is the most promising option. Injection into Eileen West End (EWE) through new pipeline to existing wells at well pads W and Z • Additional CO2 injection options outside POP will be evaluated for additional enhanced recovery opportunity • Backup capability could be FS2 and the Apex injectors N • • Redacted Confidential Information all r-7 • • Redacted Confidential Information • Results of MGS reference case demonstrate POP is capable of delivering planned plateau gas supply for approximately 20 years. • Total gas supply from POP over project period is comparable for MGS reference and MAG sensitivity cases Redacted Confidential Information • 12 by • POP pressure declines about 100 psi / year in the MGS reference case during the plateau period, but remains sufficient to sustain the planned gas supply. • POP pressure decline slightly greater in the MAG case, but still remains sufficient to sustain planned gas supply. Redacted Confidential Information • MGS, MAG and Oil Reference Case - POP Offt � Cumulative curves include gas recovery in BOE totals Redacted Confidential Information 14 0 • qt kf k f.'.a'xYltiY'� o' �n, `3 Fu f Redacted Confidential Information • The net total BOE recovery increase from POP due to MGS is —3.6 Billion BOE. • Cumulative oil during major gas sales is decreased by <300 million bbls, due to pressure impacts, but greatly offset by increased BOE's from gas sales. 15 • • by • The MGS reference and MAG sensitivity cases demonstrate the substantial increased hydrocarbon recovery from POP due to MGS compared to the Oil Reference case . 20.0 ■ Gas Sales 18.0 ■ Remaining Oil+NGL 16.0 Produced Oil+NGL to 1/1/2015 w m 14.0 c 0 12.0 d 10.0 0 v 8.0 a m 6.0 a 4.0 2.0 me Reference Oil Case MGS Reference Case MAG Sensitivity Case —3.5-3.6 billion BOE's additional HC recovery from POP due to MGS. 16 • The current field activity prepares for MGS: Active drilling program Rig workovers to maintain healthy well stock Continued Gas Cap Water Injection (GCWI) Active non -rig well work programs - Waterflood and MI management BPXA and the other unit owners will continue to actively manage field optimization of the depletion strategy to enhance field performance into the future 14 17 it • 7 Additional Topic - MGS Start Date Sensitivity Redacted Confidential Information The Alaska LNG schedule basis is for a 2025 start-up. It is unknown when or if other major gas sales opportunities will t come • Later initiation of gas sales by more than 5 years will decrease recovery, as fuel gas impacts become larger than oil impacts Later gas sales increases risk of facility life impacts on recovery (not accounted for in profiles). • PBU FFM used to test sensitivity to injection of PTU gas into POP starting in 2023 at rate of —800 MMSCFD. Inject 0.6 TCF of PTU gas into POP In 2025 PTU and POP deliver gas to GTP Results. - Negligible net impacts to oil recovery POP oil rates decrease during PTU gas injection Additional pressure provides some compensating oil benefits Redacted Confidential Information • • The Major Gas Sales (MGS) Reference Case (3.3 BSCFD) and the Maximum Allowable Gas (MAG) Sensitivity Case (4.1 BSCFD) both demonstrate significant additional hydrocarbon recovery from POP as a result of major gas sales Results of the MGS reference case demonstrate that POP is capable of delivering: Approximately 22 Trillion Standard Cubic Feet (TSCF) of hydrocarbon sales gas or 3.8 billion Barrels of Oil Equivalent (BOE) - A gas sales plateau length of 20+ years Continued oil development and production The MAG sensitivity case produces an equivalent ultimate hydrocarbon recovery of between 17.7 and 17.8 billion BOE's An increase in Rule 9 gas offtake to an annual average of 4.1 billion standard cubic feet per day (BSCFD) is consistent with good oil field engineering practices; and positions the Prudhoe Bay Unit working interest owners to access of the MGS opportunity afforded by the Alaska LNG Project, and therefore should be approved 20 Objective - Requesting modification to AIO 3A and 4F for the POP Explain technical benefits and implications of injection CO2 into POP Summary CO2 handling limitations impact CO2 injection development options POP is injecting a similar amount of CO2 under current field operations EWE is the most promising location for CO2 injection within the POP - Additional CO2 from outside sources generates negligible changes to POP reservoir outcomes BPXA has studied and anticipates that the PBU working interest owners will continue to evaluate potential locations where p CO2 infection may be economically beneficial for enhanced recovery and pressure maintenance by 21 . . u ply& CO2 By -Product book Total GTP supply in the MGS reference case assumes 25% of gas delivered from non -POP sources. Currently POP produces and injects —800 MMSCFD of CO2 as part of field operations The AlO modification requests approval to inject GTP CO2 By - Product (POP CO2 plus an estimated —40 MMSCFD from PTU). Estimated GTP CO2 By -Product: • POP — 3.1 TCF • PTU — 0.3 TCF • Total — 3.4 TCF Redacted Confidential Information Redacted Confidential Information 22 it • CO2 handling limitations - Corrosion mitigation limits CO2 concentrations in equipment Increased CO2 concentration impacts equipment operational efficiency (turbines, flares, de -hydration) A Gas liquefaction must have very low concentrations CO2 for LNG processing. GTP CO2 processing capacity is expected to limit overall inlet gas CO2 concentrations. 1 Current modeling assumptions - Wells shut-in upon reaching 25 mole% CO2 The GTP will have a CO2 handling limit 23 CO2 ,Injection Locations Investigated The PBU FFM was used to determine the most promising location in the POP for GTP CO2 by-product injection for total hydrocarbon recovery Injection areas investigated: Eileen West End (EWE) Flow Station 2 Area (FS-2) Gas Caa — behind GCWI Injectors 24 of CO2 Injection Location, POP Recovery Redacted Confidential Information • EWE is the most promising location for CO2 injection for total hydrocarbon recovery EWE CO2 injection limits migration to high gas recovery areas FIN Data VNwPoM G1W ivemwn OMply Walla H* Tbe: D cox 2025 1.. a ass O.f0t 115'.. 020 025 am am 0.4 0. ame Foe Data VIMPOM Grid SPeaMM DIePMy WePe Help •`. ,;. Blue indicates higher CO2 concentrations Fde Dade VMw P01M Gnd Spce DISpNy Weer HIP W it r-- PBU FFM used to test sensitivity of reservoir to additional 0.3 TCF CO2 removed from PTU gas Same total BOE recovery as MGS reference case within model resolution Injection of CO2 removed from PTU gas into POP creates no discernable change to ultimate hydrocarbon recovery from POP 27 rJ • Additional Topic of Interest Alternate CO2 Usage in PBU - Studies CO2 Injection Lab Studies =. Point McIntyre _ Borealis - Orion Tools developed for CO2 injection benefit prediction - EOS models tuned to CO2 lab data Type patterns - Type pattern scale -up tools (COBRA) -- Compositional full field models IV Continuing to perform development studies to evaluate potential use of CO2 within PBU • Additional Topic of Interest " CO2 Injection Recovery Range Estimates #A Redacted Confidential Information To achieve upside all CO2 handling limitations need to be removed. High side assumes Ml injection discontinued in 2015 with no additional FOR recovery. 29 • by Nz Summary CO2 handling limitations impact CO2 injection development options POP is injecting a similar amount of CO2 under current field operations EWE is the most promising location for CO2 injection within the POP - Additional CO2 from outside sources generates negligible changes to POP reservoir outcomes BPXA has studied and anticipates that the PBU working interest owners will continue to evaluate potential locations where CO2 injection may be economically beneficial for enhanced recovery and pressure maintenance 30 • PXA Presents All opinions, assessments and analyses (including forward looking or predictions of future activities) in this presentation are those of BP Exploration (Alaska) Inc., in its capacity as an individual working interest owner in the Prudhoe Bay Unit. The PBU FFM consists of three parts: (1) historical PBU operational data; (ii) a set of reasoned assumptions about future PBU activities; (items (1) and (ii) are collectively referred to as the "FFM Inputs"); and (iii) a BPXA proprietary and trade secret process consisting of software code and algorithms owned by or licensed to BPXA (the "FFM Tool"). Full Field Model runs (sometimes referred to as cases or scenarios) are generated by inputting the FFM Inputs into the FFM Tool. FFM runs are meant to be predictive of future circumstances or consequences that could occur, depending on the FFM Inputs. Because of the proprietary and trade secret processes that BPXA employs in the use of the FFM Tool, it is not possible to derive • the details of PBU operational or technical data (e.g., specific geological data) from FFM runs. BPXA uses the FFM Tool to generate FFM runs for both itself and, upon request, for the PBU working interest owners. All references in this testimony to the FFM (or to PBU FFM) are a reference to FFM Inputs plus the FFM Tool. 0 0 Colombie, Jody J (DOA) From: Schultz, Jon S <1on.Schultz@conocophillips.com> Sent: Friday, September 04, 2015 2:28 PM To: Roby, David S (DOA) Cc: gilbert.wong@exxonmobil.com; Luna, Charles S(charles.s.luna@exxonmobil.com); pmayer@chevron.com; abible@chevron.com; john.dittrich@bp.com; glyle@guessrudd.com; chris.wyatt@bp.com; Reinbold, Eric W; Evans, John R (LDZX); Foerster, Catherine P (DOA); Seamount, Dan T (DOA); Ballantine, Tab A (LAW); Colombie, Jody 1 (DOA); Wallace, Chris D (DOA) Subject: RE: Supplemental information on CO2 disposal (dockets: NO 15-032, NO 15-033, and CO 15-09) Mr. Roby, Thank you very much for your note and opportunity to clarify our disposal request. The 2015 EPA Guidance supports CO2 disposal in Class II wells except where "the primary purpose [is] long-term storage ... [and] there is an increased risk to USDWs ... ", and only where Class II regulatory tools cannot manage the increased USDW risk (2015 EPA Guidance, at 2 and note 1, emphasis in original) (quoting 40 CFR 144.19). Accordingly, the Commission's authority to authorize Class II CO2 disposal, as supported by the 2015 EPA Guidance, is broad. That said, CPAI's request for the Commission to authorize disposal is narrow and tailored to the circumstances you describe in your note below. Specifically, CPAI requests that the Commission authorize CO2 disposal in Class II wells only where, as you state, an "enhanced recovery project is no longer viable." If an enhanced recovery project is viable, the CO2 would be injected and used for enhanced recovery. As we stated in our Comments and testimony, the working interest owners have done considerable work examining potential enhanced recovery opportunities; we will continue this work in advance of projected AKLNG start-up in 2025. We hope this clarification assists the Commission's consideration of our request. Please advise if CPAI can provide any further information or clarification. Responsive to your last question, CPAI does not request at this time that the Commission leave the record open beyond Sept. 8. Thank you very much. Regards, Jon Schultz ConocoPhillips Alaska Manager, Greater Prudhoe Area Office: +1-907-265-1315 Mobile: +1-907-227-8708 From: Roby, David S (DOA) fmailto:dave.robyC&alaska.gov] Sent: Friday, September 04, 2015 12:07 PM To: Schultz, Jon S • Cc: gilbert.wong@exxonmobil.com; Luna, Charles S(charles.s.luna(&exxonmobil.com); pmayer@chevron.com; abible@chevron.com; iohn.dittrich@bp.com; glyle a guessrudd.com; chris.wyatt@bp.com; Reinbold, Eric W; Evans, John R (LDZX); Foerster, Catherine P (DOA); Seamount, Dan T (DOA); Ballantine, Tab A (LAW); Colombie, Jody J (DOA); Wallace, Chris D (DOA) Subject: [EXTERNAL]Supplemental information on CO2 disposal (dockets: AIO 15-032, AIO 15-033, and CO 15-09) Mr. Schultz, Thank you for your letter dated September 3, 2015, in response to the AOGCC's request at the August 27, 2015, hearing on gas offtake from PBU that ConocoPhillips explain how the AOGCC has authority to approve CO2 disposal in Class II wells as opposed to requiring that CO2 disposal be conducted in Class VI CO2 sequestration wells. We are, frankly, reading and interpreting the April 23, 2015, EPA memo quite differently than you are. The memo clearly states that CO2 injection for enhanced recovery purposes is a Class II operation, which the AOGCC concurs with, however what you're proposing is CO2 disposal and by our reading of the EPA memo that can only be done as a Class II operation if it is using Class II wells that were formerly used for enhanced recovery operations but the enhanced recovery project is no longer viable. Injection of CO2 into a disposal interval or into a deep portion of the Ivishak aquifer where injection would not contribute to enhanced oil recovery would not fall into the narrow definition of when the EPA says that Class II wells can be used instead of Class VI wells for CO2 disposal. Unless you have something directly from the EPA that clearly shows that our interpretation of their memo is incorrect I'm afraid I will have to recommend that the Commissioners reject your application for authorization of CO2 disposal at this time. If you have such a document please submit it, if you do not but would like to ask the EPA to weigh in on this matter on the record we'd be willing to keep the record open for a reasonable amount of time to allow them to do so. Please advise before COB Tuesday September 8th if you'd like us to keep the record open and if so for how long. Regards, Dave Roby Sr. Reservoir Engineer Alaska Oil and Gas Conservation Commission (907)793-1232 0 0 C� ConocoPhillips Alaska September 3, 2015 Catherine P. Foerster, Commission Chair Alaska Oil and Gas Conservation Commission 333 W. 7th Ave #100 Anchorage, Alaska, 99501-3539 RECEIVED SEP 03 2015 AOGCC Jon Schultz Manager Greater Prudhoe Area P.O. Box100360 Anchorage, AK 99510-0360 Phone: 907-265-1315 RE: Docket Numbers: AIO 15-032, AIO 15-033, CO 15-09 — Prudhoe Bay Unit ConocoPhillips Alaska, Inc. (CPAI) Supplemental Submission Re AOGCC Authority to Authorize Disposal of Gas Treatment Byproducts, Principally Comprising Carbon Dioxide, In Class II Wells Dear Commissioner Foerster, At the August 27, 2015 hearing in the above referenced matter, the Alaska Oil and Gas Conservation Commission (Commission) requested that CPAI provide supplemental information regarding the Commission's authority to approve disposal of gas treatment byproducts, principally comprising carbon dioxide (CO2), in Class II PBU wells (Supplemental Submission). More specifically, at the August 27 hearing, the Commission received into the record an April 23, 2015 guidance letter from the United States Environmental Protection Agency (EPA) Director of the Office of Ground Water and Drinking Water, referencing key principles related to transition of Class II to Class VI wells (2015 EPA Guidance, attached). The Commission requested that CPAI explain how the 2015 EPA Guidance supports the Commission's authority to authorize CO2 disposal in Class II wells. Background: Underground Infection Control Program Under the Safe Drinking Water Act, EPA is authorized through the Underground Injection Control (UIC) program to regulate the injection of fluids into underground wells in order to ensure underground sources of drinking water (USDWs) are not impaired. EPA's UIC regulations govern the siting, construction, operation and closure of six "classes" of underground injection wells - referred to as Class I through Class VI - which vary according to the potential for the class of injected fluid to impact USDWs. See 40 C.F.R. § 144.6. The two UIC well classes pertinent to the Commission's inquiry in this matter are: • Class II - Class II wells are primarily used by the oil and gas industry to inject fluids either for enhanced recovery (ER) or exploration and production waste disposal. CPAI Supplemental Submission Re Commission Authority to Approve C0Disposal in Class II Wells Page 2 of 4 September 3, 2015 • Class VI - In late 2010, EPA promulgated regulations establishing a new category of injection wells defined to be wells "used for geologic sequestration of carbon dioxide beneath the lowermost formation containing a USDW[.]" 40 C.F.R. § 144.6(f).' A state or tribe may apply for and obtain from EPA primacy (lead administration and enforcement authority) for one or all of the six classes of UIC wells. The State of Alaska, through the Commission, has obtained primacy to administer and enforce the Class II UIC program in Alaska. The State of Alaska has not yet sought primacy to administer and enforce the Class VI UIC program.2 Though it has existed for five years, the Class VI program is not widely used. At this time, EPA has approved Class VI wells for two applicants, and estimates that 6 to 10 additional commercial Class VI wells will come online by 2016.3 By comparison, EPA reports that there are approximately 172,068 Class II wells currently in operation.4 2. The 2015 EPA Guidance Clarifies That the Commission Has Authority to Approve CO2 Disposal or Storage In Class II Wells In its 2015 guidance letter, consistent with well -established Class II regulation of both enhanced recovery injection and exploration and production waste disposal, EPA pragmatically encourages use of Class II wells for CO2 injection for ER, as well as for CO2 disposal or storage.5 EPA recognizes that "CO2 storage associated with Class II wells is a common occurrence ...." 2015 EPA Guidance at 1. EPA notes that "CO2 can be safely stored where injected through Class II -permitted wells for the purpose of oil or gas -related recovery". Id. This is consistent with current PBU enhanced recovery operations. As BPXA notes in its pre -filed testimony, CO2 is a significant component (comprising approximately 800 mmscf/d) of the gas currently reinjected in the Prudhoe Oil Pool (POP) for enhanced oil recovery. (BPXA Pre -Filed Testimony, at 12.) As the Commission is aware, in the major gas sale development phase of Prudhoe Bay, after commencement of natural gas offtake, treatment and export, natural gas reinjection into the POP to support enhanced liquid recovery would decrease over time. Also in this next phase, gas treatment byproduct, principally comprising CO2, would be injected. Although this CO2 would be preferentially used for ER, if viable ER opportunities are not identified, the CO2 would be injected for disposal (as, for example, produced water would be injected for disposal, where viable ER opportunities for water injection are not presents). Regarding such Class II CO2 injection in later phases of oil and gas development, EPA states: See generally40 C.F.R. § 146.81 et seq. (EPA's UIC Class VI program regulations). 2 The 2015 EPA Guidance encourages states to apply for primacy for all well classes, including Class VI 3 See http://www.epa.gov/r5water/uic/adm/ (reporting on the issuance of two Class VI UIC wells to Archer Daniels Midland, one of which had been appealed to the Environmental Appeals Board); http://www.epa.gov/r5water/uic/futuregen/ (addressing Class VI permits issued to FutureGen Alliance 2.0). 4 http://water.epa.gov/type/qroundwater/uic/welIs.cfm. 5 The 2015 EPA Guidance generally refers to CO2 "storage". In the context of Alaska's Class II program, "storage" of CO2 would constitute "disposal". See 20 AAC 25.252 and note 6 below. s Like produced water, if not used for ER, the gas treatment byproduct stream would be conventional oilfield waste. See 58 Fed. Reg. 15284, 15286 (Mar. 22, 1993); EPA Report to Congress on the Management of Waste from the Exploration, Development, and Production of Crude Oil, Natural Gas, and Geothermal CPAI Supplemental Submission Re Commission Authority to Approve C0Disposal in Class II Wells Page 3 of 4 September 3, 2015 If oil or gas recovery is no longer a significant aspect of a Class II permitted ER operation, the key factor in determining the potential need to transition a CO2 ER operation from Class II to Class VI is the increased risk to USDWs related to significant storage of CO2 in the reservoir, where the regulatory tools of the Class II program cannot successfully manage the risk. 2015 EPA Guidance at 2 (emphasis in original). EPA further states: The most direct indicator of increased risk to USDWs is increased pressure in the injection zone related to the significant storage of CO2. Increases in pressure with the potential to impact USDWs should first be addressed using tools within the Class II program. Transition to Class Vl should only be considered if the Class 11 tools are insufficient to manage the increased risk. The key regulation, "Transitioning from Class II to Class VI," codified at 40 CFR 144.19, states that owners or operations that are injecting carbon dioxide for the primary purpose of long-term storage into an oil and gas reservoir must apply and obtain a Class VI GS permit when there is an increased risk to USDWs compared to Class 11 operations. 2015 EPA Guidance at 2 and note 1 (first emphasis added; second and third emphases in original). This EPA guidance directly supports the Commission's authority to authorize CO2 disposal in Class II PBU wells. As BPXA states in its application, there is no underground freshwater source within the PBU; accordingly, there is no risk of movement of injected CO2 into USDWs. BPXA and EMAP Consolidated Application at 6. Applying this key fact to EPA's guidance, because there is no increased risk to USDWs, even if viable enhanced recovery opportunities are not identified, and CO2 and other gas treatment byproducts are injected into the reservoir for disposal or storage, rather than enhanced recovery, Class II tools will remain sufficient to manage any risks. Accordingly, there will be no reason or requirement to transition any PBU Class II operation to Class VI. As PBU CO2 disposal or storage will remain a Class II operation, the Commission has and will retain authority to approve and regulate it. We trust this Supplemental Submission addresses the Commission's request. If there is additional information that CPAI can provide, we would be pleased to do so. Sincerely, 1711 // r, Greater Prudhoe Area a. Inc. Energy, EPA530-SW-88-003, Vol. 1, at p. II-18 (Dec. 1987); EPA530-K-01-004, Exemption of Oil and Gas Exploration and Production Wastes from Federal Hazardous Waste Regulations at 7 (Oct. 2002). • • CPAI Supplemental Submission Re Commission Authority to Approve CO2 Disposal in Class II Wells Page 4 of 4 September 3, 2015 Attachment 1 — April 23, 2015 EPA Guidance cc via email: Gilbert Wong, EMAP (gilbert.wong(q�,exxonmobil .com) Steve Luna, EMAP(charles.s.luna(a�exxonmobil.com) Phil Ayer, CUSA (pmayer(a�chevron.com) Angie Bible, CUSA (abible(_)chevron.com) John Dittrich, BPXA (John. Dittrich(cD-bp.com) George Lyle, Guess & Rudd (g_lyle @,guessrudd.com) Chris Wyatt, BPXA (Chris.Wyatt(a-bp.com) Eric Reinbold, CPAI (Eric.W.Rein bold(a)conocophill ips.com) John Evans, CPAI (John.R.Evans(c)-conocophillips.com) r: • Attachment 1 April 23, 2015 EPA Guidance See attached. • hAr UNITED STATES ENVIRONMENTAL PROTECTION AGENCY z WASHINGTON D C 20460 F�rgl PpOSEG�� APO 7 3 901t OFFICE OF WATER MEMORANDUM FROM: Peter C. Grevatt, Director Office of Ground Water and Drinking Water G TO: Regional Water Division Directors SUBJECT: Key Principles in EPA's Underground Injection Control Program Class VI Rule Related to Transition of Class tI Enhanced Oil or Gas Recovery Wells to Class VI Most states have primary enforcement responsibility (i.e., primacy) for the Class 11 Underground Injection Control program for oil or gas -related injection activities, while EPA Regions currently retain direct implementation authority for the Class VI program in every state. The shared implementation of the UIC program necessitates a clear articulation and common understanding of the potential for transition of enhanced recovery wells from Class II to Class VI, consistent with EPA's Class VI Rule. This memo is intended to emphasize the key principles in EPA's UIC Class VI Rule related to the transition from Class 11 to Class VI for ER wells that inject carbon dioxide for long-term storage. As Regions work with states on implementation of the Class VI program, I encourage you to assist states in submitting primacy applications for all well classes, including Class VI. EPA recognizes the importance of geologic sequestration of anthropogenic CO2 for climate change mitigation. The UIC Class VI Rule was developed to facilitate GS and ensure protection of underground sources of drinking water from the particular risks that large scale CO2 injection for purposes of long- term storage may pose. The following are key principles related to the transition of ER wells that store CO2 from Class II operations to the Class VI program: 1. Geologic storage of CO2 can continue to be permitted under the UIC Class 11 program. ER wells across the U.S. are currently permitted as UIC Class II wells. CO2 storage associated with Class 11 wells is a common occurrence, and CO2 can be safely stored where injected through Class tI-permitted wells for the purpose of oil or gas -related recovery. 2. Use of anthropogenic CO2 in ER operations does not necessitate a Class VI permit. ER operations can continue to be permitted as Class II wells, regardless of the source of CO2. An owner or operator of an ER operation can switch from using a natural source to an anthropogenic source of CO2 without triggering the need for a Class VI permit. Internet Address (URr_) - http 8www epa gov RecyclediRecyclable • P MILek! WO Vegetable 0,1 Based Inks on tpp"... Postconsurner Process Chlorine Free Recycled Paper 0 9 3. Class VI site closure requirements are not required for Class II CO2 infection operations. A Class II well that has been used for injection of anthropogenic or non-anthropogenic CO2 and has been operated within its permit conditions can be closed as a Class lI well. 4. f ER operations that are focused on oil or gas production will be managed under the Class II program. If oil or gas recovery is no longer a significant aspect of a Class II permitted ER operation, the key factor in determining the potential need to transition a CO2 ER operation from Class II to Class VI is the increased risk to USDWs related to significant storage of CO2 in the reservoir, where the regulatory tools of the Class II program cannot successfully manage the risk. The most direct indicator of increased risk to USDWs is increased pressure in the injection zone related to the significant storage of m. Increases in pressure with the potential to impact USDWs should First be addressed using tools within the Class 11 program. Transition to Class VI should only be considered if the Class II tools are insufficient to manage the increased risk. 5. The Class II and Class VI directors should work together to address the potential need for transition of any individual operation from a Class II to a Class VI permit. The Class II program director (in most cases a state official) will have the relevant data on pressure and volume of COa injected into Class Ii BR operations, which will influence any transition decision. EPA encourages the Class 11 director to contact the Class VI director where he/she believes the risk has changed as a result of significant storage of COz in the reservoir. 6. , The best implementation approach is for states to administer both the Class II and the Class VI UIC programs. EPA encourages states to apply for primacy for all well classes, including Class V1. Based on our conversations with states. in most cases, states who are approved for primacy for the Class V1 program are expected to administer the program through their oil and gas program. The Office of Ground Water and Drinking Water is currently working with the U.S. Department of Energy, state associations, EPA Regions and stakeholders to finalize technical guidance focused on risk factors discussed in the Class VI Rule at 40 CFR 144.19, As we complete the final guidance, we will work to ensure that these key principles remain clear. Please contact me or have your staff contact Ron Bergman at 202-564-3823 if we can be of assistance to you on these or other UIC program issues. ' The key regulation, "Transitioning from Class 11 to Class VI," codified at 40 CFR 144.19, states that owners or operators that are injecting carbon dioxide fur the primary purpose of long-term storage into an oil and gas reservoir must apply for and obtain a Class V l GS permit whet there is au increased risk to USD Ills compared to Class H operations. 0 0 1 ALASKA OIL AND GAS CONSERVATION COMMISSION 2 3 Before Commissioners: Cathy Foerster, Chair 4 Daniel T. Seamount 5 6 In the Matter of the Application of BP ) 7 Exploration Alaska, Inc., to Modify AIO ) 8 3A and 4F and CO 341D to Authorize the ) 9 Injection of CO2 for Enhanced Recovery ) 10 Purposes and to Increase the Allowable ) 11 Gas Offtake Rate for the Prudhoe Oil Pool. ) 12 ) 13 Docket No.: AIO 15-032, AIO 15-033, CO 15-09 14 15 ALASKA OIL and GAS CONSERVATION COMMISSION 16 Anchorage, Alaska 17 18 August 27, 2015 19 9:00 o'clock a.m. 20 21 PUBLIC HEARING 22 (CONFIDENTIAL PORTION EXCLUDED) 23 24 BEFORE: Cathy Foerster, Chair 25 Daniel T. Seamount, Commissioner 1 TABLE OF CONTENTS 2 Opening remarks by Chair Foerster 03 3 Remarks by Mr. Lyle 10 4 Remarks by Mr. Vantyle 15 5 Remarks by Mr. Laughlin 24 6 Remarks by Mr. Lakosh 41 7 Remarks by Mr. Reinbold 82 8 Remarks by Mr. Stramp 85 K 1 P R O C E E D I N G S 2 (On record - 9:00 a.m.) 3 CHAIR FOERSTER: I'd like to call this hearing 4 to order. Today is August 27th, 2015, the time is 9:00 5 o'clock a.m. We're located in the Anchorage 6 Legislative Office Building, Legislative Information 7 Office Building, I think, 716 West Fourth Avenue, 8 Anchorage, Alaska. 9 To my left is Dan Seamount, he's one of the 10 Commissioners at the Alaska Oil and Gas Conservation 11 Commission and I'm Cathy Foerster, I'm another 12 Commissioner, I'm the Chair. 13 We're here today in regard to Docket number AIO 14 15-032, AIO 15-033 and CO 15-09, all regarding the 15 Prudhoe Bay unit and requested modifications to those 16 orders. 17 BP Exploration Alaska, Inc. by letter dated 18 July 17th, 2015 -- can -- well, let me stop. Can 19 everybody hear me, I've never used this mic before, in 20 the back or -- do I see some nods in the back? All 21 right. Good. BP Exploration requests the Alaska Oil 22 and Gas Conservation Commission modify the following 23 orders. Area injection orders 3A and 4F to authorize 24 the injection of CO2 for enhanced recovery and pressure 25 maintenance from sources both inside which is already C 1 authorized, and outside the Prudhoe Bay unit, as well 2 as rule 9 of conservation order 341D for the Prudhoe 3 Bay -- for the Prudhoe oil pool to authorize an 4 increase in the maximum annual average gas offtake 5 limit from 2.7 billion standard cubic feet per day to 6 4.1 billion standard cubic feet per day. 7 Computer Matrix will be recording these 8 proceedings and you can get a copy of the transcript 9 from Computer Matrix Reporting. 10 Before we begin I'd like to thank the Alaska 11 Legislature for allowing us to use this conference room 12 and especially Senator Gary Stevens for offering this 13 as a solution to us when I ran into him at Kaladi 14 Brothers and said our room isn't big enough for this 15 hearing, what am I going to do. So thank you to the 16 Legislature. 17 I trust that the representatives from BP, 18 Chevron, Conoco and Exxon are familiar with the purpose 19 of this hearing and the statutory authority of the 20 AOGCC in this matter, but we have some folks in the 21 audience today who may not be so I'll explain those 22 things briefly for their benefit. This will probably 23 save some time and confusion as we proceed and help 24 everyone with their expectations on today's 25 proceedings. 4 0 • 1 As I mentioned earlier BP and Exxon have made 2 two requests and Conoco and Chevron have requested 3 modifications related to those request. The first 4 request is to modify injection orders to allow for CO2 5 injection for enhanced oil recovery and the second is 6 to modify rule 9 of CO 341D to increase the gas offtake 7 allowable from Prudhoe Bay. The purpose of this 8 hearing is to gather sufficient information to make a 9 determination on both of those requests. The AOGCC's 10 statutory authority -- let me go back, and to make as 11 much of that information as is possible available to 12 the public so the public can understand the decision 13 that's being made. The AOGCC's statutory authority 14 requires that our decisions in these matters be based 15 on maximizing greater ultimate hydrocarbon recovery and 16 preventing hydrocarbon waste. Although we can hear 17 other considerations, these two override in our 18 decision making. 19 It appears that BP and Conoco both intend to 20 testify today and I didn't see any other entities 21 choosing to testify today, but as the proceedings 22 progress if someone, you know, feels compelled to 23 testify later we can always -- you know, just because 24 you wrote down no doesn't mean that we will preclude 25 you from testifying. 5 1 COMMISSIONER SEAMOUNT: Is there anybody 2 telephonically that wanted to..... 3 CHAIR FOERSTER: Is there anyone telephonically 4 listening today who would like to testify, is there 5 anyone online? 6 UNIDENTIFIED VOICE: Not that I know of. 7 CHAIR FOERSTER: Okay. So just to help 8 everyone understand how this will progress, the 9 Commissioners will ask questions during testimony, we 10 may also take a recess to consult with staff to 11 determine whether additional information or clarifying 12 questions are necessary. If a member of the audience 13 has a question that he or she feels should be asked 14 please submit that question in writing to Jody Colombie 15 or Sam Carlisle who are making the float wave right 16 now. They will provide the question to the 17 Commissioners and if we feel that asking that question 18 will assist us in making our determination we will ask 19 it. If your question isn't asked then I apologize for 20 your hurt feelings. 21 We will start by taking testimony from and 22 asking questions of the original applicants, BP and 23 Exxon. We will then ask questions -- well, we will 24 then allow Conoco to testify and ask questions of them. 25 We will then take testimony from any of the other on 1 members of the public who choose to do so at that time. 2 For those testifying please keep in mind that you must 3 speak into the microphone so that those in the 4 audience, the court reporter and those on 5 teleconference or watching the live feed can hear you. 6 This is a public hearing and informing the public is an 7 important part of today's proceeding. 8 Also please remember to reference your slides 9 so that someone reading the public record in the future 10 can follow along. And those of you who've testified 11 before me before know that I'm a royal pain in the neck 12 or every body part to make sure that you do that. So 13 if you fail to do that I will remind you. And the way 14 that would look is as you -- as you refer to a slide 15 say we're now looking at slide number X or if the 16 slides are not numbered and that will be part of the 17 permanent record then say we are referring to the slide 18 entitled blah. So it's pretty darn simple. 19 I want to add that this is an important 20 proceeding and Dan and I will try to carry ourselves as 21 professionally as we're capable of, but please relax, 22 this isn't -- this isn't a trial, no one's going to 23 jail, we're here to gather information. This is -- 24 some of this information can by mind numbingly 25 technical and boring so please just relax and give us 7 1 your honest information in as comfortable way as you 2 can. 3 COMMISSIONER SEAMOUNT: Chair Foerster, does 4 that mean I can talk about the king I caught and the 5 other fish and the caribou I didn't shoot? 6 CHAIR FOERSTER: If you keep it to under three 7 minutes because it has nothing to do with these 8 proceedings, yes. 9 We have a few ground rules on what is allowed 10 relative to testimony. First all testimony must be 11 relevant to the purposes of the hearing that I outlined 12 a few minutes ago and to the statutory authority of the 13 AOGCC. Anyone desiring to testify or talk about their 14 fishing and hunting may do so, but if the testimony 15 drifts off topic then we will limit it to three 16 minutes. Additionally testimony may not take the form 17 of cross examination. As I said before Commissioner 18 Seamount and I will be asking all the questions today. 19 And finally testimony that is disrespectful or 20 inappropriate will not be allowed. 21 Dan, do you have anything to add for the good 22 of the order? 23 COMMISSIONER SEAMOUNT: No, not at this time. 24 Are you going to go over the confidentiality issue? 25 CHAIR FOERSTER: Yes, when we get BP up here. 1 COMMISSIONER SEAMOUNT: Okay. 2 CHAIR FOERSTER: Okay. Let's start with BP 3 first, but before you guys begin we do have some 4 administrative bits to work through. First a review of 5 your application and prefiled testimony were -- we were 6 initially struggling to understand why certain document 7 were labeled confidential because there's a lot of 8 nonconfidential information in that, but I think your 9 -- the point that you made in the hard copies we got 10 today is that anything that's nonconfidential that's 11 part of your confidential testimony is also in your 12 nonconfidential testimony. If someone could come up to 13 the mic and say yes or no to that then that -- the 14 public record will not capture the head nods. 15 MR. LYLE: That's correct. 16 CHAIR FOERSTER: The next thing on 17 confidentiality, for the sake of getting through this 18 in a reasonable amount of time we would prefer that you 19 give all of your nonconfidential testimony first and 20 then we can have an in camera section -- session for 21 your nonconfidential [sic]. And come back up and you 22 also need to because the nods won't be recorded, is 23 that an acceptable process to BP. 24 UNIDENTIFIED VOICE: That's acceptable. 25 CHAIR FOERSTER: Okay. And there..... 9 1 REPORTER: Can I just get a clarification, 2 Madam Chair. 3 CHAIR FOERSTER: For the record your name and 4 who you represent. 5 MR. LYLE: George Lyle, I'm with the law firm 6 of Guess & Rudd, I represent BP. And just in terms of 7 the sequence of public and confidential, we'd had a 8 prehearing conference where we had suggested and I 9 thought the staff thought it make sense, to allow all 10 the public testimony to occur and then break to have 11 the confidential testimony from any witness who's 12 giving confidential testimony after all the public 13 testimony..... 14 CHAIR FOERSTER: Okay. 15 MR. LYLE: .....so we don't have to have people 16 coming in and out of the room. 17 CHAIR FOERSTER: Okay. So after everyone who 18 chooses to testify BP will come back up with the 19 confidential. Okay. 20 MR. LYLE: Correct. 21 CHAIR FOERSTER: And for the record and for the 22 process I was told that all of the working interest 23 owners in Prudhoe Bay will be allowed to stay in the 24 room, it's just the press and members of the public 25 that will be asked to leave. Like we have some 10 9 0 1 representatives from the Department of Natural 2 Resources, will they be allowed to stay? 3 MR. LYLE: We'll have to determine exactly who 4 is allowed to stay and who..... 5 CHAIR FOERSTER: Okay. Well, we can do that at 6 that time. And the AOGCC will not be responsible for 7 your determining who gets to stay and who gets to go, 8 we're going to -- that monkey just is sitting right on 9 your shoulders. If there's somebody in this room after 10 we go in camera that you don't want in here it's your 11 job to get them out. 12 MR. LYLE: We understand. 13 CHAIR FOERSTER: Okay. Okay. Thank you. 14 MR. LYLE: Thank you. 15 CHAIR FOERSTER: Let's see, one last thing 16 before we -- before you testify. Your application 17 appears to optimize around one timing and wait scenario 18 based on a single commercial opportunity, whether then 19 to optimize based on greater ultimate hydrocarbon 20 recovery. Have you run a scenario and are you prepared 21 to present a scenario that optimizes first on greater 22 ultimate primary -- great ultimate hydrocarbon recovery 23 with all those other considerations aside have you -- 24 have you run that case and are you prepared to present 25 it to us today? That's a yes or no question, anybody 11 1 can answer it. 2 MR. LYLE: We have run the case, but we're not 3 prepared to present it today. 4 CHAIR FOERSTER: Okay. Well, then here's the 5 decision point for you guys. That case is going to be 6 essential to us in our deliberation. So we can either 7 stop right now and continue the hearing until such time 8 as you're prepared to present it or we can proceed with 9 today's hearing and hear everything else that everyone 10 has to say and continue the hearing until such time as 11 you can provide that to us and be prepared to talk to 12 it. 13 MR. LYLE: There are pieces of our testimony 14 today that actually will address most of that. 15 CHAIR FOERSTER: So you want to continue today 16 and -- you want to proceed today and be prepared to 17 continue the hearing should we determine that 18 additional cases are necessary. Okay. All right. So 19 just be prepared that that is an -- that is a 20 possibility at the end of these proceedings. And also 21 if we aren't able to finish today we found out that 22 this room will be available to us tomorrow and we will 23 continue tomorrow if that is necessary. 24 Okay. All right. So I think we're ready for 25 your witness to come up and be sworn or affirmed in and 12 0 • 1 have witnesses recognized as expert or not, so whatever 2 order -- I know you might have somebody that doesn't 3 want to be an expert and I think -- we don't swear in 4 lawyers do we because we don't believe them? 5 COMMISSIONER SEAMOUNT: That's what a federal 6 lawyer once told us. 7 CHAIR FOERSTER: Okay. So you -- BP, please 8 start your testimony in whatever order, but if you do 9 have a witness who is a non -attorney or is going to be 10 testifying on other things other than just the 11 introductory stuff we will need to swear you in before 12 you stop -- start speaking and validate your expertise 13 and accept or not accept you as an expert witness. 14 So and one more thing. 15 MR. LYLE: Thank you. My name is George Lyle, 16 I'm an attorney with the Anchorage law firm of Guess & 17 Rudd and I'm representing BP Exploration Alaska in this 18 matter. Just one other procedural issues and then Mr. 19 Vantyle will provide some nonconfidential testimony. 20 CHAIR FOERSTER: Before you start, can you hear 21 in the back? 22 IN UNISON: No. 23 MR. LYLE: I apologize, let me get closer. 24 Again my name is George Lyle, I'm with the law firm of 25 Guess & Rudd and here today representing BP Exploration 13 1 Alaska. Mr. Vantyle will be providing testimony of a 2 nonconfidential nature, but I had one procedural issue 3 I just wanted to clarify. 4 CHAIR FOERSTER: Okay. First now can you hear 5 in the back? 6 (No comments) 7 CHAIR FOERSTER: Okay. If at anytime during 8 the proceedings you cannot hear in the back would you 9 just stand up and let me know because I want everyone 10 in the room to be able to hear what you came here to 11 hear today. 12 All right. Sorry for the interruption. 13 MR. LYLE: The procedural issue is simply BP 14 hopes and expects to be able to answer all of the 15 Commission's questions today, but in the event there is 16 an issue that they're not able to address today they'd 17 like the opportunity to after the hearing or the 18 continued hearing to answer the question and if the 19 Commission desires any sort of post hearing briefing 20 the opportunity to do that as well to address any 21 unexpected issues that might come up. 22 CHAIR FOERSTER: Okay. We won't -- we won't do 23 a post hearing briefing, everything in this proceeding 24 that -- is going to be as public as possible so if 25 there remain questions at the end of this day we will 14 1 either continue the hearing or leave the record open 2 until those questions can be answered. 3 MR. LYLE: Okay. Thank you very much. 4 CHAIR FOERSTER: You're welcome. So can I 5 swear you in? 6 MR. VANTYLE: Standing or sitting? Standing. 7 CHAIR FOERSTER: Can I swear you in? 8 MR. VANTYLE: Yes. 9 CHAIR FOERSTER: Get down close enough -- you 10 don't have to stand, just get close enough to the mic 11 so that your answer can be..... 12 COMMISSIONER SEAMOUNT: Or don't sit down. 13 CHAIR FOERSTER: Yeah, have a seat, get 14 comfortable. As comfortable as these chairs can let 15 you get. 16 (Oath administered) 17 MR. VANTYLE: I do. 18 DAVID VANTYLE 19 called as a witness on behalf of BP Exploration Alaska, 20 Inc., testified as follows on: 21 DIRECT EXAMINATION 22 CHAIR FOERSTER: All right. Now for the record 23 give us your name, who you represent and if you want to 24 be recognized as an expert what that expertise is so we 25 can decide whether to accept that. 15 0 • 1 MR. VANTYLE: Yeah. Thank you, Madam Chair, 2 Commissioner Seamount. My name is David Vantyle and 3 I'm BP's vice president and regional manager here in 4 Alaska. And the testimony I'm going to provide is 5 contextual along the Alaska LNG project and I don't 6 wish to be recognized as an expert. 7 CHAIR FOERSTER: Okay. Okay. Please proceed 8 then. 9 MR. VANTYLE: Yes, thank you. I've been 10 working for BP in Alaska here for over 31 years now and 11 the last several of which have been dedicated to 12 working to get Alaska's gas to market. And today I 13 represent BP's interest in the Alaska LNG project. 14 Janet Reese, our regional president, wanted to be here 15 this morning and sends her regrets. She's actually as 16 we speak on a conference call with our upstream 17 executive management discussing the Alaska LNG project. 18 19 So, Commissioners, thank you for the 20 opportunity to be here this morning. I'll be providing 21 as I mentioned some brief opening remarks that will 22 place context around BP's request to the Commission as 23 Prudhoe Bay working interest owner, not as operator for 24 an offtake rate increase at Prudhoe Bay and for the 25 modification to the area injection order to allow for 16 1 CO2 disposition from the Alaska LNG project. Then my 2 colleague, Bruce Laughlin, will provide additional 3 technical detail supporting the request. 4 BP is very pleased to be here before the 5 Commission to discuss our request to increase the 6 Prudhoe Bay gas offtake in preparation for a major gas 7 sale. It means that we've come another important step 8 closer to a successful Alaska gas project. The success 9 of the Alaska LNG project, it's critical to BP's 10 business here in Alaska and it's also critical to the 11 future of the state of Alaska itself and to so many 12 Alaskans who will benefit both directly and indirectly 13 from a successful Alaska gas project. 14 As you're no doubt aware the project has 15 recently taken several very important steps forward to 16 becoming the reality that we all hope for. Back in 17 January of last year, 2014, BP, ExxonMobil, 18 TransCanada, ConocoPhillips, Alaska Gasline Development 19 Corporation, the DNR, the DOR, all signed the Alaska 20 LNG project heads of agreement. And that outlined our 21 way forward for the project, it showed we had an 22 aligned interest in advancing the project as an agreed 23 way forward to commercialize Alaska's gas. A few 24 months later in April the Legislature voted 52 to eight 25 to approve SB 138 which was the legislation outlined in 17 1 the heads of agreement that defines the State's 2 participation in this effort and provided the way 3 forward for the project to advance. And the Governor 4 signed that bill into law the next month, in May. Then 5 in June all the parties signed the prefeed joint 6 venture agreement that allowed the project to advance 7 to the prefeed phase where we -- where we sit today, 8 feed meaning front end engineering and design. 9 The very next month in July the project 10 submitted its export license application to the 11 Department of Energy. Then in September, just a few 12 months after that, the project initiated our FERC 13 prefiling process, another important milestone to 14 involve the FERC. And the FERC approved that prefiling 15 later that same month. Then in November we received 16 the Department of Energy's approval for the export 17 license application we had submitted as it related to 18 free trade agreement countries. And earlier this year 19 in end of May we received a non free trade agreement 20 export approval from the Department of Energy. And 21 that project wouldn't be a success without that 22 approval. That's a big deal and now we have it in 23 hand. And the relative speed with which that approval 24 was obtained I think that also shows how important the 25 project is on a U.S. federal level and frankly I think M 1 we all owe a debt of gratitude to our congressional 2 delegation for the work they did in helping to achieve 3 that critical milestone for the project. And that 4 approval sends an important message, you know, 5 certainly here in Alaska, but even much more broadly to 6 the world that the Alaska LNG project is real and it's 7 coming. Just last week the FERC chairman visited the 8 Alaska North Slope to review the existing facilities, 9 see the location of the future Alaska LNG project 10 facilities. And I believe that's the first time ever 11 that the acting FERC chairman has visited the Alaska 12 North Slope. 13 All of that context shows that the project 14 momentum is building. Now while there's still much 15 work to be done and clearly there is still much work to 16 be done, we continue to make progress The -- frankly 17 the request before the Commission today is further 18 evidence of the progress that the project is making and 19 as you outlined, Madam Chair, in your opening comments, 20 there are two main components of that request. One is 21 allowing the Prudhoe Bay pool to receive carbon dioxide 22 from the Alaska LNG project and the other is to 23 increase the maximum allowable gas offtake rate at 24 Prudhoe Bay. As I just mentioned Commission approval 25 to allow Prudhoe Bay to receive CO2 from the Alaska LNG 19 1 treatment plant is a critical step in the progression 2 of the project. The Alaska LNG gas treatment plant has 3 been designed to return CO2 to Prudhoe Bay as the 4 participants have stated publicly to the FERC and 5 others. And the requested modifications to the Prudhoe 6 Bay area injection order provide both the flexibility 7 and the certainty necessary for the major gas sale 8 project to move forward. I'll say a bit more about 9 that right now. 10 The second component, the Commission regulatory 11 approval of an increase in the Prudhoe Bay gas offtake 12 rate to 4.1 billion cubic feet per day and that's on an 13 annual average basis, is another critical step in the 14 process. Certainty of Prudhoe Bay gas offtake 15 underpins the upcoming front end engineering and design 16 decision, we're in prefront end engineering and design 17 and that will be the next phase of development, front 18 end engineering design. Spend doing feed as we call it 19 is estimated to be measured in billions of dollars. So 20 it's a huge commitment. And to support that commitment 21 we want to reduce uncertainty wherever we can. We'll 22 have increased confidence in the project that we're 23 evaluating if we have the Commission's approval for the 24 increased offtake we're requesting to 4.1 billion cubic 25 feet per day. And it's not just BP as a project 20 1 participant, but others seek that certainty as well. 2 Perspective LNG buyers will also value security of 3 supply and we believe the 4.1 billion cubic foot per 4 day offtake rate provides that security of supply. 5 Those LNG buyers will be committing for decades and 6 their economies will be based on the certainty that 7 those deliveries will actually occur. And that 8 security of supply will help the Alaska LNG project 9 successfully compete in a crowded marketplace. others 10 will also be looking to provide supply. Project 11 lenders will also value security of supply and will 12 enhance the financeability of the project. And again 13 the requested offtake rate gives perspective lenders 14 increased certainty that they'll be paid. 15 The established 4.1 billion cubic foot per day 16 gas offtake rate will enable many things. It provides 17 for the necessary fuel and North Slope usage, it 18 underpins decades of LNG export, it provides for the 19 possibility that the Alaska LNG project will perform 20 above name plate capacity as we've seen in other LNG 21 projects around the world. And importantly it also 22 accounts for gas for in state use by Alaskans here at 23 home. Creating an opportunity for delivering gas to 24 Alaskans is an important aspect to a successful Alaska 25 LNG project and that's facilitated by the 4.1 billion 21 • 1 cubic foot per day maximum gas offtake rate BP has 2 requested. Deferring a decision to establish a higher 3 Prudhoe Bay gas offtake rate is not prudence. A delay 4 could jeopardize BP's decision to enter into the feed 5 phase of the project and a delay would also 6 unnecessarily impair our ability to market our share of 7 Alaska LNG. The Commission has long understood that 8 Prudhoe Bay gas offtake would need to be revised to 9 support a major gas sale, now is the time. 10 Thank you, Commissioners. I'd be happy to 11 answer any questions that you might have. 12 CHAIR FOERSTER: Commissioner Seamount, do you 13 have any questions? 14 COMMISSIONER SEAMOUNT: I'm going to hold off 15 on questions. 16 CHAIR FOERSTER: Okay. I don't have any 17 questions at this time either. But before you proceed, 18 we don't have a protocol for doing this, but I 19 personally think it's important to highlight some of 20 the statements you made about the importance of our 21 proceedings. I just wanted to point out to the crowd 22 and thank Senator Giessel for being here. I have a lot 23 of respect for Senator Giessel because how seriously 24 she takes her job and because she is one of the few 25 people I know who knows that when you spell Cathy C is 22 1 for correct and K is for knucklehead. So, Senator 2 Giessel, thank you for being here today. And if there 3 are any other members of the Legislature that I missed 4 I apologize to you. 5 So I think you have another witness that's 6 going to come on up and at this time bring him on up 7 and we'll swear him in and find out whether he is -- 8 will be recognized as an expert. 9 MR. VANTYLE: Thank you, Madam Chair. 10 Testifying next for BP will be Bruce Laughlin and he's 11 BP's reservoir management team leader and he'll talk 12 about technical information about the request. 13 CHAIR FOERSTER: Okay. And I want you to 14 remember and everyone else who testifies, if we swear 15 you in and you walk away an then we bring back -- bring 16 you back later today, you're still sworn in. So if 17 you're telling us the truth now you've got to keep 18 telling us the truth the rest of the day. 19 MR. VANTYLE: That's a good practice. 20 CHAIR FOERSTER: And if it's continued tomorrow 21 it carries forward. 22 MR. VANTYLE: Thank you. 23 CHAIR FOERSTER: Okay. Please introduce 24 yourself, your name, who you represent and then I'll 25 swear you in and then we'll go into the do you want to 23 • 1 be recognized as an expert. 2 MR. LAUGHLIN: All right. My name is Bruce 3 Laughlin and you spell the last name L-A-U-G-H-L-I-N. 4 I am employed by BP Alaska, working at BP's Anchorage 5 office. 6 CHAIR FOERSTER: Okay. Raise your right hand. 7 (Oath administered) 8 MR. LAUGHLIN: I do. 9 CHAIR FOERSTER: Thank you. 10 BRUCE LAUGHLIN 11 called as a witness on behalf of BP Exploration Alaska, 12 Inc., testified as follows on: 13 DIRECT EXAMINATION 14 CHAIR FOERSTER: So do you want to be 15 recognized as an expert? 16 MR. LAUGHLIN: I do. 17 CHAIR FOERSTER: In what area? 18 MR. LAUGHLIN: Reservoir engineering and 19 management. 20 CHAIR FOERSTER: All right. Please give us 21 your cred -- I know you've testified before us before, 22 but for this record give us your credentials and allow 23 us to consider whether to accept you as an expert. And 24 keep in mind where I went to college versus where you 25 did. 24 0 • 1 MR. LAUGHLIN: Thank you, Commissioner. I have 2 a bachelor's of science in petroleum engineering from 3 Pennsylvania State University, I also have a masters of 4 science degree in petroleum engineering from Texas A&M 5 University. I recognize the Chair's. 6 CHAIR FOERSTER: Do you see my -- do you see my 7 iPhone? 8 MR. LAUGHLIN: Yes. 9 CHAIR FOERSTER: Okay. Good. Good. Let the 10 pub -- okay. Let's make sure that the camera caught 11 that. All right. 12 MR. LAUGHLIN: I've worked in the oil and gas 13 industry for 30 years. I have worked at -- for the 14 Texas Railroad Commission evaluating West Texas 15 carbonate fields for in field drilling benefits, I've 16 worked for Union Pacific Resources as a reservoir 17 production and drilling engineer with experience in 18 South Texas gas production. I have experience in 19 California working the Wilmington waterflood and FOR 20 steamflood before returning to Texas to work Gulf of 21 Mexico production and exploration projects for Union 22 Pacific. I moved to Alaska in 1995 to work for BP 23 where I initially was a reservoir engineer evaluating 24 development opportunities for the western portion of 25 the Prudhoe oil field. I have performed production 25 1 forecasting and simulation activities within the 2 waterflooding, gravity drainage, waterflood interaction 3 areas of the Prudhoe oil pool and after that I later 4 moved to Kuwait where I was the team manager for the 5 North Kuwait Raudhatain (ph) field which produced from 6 four horizons approximately 400,000 barrels of oil per 7 day. I relocated back to Alaska in 2006 with BP where 8 I have been the Prudhoe Bay unit full field reservoir 9 management team leader evaluating major gas sales, 10 development opportunities and managing the full field 11 modeling team responsible for both static and dynamic 12 modeling. I have brought in analytical and dynamic 13 modeling skills that allow me to evaluate opportunities 14 for development for BP. Previously I have testified as 15 an expert witness before the AOGCC for the inquiry into 16 gas liquids disposition in January of 2014. At this 17 time I would request qualification as an expert witness 18 before the Commission. 19 CHAIR FOERSTER: Thank you. Commissioner 20 Seamount, do you have any questions? 21 COMMISSIONER SEAMOUNT: Mr. Laughlin, just out 22 of curiosity which formations did you work in South 23 Texas? 24 MR. LAUGHLIN: I worked the Frio formation and 25 the McAllen Ranch Vicksburg formation. 26 1 COMMISSIONER SEAMOUNT: Did you -- okay. Well, 2 I think most importantly since you went to the better 3 school in Texas I think that you should be qualified as 4 an expert witness. 5 CHAIR FOERSTER: I too worked the Vicksburg and 6 the Frio in South Texas and I want the record to 7 reflect that Mr. Seamount is not qualified as an expert 8 in which is the better school in South Texas, but I 9 acknowledge that you have a vast quantity and quality 10 of experience and I too recognize you as an expert. So 11 you may please -- you may proceed with your testimony. 12 MR. LAUGHLIN: Thank you, Commissioners. The 13 testimony we have prepared for you is a collective 14 effort of myself, my staff, associates as well as 15 ExxonMobil Alaska production as working interest owners 16 in Prudhoe Bay. Prudhoe Bay major gas sales and the 17 analysis of this project falls within my team and it is 18 my responsibility for accurate analysis of the 19 benefits. I will only be commenting on the Prudhoe oil 20 pool gas delivery opportunity on the project before us, 21 the Alaska LNG project. Specifics about the Alaska LNG 22 project are not part of this scope and would be best 23 asked of the Alaska LNG project team. 24 At this time BP and ExxonMobil are requesting 25 an increase in the maximum allowable offtake rate from 27 • 0 1 Prudhoe oil pool. The increase is from 2.7 bcf per day 2 allowable set in 1977 to a 4.1 bcf per day maximum 3 allowable on an annual average basis. As Mr. Vantyle 4 has testified the current allowable is not sufficient 5 to support the major gas sales into the Alaska LNG 6 project. The expected offtake rate from the Prudhoe 7 oil pool for gas shipments, fuel usage, minor North 8 Slope sales and miscible injectant that is used outside 9 of the Prudhoe oil pool would -- is approximately 3.3 10 to 3.4 bcf per day under normal operations for the 11 project. This request of 4.1 bcf per day provides 12 assurance to both PBU owners and the Alaska LNG project 13 that gas can be delivered during events where Point 14 Thomson unit or third party gas to the gas treatment 15 plant is unavailable. A PBU only full rate stream to 16 the gas treatment plant to accommodate in state sales 17 of gas, chill gas, gas delivery to the LNG for export 18 would increase our need to 4.1 bcf per day. 19 During my presentation which will be separated 20 into a public portion and a confidential section I will 21 give BP -- give a BP as owner technical overview of how 22 Prudhoe oil pool will fit within the overall scope of 23 the Alaska LNG project. In addition I will detail our 24 assumptions for the oil case by which the gas sales 25 case was compared for reference. Finally I will show 1 how BP and ExxonMobil arrived at the proposed maximum 2 allowable offtake rate and illustrate this changes the 3 overall recovery for the Prudhoe oil pool. What I will 4 exhibit during my public testimony today is the 5 negligible difference in ultimate recovery using a 6 reference case gas production stream into the Alaska 7 LNG gas treatment plant also known as the GTP under 8 normal operations and the extreme example of a gas 9 production stream into the GTP when the Prudhoe oil 10 pool is supplying 100 percent of the gas stream to the 11 GTP for the life of the Alaska LNG project. In the 12 confidential section I will share data that contains 13 BPXA's own engineering, geological and geophysical 14 analysis and interpretation of PBU data as well as 15 other sensitive commercial information. 16 Are there any questions at this time before I 17 go through my more formal presentation? 18 CHAIR FOERSTER: Commissioner Seamount, do you 19 have any questions. 20 COMMISSIONER SEAMOUNT: I have none. 21 CHAIR FOERSTER: Nor do I. 22 MR. LAUGHLIN: Slide two. I will give a 23 general overview of the Alaska LNG project, will 24 discuss support for the rule 9 application for 25 amendment of the conservation order 341D, rule 9 for Q • 0 1 the Prudhoe oil pool, give technical justification for 2 increasing the maximum allowable gas offtake from 2.7 3 to 4.1 bcf per day and I'll address several topics of 4 interest for the AOGCC that were brought to us by the 5 technical staff of the Commission. I'll support the 6 application for the area injection order modification 7 of AIO 3A, AIO 4F and provide the technical 8 justification for the request to inject CO2 byproduct 9 into the Prudhoe oil pool for enhanced recovery and 10 pressure maintenance. 11 Slide three basically gives a general overview 12 of the Alaska LNG project. It was made up of six 13 components, major components. The Prudhoe Bay 14 transmission line receiving gas from Prudhoe Bay, it's 15 approximately a one mile pipeline, 60 inches in 16 diameter and it's above ground. We also have the Point 17 Thomson transmission line which is approximately 60 18 miles long, 32 inches in diameter and it also is above 19 ground. Both of those fields will transport their gas 20 to the gas treatment plant which has three trains of 21 CO2 capable of removing for the injection back into the 22 Prudhoe Bay unit. There's an 800 mile pipeline that's 23 42 inches in diameter, it's below ground gas pipeline, 24 it has six to 10 compressor stations and up to five in 25 state optic points. This proceeds into the 30 9 1 liquefaction plant facility, essentially it's a natural 2 gas, it is cooled to minus 260 degree fahrenheit, where 3 the volume has actually shrunk by about 600 times due 4 to the change in temperature. Three trains will 5 actually dehydrate and liquify the gas to produce up to 6 20 million tons of LNG each year. The LNG is moved to 7 storage tanks and then off to the LNG carriers as it 8 proceeds out of the -- out of the Cook Inlet. 9 I want to start by actually talking about the 10 summary and conclusions on page 4. The major gas sales 11 reference case of 3.3 bcf per day and the maximum 12 allowable gas sensitivity case of 4.1 bcf per day, both 13 demonstrate significant additional hydrocarbon recovery 14 as a result of major gas sales from the Prudhoe oil 15 pool. The results that we have seen from the work that 16 we have done is that the major gas sales reference case 17 demonstrates that the Prudhoe oil pool is capable of 18 delivering approximately 22 trillion standard cubic 19 feet of gas or roughly 3.8 billion barrels of oil 20 equivalent, a gas sales plateau of approximately 20 21 plus years and this is all built upon a strong and 22 viable continued oil development and production within 23 the Prudhoe oil pool. The MAG sensitivity case 24 produces an equivalent ultimate hydrocarbon recovery of 25 between 17.7 and 17.8 billion barrels of oil 31 1 equivalent. An increase in the rule 9 gas offtake to 2 an annual average of 4.1 billion standard cubic feet 3 per day is consistent with good oil field engineering 4 practices and positions the Prudhoe Bay unit working 5 interest owners to access the major gas sales 6 opportunity by the Alaska LNG project and therefore 7 should be approved. 8 Slide number 5. The Alaska LNG project has 9 advised gas supply to the gas treatment plant must be 10 maintained during normal operations at a rate of 11 approximately 3.5 bcf per day annual average untreated 12 gas. The gas treatment plant feed rate of 3.5 bcf per 13 day allows for approximately .4 to .5 bcf per day for 14 in state gas demand and 2.7 bcf per day to satisfy the 15 LNG facility inlet demand. Prudhoe oil pools total 16 gas offtake would also include lease fuel, minor North 17 Slope sales and miscible injectant used outside of the 18 Prudhoe oil pool in the Prudhoe Bay unit satellites. 19 4.1 bcf per day allows Prudhoe oil pool flexibility to 20 supply the full GTP rate in the event of supply 21 disruptions from other fields to accommodate improved 22 facility performance and allow operational flexibility. 23 This table below actually states that the Prudhoe oil 24 pool offtake of major gas sales reference case under 25 normal operations would supply approximately 2.7 bcf 32 0 • 1 per day to the AKLNG GTP. PBU believes fuel is 2 approximately .4 bcf per day and minor North Slope 3 sales to Alyeska, Norgasco and Kuparuk River unit as 4 well as miscible injectant outside of Prudhoe oil pool 5 is approximately .2 bcf per day totalling a total of 6 3.3 bcf per day. Under the major gas maximum allowable 7 gas sensitivity case this 3.6 bcf per day to the GTP is 8 slightly higher than the blended rate of Point Thomson 9 and Prudhoe because Prudhoe has a higher CO2 10 concentration. We will have a slightly less lease fuel 11 because we'll be turning down some of the compressors 12 and turbines that we have on the North Slope because 13 we'll be delivering a slightly higher rate, but our 14 North Slope sales will still be roughly .2 bcf per day 15 totalling 4.1 bcf per day. 16 CHAIR FOERSTER: Thank you for answering my 17 questions before I can ask them. 18 MR. LAUGHLIN: Slide number 6 basically 19 illustrates how we're going to get the gas out of 20 Prudhoe Bay. We're going to produce gas from existing 21 well stock and facilities, the -- optimize with 22 targeted recompletion of our gas from our production 23 wells and late in field life we will look at injector 24 to producer conversions for the apex injectors so the 25 AGI wells in the north where we're currently injecting 33 0 • 1 lean gas will be turned around and utilized for 2 production late in field life. We will also have two 3 redundant points at the central gas facility for 4 offtake in the LTS or low temperature separator modules 5 which will have clean dry gas except for CO2. Alaska 6 LNG project participants are designing the GTP to 7 return the CO2 byproduct to PBU. And we've actually 8 looked at several locations within the Prudhoe oil pool 9 and for injection at -- in the Prudhoe oil pool Eileen 10 West End through the new pipeline that we would need to 11 build to existing wells at well pads W and Z. Eileen 12 West End is the most promising option and I will 13 discuss that more in the confidential section when we 14 talk about the details of that. Additional CO2 15 injection options outside of Prudhoe oil pool will be 16 evaluated for additional enhanced recovery opportunity. 17 We will also have backup capability that could be flow 18 station two area which is a mature area of the Prudhoe 19 oil pool on the eastern side of the field as well as 20 the apex injectors in a situation where the pipeline 21 out to the west end may be either pigged for -- to 22 determine how it's handling the CO2 or if it's down for 23 whatever reason, but essentially the CO2 comes back 24 from the GTP through a control module which allows us 25 to either inject into the apex or out through the west 34 • • 1 end to the W and Z pad in the Eileen West End through 2 our miscible injectors we currently have out there. 3 CHAIR FOERSTER: So you have looked at or you 4 are planning to look at FOR opportunities in non BP 5 operated fields? 6 MR. LAUGHLIN: Not non BP operated. 7 CHAIR FOERSTER: Not in non BP operated fields. 8 Okay. Thank you. 9 MR. LAUGHLIN: Slide number 7. The current 10 field activity that we've actually been under prepares 11 us for major gas sales. There is an active drilling 12 program targeting bypassed oil through pattern 13 reconfiguration of the waterflood and additional 14 bypassed oil in the gravity drainage area drilling for 15 low in zone one oil that has not been obtained through 16 the current vaporization process. We will also 17 continue to do or have been doing rig workovers to 18 maintain healthy well stock, we've put a lot of effort 19 and money into doing so. We continued gas cap water 20 injection to the sanctioned volume of 4.2 billion 21 barrels which actually ends in approximately 2027, two 22 years after the start up of gas cap or for major gas 23 sales. We also do active non -rig well work programs to 24 manage economically some of the wells that have been 25 down because of mechanical issues. And a lot of effort 35 • 0 1 has gone into that. We do waterflood and MI management 2 which we've talked about before with the Commission on 3 enhanced oil recovery and we continue to do that as 4 well. BPXA and other unit owners will continue to 5 actively manage field optimization for depletion 6 strategy to enhance the performance of the Prudhoe Bay 7 oil field. 8 I want to just end this section on the 4.1 bcf 9 per day allowable by going back over the major gas 10 sales reference case in our public portion of the 11 testimony. 12 CHAIR FOERSTER: And you're talking to slide 13 number 8 now? 14 MR. LAUGHLIN: Slide number 8. Thank you. We 15 are on slide number 8. The reference case of 3.3 and 16 the maximum allowable case of 4.1 both demonstrate 17 significant additional hydrocarbon recovery from the 18 Prudhoe oil pool as a result of major gas sales. 19 Results of the major gas sales case demonstrates that 20 the Prudhoe oil pool is actually capable of delivering 21 approximately 22 tcf of gas -- of hydrocarbon gas or 22 approximately 3.8 billion barrels of oil equivalent, a 23 gas sales plateau of -- length of approximately 20 plus 24 years and continued oil development and production. 25 The MAG sensitivity case which is the maximum allowable 36 1 gas offtake case produces an equivalent ultimate 2 hydrocarbon recovery of approximately 17.7 to 17.8 3 billion barrels of oil equivalent. An increase in the 4 rule 9 gas offtake to an annual average of 4.1 billion 5 standard cubic feet per day is consistent with good oil 6 field engineering practices and positions the Prudhoe 7 Bay unit working interest owners to access the major 8 gas sales opportunity that's afforded by the Alaska LNG 9 project and as well this should be approved. 10 I'd like to move on briefly to the area 11 injection order in the public portion of the testimony, 12 that's slide nine. We're requesting modification to 13 the area injection order 3A and 4F for the Prudhoe oil 14 pool. We'd like to explain the technical benefits and 15 implications of injection of CO2 into the Prudhoe oil 16 pool and as a summary of that we actually have looked 17 at CO2 handling limitations and impact of CO2 injection 18 in other development operations options around the 19 Prudhoe oil pool. The Prudhoe oil pool is injecting a 20 similar amount of CO2 under current field operations of 21 approximately 800 million cubic feet a day and we don't 22 see that changing very much under our gas sales 23 scenario. Eileen West End is the most promising 24 location for CO2 injection within the Prudhoe oil pool 25 itself. Additional CO2 from outside sources generates 37 1 negligible changes to the Prudhoe oil pool reservoir 2 outcomes. And BPXA has studied and anticipates that 3 the PBU working interest owners will continue to 4 evaluate potential locations where CO2 injection may be 5 economically beneficial for enhanced recovery and 6 pressure maintenance. 7 CHAIR FOERSTER: Will the owners be looking at 8 non BP operated and will the owners be open to 9 opportunities that other operators on the North Slope 10 may identify and come to you for? 11 MR. LAUGHLIN: I believe that is the case. 12 CHAIR FOERSTER: Okay. Thank you. 13 MR. LAUGHLIN: I'll give you a quick summary of 14 the confidential portion of BPXA's testimony before we 15 do enter into that confidential piece. 16 CHAIR FOERSTER: And you're referring to slide 17 10. 18 MR. LAUGHLIN: We'll give a discussion of a 19 full field model and the quality and uses, we'll talk 20 about the forward prediction of the oil reference case 21 by which we compare the gas sales cases to it, we'll be 22 giving a detailed discussion of the comparative cases 23 and their assumptions, also to give a description of 24 gas delivery and CO2 handling, we'll talk about major 25 gas sales reference case profile, the maximum allowable W. • 1 gas sensitivity case profile, the expected recovery 2 comparison, the major gas sales start date sensitivity 3 which I think might address some of the information 4 that you had requested earlier. We'll talk about the 5 area injection order modification, we'll also look at 6 CO2 studies that have already been conducted within the 7 Prudhoe oil pool and outside of Prudhoe oil pool and 8 then we'll talk about Prudhoe oil pool and non Prudhoe 9 oil pool CO2 recovery estimates. 10 That concludes my public portion of the 11 testimony. 12 CHAIR FOERSTER: Okay. Commissioner Seamount, 13 do you have any questions at this time? 14 COMMISSIONER SEAMOUNT: Mr. Laughlin, how 15 confident are you that CO2 will improve -- will be 16 effective as an FOR agent in the -- in the pool? 17 MR. LAUGHLIN: We term it as enhanced recovery 18 is the opportunity that stands before us to put back in 19 the reservoir the CO2 that we're actually producing 20 today while taking out the hydrocarbon portion and 21 selling it down the pipeline. So this enhanced 22 recovery is actually part of the overall project to 23 deliver gas to the Alaska LNG project. 24 COMMISSIONER SEAMOUNT: And does -- can the 25 pool take all the CO2 that's dripped out? 39 0 • 1 MR. LAUGHLIN: Yes. 2 COMMISSIONER SEAMOUNT: And as -- as you 3 produce more and more of the hydrocarbons I assume that 4 the CO2 percentage injected back into the pool is going 5 to be going up? 6 MR. LAUGHLIN: It's -- and we'll actually talk 7 about that in the confidential section, but it actually 8 is managed very effectively. 9 COMMISSIONER SEAMOUNT: Okay. And you're not 10 worried about corrosion? 11 MR. LAUGHLIN: We are worried about corrosion 12 as we had said, but there is -- there are some CO2 13 limitations. 14 COMMISSIONER SEAMOUNT: Okay. 15 MR. LAUGHLIN: Uh-huh. 16 COMMISSIONER SEAMOUNT: That's all I have. 17 CHAIR FOERSTER: Okay. I have several 18 questions, but I want to know whether we should take a 19 recess and see if technical staff have any additional 20 questions and let people have a chance to go powder 21 their noses and then come back. 22 COMMISSIONER SEAMOUNT: That's probably a good 23 idea. I -- I had some questions on the confidential 24 literature that was passed out, but we could probably 25 discuss that in a recess too. 40 0 • 1 CHAIR FOERSTER: Okay. All right. At 10 2 minutes until 10:00 we're going to take a recess and we 3 will reconvene at 10:00 minutes after 10:00. 4 (Off record) 5 (On record) 6 CHAIR FOERSTER: .....other than yourself, who 7 that is, and then I'll swear you in. 8 MR. LAKOSH: Okay. Thank you very much. My 9 name is Tom Lakosh, L-A-K-O-S-H. I'm an owner -- 10 public owner of the resources on the North Slope and 11 have no other group affiliation. 12 CHAIR FOERSTER: Okay. So I'll swear you in. 13 Right hand's raised. 14 (Oath administered) 15 MR. LAKOSH: Yes, I do so affirm. 16 TOM LAKOSH 17 called as a witness on his own behalf, testified as 18 follows on: 19 DIRECT EXAMINATION 20 CHAIR FOERSTER: Okay. And would you like to 21 be recognized as an expert in any particular area? 22 MR. LAKOSH: No. 23 CHAIR FOERSTER: Okay. Well, then -- can 24 people in the back hear? 25 (No comments) 41 9 • 1 CHAIR FOERSTER: Okay. Please proceed, Mr. 2 Lakosh. 3 MR. LAKOSH: Oh, I came to speak to you this 4 morning and I apologize for not being able to read from 5 prepared statements, my printer failed on me this 6 morning so I'm going to try and email you some written 7 comments later today. But my major concern was the 8 maintenance of -- of pool pressures and the 9 efficaciousness of the CO2 injection as a enhanced oil 10 recovery device. My studies suggest that, yes, CO2 is 11 a very effective enhanced oil recovery method and 12 particularly with concurrent injection of natural gas 13 liquids in 15 to 30 percent, even full recovery of head 14 royals in fields which are presently laying fallow due 15 to the inability of the lessees to fully exploit those 16 resources. And what my concern is is that the removal 17 of the natural gas from the reservoirs will greatly 18 exceed the reinjection of CO2 and that I would like the 19 Commission to closely examine the -- the unit operators 20 -- unit operator and the -- now the interest owners who 21 seem to disagree about the amount of gas that could be 22 reasonably extracted to see if they could potentially 23 capture and inject CO2 from their power production 24 sources as a cost effective means of continued oil 25 production with this enhanced oil recovery techniques 42 1 using CO2 and particularly high temperature, high 2 pressure CO2 with natural gas liquids. 3 I've been examining methods to reduce the 4 carbon footprint of our hydrocarbon industry, I've come 5 across a particular technology called the super 6 critical CO2 turbine for power production that is an 7 oxyfuel process that allows for easy capture and 8 sequestration and use for enhanced oil recovery or 9 chemical synthesis that are symbiotic. And one of the 10 subcontractors on the Alaska LNG line, Chicago Bridge 11 and Iron, is one of the co -producers with Net Power and 12 Toshiba in the production of this. Now this is still 13 an emergent technology, but I request that the 14 Commission both look prospectively and retroactively on 15 the potential of the CO2 recovery and where we are now 16 being informed that this is a viable method of enhanced 17 oil recovery, whether it has been in the past a deficit 18 in oil recovery capability due to the lack of CO2 19 injectants and miscible injectants in the past, that 20 there be compensation for the lack of that productivity 21 and to ensure in the future that there is the highest 22 pool pressures and enhanced oil recovery capability 23 through full sequestration of the CO2 in -- in it's 24 best use and form. Particularly with this turbine you 25 may be able to get higher pressures and temperatures 43 1 and not have to pump the CO2 at all. 2 And then I'm concerned that there be an open 3 mind left for advancement of these technologies and use 4 of either absorbents or oxyfuel technologies to ensure 5 that these CO2 effluents are properly sequestered not 6 only for maintenance of the field in oil production, 7 but for the long term ability to utilize the area where 8 our ability to grow (ph) is increasingly becoming 9 shorter and shorter, our drilling seasons are becoming 10 shorter and shorter due to the global warming affects. 11 If you could set the standard here for enhanced oil 12 recovery using CO2 that could be adopted industry wide 13 it will not only increase all productivity in the short 14 term, but in the long term allow us longer drilling 15 seasons that will allow us to exploit our resources on 16 the open market. 17 Thank you very much for this opportunity to 18 testify. I hope to answer any questions the Commission 19 might have. 20 CHAIR FOERSTER: Thank you. Commissioner 21 Seamount, do you have any questions? 22 COMMISSIONER SEAMOUNT: Yes, Mr. Lakosh. You 23 say you're an owner on the North Slope? 24 MR. LAKOSH: Yeah, our constitution provides us 25 each individually as a -- as a citizen owner..... 44 0 0 1 COMMISSIONER SEAMOUNT: Okay. 2 MR. LAKOSH: .....of the natural resource, 3 requiring proper consideration of its exploitation and 4 concurrent reasonable uses and compensation for lack 5 there of. And so I think my representatives in the 6 state DNR who obtain revenues from these fields ought 7 to be adequately compensated for the failure to 8 properly exploit the resources in their fullest -- to 9 their fullest extent using these enhanced oil recovery 10 techniques for capture of CO2 from the gas extraction 11 process itself and from power production..... 12 COMMISSIONER SEAMOUNT: Okay. 13 MR. LAKOSH: .....as well. 14 COMMISSIONER SEAMOUNT: Well, that's our job to 15 protect the public interests in oil and gas. I have no 16 further comments or questions. Thank you..... 17 CHAIR FOERSTER: Okay. 18 COMMISSIONER SEAMOUNT: .....Mr. Lakosh. 19 CHAIR FOERSTER: And my only -- I only have a 20 comment. And I just wanted to thank you for taking 21 time and give -- especially given your health 22 considerations to come in and express in your own words 23 what I consider to be our primary objective, to make 24 sure that greater ultimate recovery is achieved so -- 25 for the citizens of the state of Alaska. So thank you. 45 0 s 1 MR. LAKOSH: And I might add that I think it's 2 wholly inappropriate for BP to come in as an individual 3 lessee and there should have been consensus obtained as 4 a unit operator. I think you should send them back to 5 their drawing board and get them -- get them in sync 6 with ConocoPhillips before they present to this 7 Commission a plan for exploitation. That's their duty 8 as unit operator. I think they need to -- they need to 9 publish those technical studies as possible when, you 10 know, appropriate redaction for trade secrets and so 11 forth, but the public deserves to know that their 12 resources are being extracted with all cost 13 effectiveness and the maximum extent possible. So 14 please send them back and -- to get a consensus with 15 Conoco and have them publish as extensively as possible 16 the prospect of replacing and maintaining pool 17 pressures and using enhanced oil recovery techniques to 18 ensure the proper development of our hydrocarbon 19 resources. 20 Thank you. 21 CHAIR FOERSTER: Thank you. So at this time we 22 do have a few questions for Mr. Laughlin. Did you have 23 any questions before I launch into mine? 24 COMMISSIONER SEAMOUNT: During the recess I 25 expressed my questions and..... 46 0 0 1 CHAIR FOERSTER: You want me to capture them? 2 COMMISSIONER SEAMOUNT: .....in deference to 3 the Chair I'll let you handle it and if you miss 4 something or if I disagree I'll be sure to let you 5 know. 6 CHAIR FOERSTER: Okay. You bat cleanup. Okay. 7 My first question refers to your prefiled testimony, I 8 just want to get some clarification. In your prefiled 9 testimony you reference a 3.8 billion barrels 10 equivalent and a 3.6 billion barrels equivalent oil and 11 I want to make sure I understand. The 3.8 billion 12 barrels of equivalent oil is the 22 tcf of gas that you 13 expect to recover and that the 3.6 billion barrels is 14 the net increase in ultimate recovery implying that 15 there's .2 billion barrels of oil losses, that 16 result..... 17 MR. LAUGHLIN: I wouldn't call them losses, I 18 would call them -- yes, there is a difference in oil 19 production based upon the assumptions that we have 20 made. 21 CHAIR FOERSTER: Okay. What would you call 22 them? 23 MR. LAUGHLIN: I would call them the -- they 24 are opportunities that we're going to continue to..... 25 CHAIR FOERSTER: There's an opportunity to lose 47 i 0 1 200 million barrels. Okay. 2 MR. LAUGHLIN: We're going to continue to do so 3 with the reflection and we'll talk about this more in 4 the confidential section, about the importance of what 5 the gas production actually does for the oil. 6 CHAIR FOERSTER: Okay. So the 3.8 represents 7 the gas that will be produced and the 3.6 acknowledges 8 that .2 billion barrels or 200 million barrels will be 9 opportunistically lost. Okay. 10 MR. LAUGHLIN: Yes. 11 CHAIR FOERSTER: That's accurate. Okay. 12 Semantics are important, aren't they. My second 13 question for you is I -- I'd like for you to discuss 14 with us a composite of what is being presented today in 15 a context comparing it to the results that we discussed 16 in 2007, the last time we visited the Prudhoe Bay 17 offtake. At that time timing was important and several 18 remediation procedures and steps needed to be 19 undertaken by BP. Could you give me a little context, 20 is timing still important, what has BP done, how does 21 what you're -- what you're recommending today compare 22 with the findings of 2007. So it's not really a 23 question, it's a prompt for you to explain some things 24 that probably would serve the public good. 25 MR. LAUGHLIN: That would be a good question to 0 1 ask. The issue that we had in 2007 was we were 2 anticipating gas sales in the early 2014 to 2015 time 3 frame which would have increased the differences in oil 4 production on a reference sales portion. It also was a 5 big pipe discussion that would have sent a lot more gas 6 down a pipeline to Chicago which is different that what 7 we've got right now and allowed us to have a higher CO2 8 contact in that gas stream going downstream. With the 9 LNG project that we have right now there is a smaller 10 quantity of CO2 that can be shipped down the pipeline 11 to the LNG facility. And so it's a difference in what 12 will be returned to the Prudhoe oil pool at this time. 13 And the aspect is that we've moved on 10 years beyond 14 that 2014 and 2015 time frame of the 2007 study and 15 we've found and will show this in a little bit more 16 detail in the confidential section, that there is a 17 timing that actually is appropriate for this project as 18 we can see it. Now the project has been laid out 19 before us as we see right now from the Alaska LNG 20 project of 2025 which is almost 11 years beyond where 21 we were before. 22 CHAIR FOERSTER: Okay. I have a couple more 23 questions. When I testify before the Legislature I 24 always tell them that this is a multi variable problem 25 and that it all depends on when we start and how much 49 • 1 and what things we've done in the meantime to get as 2 much oil out of the ground as possible. Just -- yes or 3 no, am I telling them the truth when I say that? 4 MR. LAUGHLIN: This is a resilient field and it 5 has a lot of energy stored up because of the gas in 6 place. 7 CHAIR FOERSTER: Is that a yes or a no? 8 MR. LAUGHLIN: Yes. 9 CHAIR FOERSTER: Okay. So what steps -- you 10 know, to me a big part of making it the right time to 11 sell the Prudhoe Bay gas is that as much of that 12 Prudhoe Bay oil has been removed as possible. Could 13 you for the public record outline what BP's been doing 14 since 2007 to accelerate oil production from the 15 Prudhoe Bay pool? 16 MR. LAUGHLIN: We continue to do significant 17 development in the field through drilling, rig 18 workovers, targeting vapor born liquids as best we can 19 through surveillance programs that we have, we continue 20 to do gas cap water injection to maximize vaporization 21 through pressure increases in the reservoir, we 22 optimize our MI strategy so that we utilize the 23 miscible injection that we currently have available to 24 us to produce oil at its highest value. We've also 25 done pattern reconfiguration in the reservoir to find 50 • 0 1 ways to find, you know, sweep issues that were in the 2 waterflood due to the maturity of those patterns. And 3 we continue to look through the Sag River formation to 4 find opportunities to development that amount oil that 5 is currently in that -- in that reservoir as well. 6 CHAIR FOERSTER: Is ever a rig that's available 7 for use on the North Slope busy? 8 MR. LAUGHLIN: All the rigs we have available 9 are busy. 10 CHAIR FOERSTER: Okay. I have another 11 question. We often hear they're warehousing our gas, 12 it's our gas, we want the gas now and there was an 13 editorial in the paper a few days ago about how we 14 haven't -- we didn't do this is 1977 and we should 15 have. Had we done this in 1977 what would have been 16 the ultimate recovery of oil from Prudhoe Bay oil pool? 17 MR. LAUGHLIN: A lot less than where we're at 18 right now. 19 CHAIR FOERSTER: Okay. So in that context how 20 -- what would be the impact on ultimate recovery of oil 21 from Prudhoe Bay oil pool of doing what you're now 22 proposing? 23 MR. LAUGHLIN: It's a small difference in the 24 14.2 billion or 14.1 billion barrels that we're 25 actually looking at as far as total recovery due to the 51 0 0 1 continued operations we have in place right now through 2 the end of field life. 3 CHAIR FOERSTER: Okay. So right now you're 4 projecting between 14.1 and 14.2 billion barrels of 5 ultimate recovery..... 6 MR. LAUGHLIN: That's correct. 7 CHAIR FOERSTER: .....and..... 8 MR. LAUGHLIN: Under the current economic 9 climate..... 10 CHAIR FOERSTER: Right. 11 MR. LAUGHLIN: .....I think it's important to 12 state that. 13 CHAIR FOERSTER: Right. Right. So you're all 14 going to go home and pray for high oil prices, but the 15 impact of major gas sales on that 14.1, 14.2 is .2? 16 MR. LAUGHLIN: .2 out of..... 17 CHAIR FOERSTER: Okay. 18 MR. LAUGHLIN: ..... 14.1..... 19 CHAIR FOERSTER: Okay. 20 MR. LAUGHLIN: .....and 14.2. 21 CHAIR FOERSTER: And how -- could you get -- 22 that -- you know, .2 billion barrels is a big oil 23 field, you know, that -- that's not -- you know, I know 24 several little companies who would love to find .2 25 billion barrels of oil. 52 0 • 1 MR. LAUGHLIN: (Indiscernible - simultaneous 2 speech) in a little more detail. The oil column that 3 we currently have is approximately 400 feet. And this 4 .2 billion barrels -- .2 billion barrels that we're 5 talking about is spread out over 250 square miles of 6 reservoir and 400 foot column. It's not all in one 7 pocket available for us to go pursue. Some of it won't 8 be because of the pressure decline in the reservoir so 9 vaporization's not going to be capable of recovering 10 some of that fluid that we will -- we have out there 11 because the energy is decreased in the reservoir. 12 CHAIR FOERSTER: So I've also heard stated that 13 the oil loss -- the projected oil losses are within the 14 uncertainties of the model, is that an accurate -- 15 that there's enough uncertainty in the model that .1 or 16 .2 billion barrels is -- is it within that uncertainty, 17 is that a fair statement or are you more proud of your 18 model than that? 19 MR. LAUGHLIN: I'm more proud of the model 20 as..... 21 CHAIR FOERSTER: Okay. 22 MR. LAUGHLIN: .....we sit here. For that type 23 of volume I think..... 24 CHAIR FOERSTER: You're getting more proud as 25 we sit here? 53 i 0 1 MR. LAUGHLIN: Yes. 2 CHAIR FOERSTER: Okay. 3 MR. LAUGHLIN: Yeah, the staff that I have 4 working with me is very capable of understanding the 5 uncertainties of that model. The uncertainties and the 6 assumptions associated with that may change over time 7 and obviously with new technology that may come along 8 between now and the time that major gas sale starts up 9 is the opportunity for us to continue to pursue 10 relevant activity as long as it's economic for the 11 opportunity we see in front of us. 12 CHAIR FOERSTER: Okay. And that -- I want to 13 ask a question that was begged by Mr. -- I know, I'm 14 going to mispronounce your name, Mr. Lakosh? 15 MR. LAKOSH: Lakosh. 16 CHAIR FOERSTER: Lakosh. I'm sorry. Mr. 17 Lakosh's testimony, but it's one of the things that you 18 guys get tired of hearing me ask. Although we are 19 looking at greater ultimate recovery from the Prudhoe 20 oil pool I share the concern that the gas that's on the 21 North Slope is all currently being used to get greater 22 ultimate recovery of oil from not only the Prudhoe oil 23 pool, but gas being exported to other fields and that 24 sort of thing and I understand that -- I appreciate 25 that there's 20 plus billion barrels of viscous and 54 i �J 1 heavy oil out there that (indiscernible) that aren't 2 being commercialized and we don't see it right now, but 3 as technology advances it might be. What role could 4 having gas available on the North Slope for such future 5 opportunities play and would those be lost if we moved 6 this gas off the Slope? 7 MR. LAUGHLIN: For the right price I'm sure 8 that we would be willing to encourage other 9 opportunities on the North Slope for the gas that's 10 available. As we see it right now we still are 11 shipping approximately .2 bcf per day through MI in and 12 around the Prudhoe oil pool as well as the 13 opportunities that we're shipping gas to the Kuparuk 14 formation or Kuparuk River unit for utilize -- 15 utilization for their activities. 16 CHAIR FOERSTER: So what I'm hearing you say is 17 every opportunity that's asking for gas is getting it? 18 MR. LAUGHLIN: Well, for the ones that we've 19 seen so far. 20 CHAIR FOERSTER: Okay. But do you have any I 21 would say educated opinion on what other opportunities 22 are out there that might be lost by moving the gas off 23 the North Slope? 24 MR. LAUGHLIN: I can't honestly comment on that 25 because I don't know whether other opportunities may 55 1 become available by other operators that may go out and 2 explore for gas because of this opportunity that's 3 in..... 4 CHAIR FOERSTER: Okay. 5 MR. LAUGHLIN: .....front of us. 6 CHAIR FOERSTER: Okay. Do you have an opinion 7 -- an educated opinion as a reservoir engineering 8 expert on the potential for using the gas that's up 9 there right now for the 20 plus billion barrels of 10 viscous oil that we know is there? 11 MR. LAUGHLIN: There's also opportunities to 12 high grade the oil that's there and utilize that for 13 fuel to help encourage enhanced recovery from that 20 14 billion barrels as well. 15 CHAIR FOERSTER: Okay. Okay. One of the -- I 16 know you don't want to go into the confidential 17 testimony right now, but before we let you off the hook 18 we have some serious concerns about the confidentiality 19 request that you've made. As I said at the start of 20 the hearing it's our job to make sure that everything 21 that can be made available to the public is made 22 available to the public and as we go through your 23 confidential section we need to ensure that everything 24 that you've requested be kept confidential deserves 25 confidentiality. And if BP and the Commission disagree 56 1 on whether something deserves confidentiality we will 2 provide you the opportunity to withdraw that or 3 consider it public because if we feel that something 4 doesn't deserve confidentiality and you insist on 5 holding it confidential we will insist that you redact 6 it from your testimony and we will not consider it in 7 our deliberations. So this would probably be a good 8 time for us to go page by page through the confidential 9 session. We will not put it up, show any numbers, show 10 any graphs, show any maps, but we'd like to page by 11 page discuss the content vaguely described of your 12 confidential section on the public record and allow you 13 the opportunity to justify to us its confidentiality 14 and if you're not able to do that make a decision as to 15 whether you want to redact it from your testimony or 16 leave it in as public. So since I've been blab, blah, 17 blahing most of the day I'm going to turn it over to my 18 sidekick here and let him ask these questions. 19 MR. LAUGHLIN: So I just want to make sure that 20 I'm not the one that's going to determine whether or 21 not we're -- we got a confidential (indiscernible - 22 simultaneous speech)..... 23 CHAIR FOERSTER: You can tag team, you can call 24 a friend, you can use a lifeline, whatever you want to 25 do. 57 • 1 MR. LAUGHLIN: A lifeline would be really good 2 right now. 3 CHAIR FOERSTER: Okay. Okay. 4 COMMISSIONER SEAMOUNT: So maybe you should get 5 your lifeline up..... 6 CHAIR FOERSTER: Yeah. 7 COMMISSIONER SEAMOUNT: .....here right now. 8 CHAIR FOERSTER: Yeah. 9 COMMISSIONER SEAMOUNT: Before we talk about 10 that I have just one more question about your public 11 testimony. On page 5 you have a table that shows minor 12 North Slope gas sales of .2 feet..... 13 MR. LAUGHLIN: BCF per day. 14 COMMISSIONER SEAMOUNT: .....bcf and according 15 to if your application is approved it continues at .2, 16 will that continue indefinitely or is that going to 17 decline similar -- at some time to the gas decline? 18 MR. LAUGHLIN: Our assumption is that .2 bcf 19 per day it utilized for Alyeska, Norgasco, Kuparuk 20 River unit, and we've just made the assumption in our 21 statement that it's going to be consistent throughout 22 the full project life. 23 COMMISSIONER SEAMOUNT: Does that include MI? 24 MR. LAUGHLIN: It does include MI. 25 COMMISSIONER SEAMOUNT: Okay. Okay. Let's go 1 to confidential stuff. The very first page where it 2 says confidential presentation, that's not meant to be 3 confidential, is it? 4 MR. LAUGHLIN: That's correct. 5 COMMISSIONER SEAMOUNT: Okay. Page 2, I think 6 you've already said this in your..... 7 MR. LAUGHLIN: We talked about that one in the 8 previous presentation. 9 COMMISSIONER SEAMOUNT: Right. So that's not 10 confidential. 11 MR. LAUGHLIN: Page 3 is the same, it's not 12 confidential. 13 COMMISSIONER SEAMOUNT: Page 3 is not 14 confidential. 15 MR. LAUGHLIN: Page 4 discusses the full field 16 model, that is confidential. 17 COMMISSIONER SEAMOUNT: Okay. Why do you 18 consider it confidential? 19 MR. LAUGHLIN: It includes proprietary BP 20 information. 21 COMMISSIONER SEAMOUNT: Would you consider 22 history matches as confidential? 23 MR. LAUGHLIN: No, more the -- the tool itself. 24 COMMISSIONER SEAMOUNT: Or the pool? 25 CHAIR FOERSTER: Tool, T-O-O..... 59 1 MR. LAUGHLIN: T-O-O-L. 2 CHAIR FOERSTER: So one slide four -- I'm 3 looking for the description of the tool that's 4 confidential, would it be the picture of the model? 5 MR. LAUGHLIN: The model, the surface, pipeline 6 (indiscernible - simultaneous speech)..... 7 CHAIR FOERSTER: Those two pictures? 8 MR. LAUGHLIN: Uh-huh. 9 CHAIR FOERSTER: But the graph and the words 10 would not be confidential? 11 MR. LAUGHLIN: The graph actually is an outcome 12 of the model itself so I would include that as 13 confidential. But I defer that to my counsel. 14 COMMISSIONER SEAMOUNT: But if the outcome of a 15 model -- I mean, that's what this whole thing is about 16 is the outcome of the model and if you don't discuss 17 the workings of the model then I don't see how that 18 would be confidential..... 19 CHAIR FOERSTER: The results of the model 20 shouldn't be..... 21 COMMISSIONER SEAMOUNT: .....the results of the 22 model. 23 CHAIR FOERSTER: .....shouldn't be 24 confidential. 25 MR. LAUGHLIN: The model itself actually is a M1 1 proprietary tool of BP and the results that come out of 2 that actually are from BP's proprietary tool. So the 3 history match is part of that tool. 4 CHAIR FOERSTER: Okay. Well, before we get 5 into the in camera session we'll have a recess where 6 we'll decide what we want to do with this and give you 7 an opportunity to respond to whatever we decide. Does 8 that sound fair? 9 COMMISSIONER SEAMOUNT: Yes, I'm just -- I'm 10 trying to understand if -- there's a number of models 11 out there I assume and you can get -- you can get 12 different results from different models, but I don't 13 see how the results of your proprietary model, how 14 someone can -- I mean, could someone go backwards, back 15 calculate, figure out the tool? 16 MR. LAUGHLIN: Very difficult, not possible. 17 COMMISSIONER SEAMOUNT: Then I'm having a hard 18 time understanding how it would be proprietary. 19 CHAIR FOERSTER: Me too. 20 MR. LAUGHLIN: Could we just ask you to make 21 the decision whether it's confidential or not. 22 CHAIR FOERSTER: Okay. You know, Coca-Cola has 23 it's recipe confidential, but it doesn't prohibit 24 people from drinking coke. 25 COMMISSIONER SEAMOUNT: Yes, but diabetes does. 61 • 1 CHAIR FOERSTER: Oh, okay. Okay. Okay. And 2 so keep in mind that anything that we disagree on 3 whether it's confidential or not will not be allowed to 4 be included in the confidential testimony and will not 5 be considered in our decision. Okay. All right. Go 6 ahead. 7 COMMISSIONER SEAMOUNT: Okay. Page 5, can you 8 describe what -- without divulging what you think is 9 confidential, can you describe what it shows? 10 MR. LAUGHLIN: I actually have no issues with 11 this being nonconfidential. 12 COMMISSIONER SEAMOUNT: Okay. Page 6, why 13 would that be confidential? 14 MR. LAUGHLIN: It's a forward projection of our 15 oil projection and cumulative production. 16 CHAIR FOERSTER: It's a model result? 17 MR. LAUGHLIN: Model result. 18 CHAIR FOERSTER: So it's the same concern as on 19 slide four? 20 MR. LAUGHLIN: Yes. 21 COMMISSIONER SEAMOUNT: Okay. 22 CHAIR FOERSTER: And the verbiage that goes 23 with that set of graph -- that graph, is the verbiage 24 confidential? 25 MR. LAUGHLIN: No, because I have basically 39) 0 • 1 stated most of what's in that verbiage. 2 CHAIR FOERSTER: Okay. 3 MR. LAUGHLIN: Can we get a clarification, you 4 said that if it's -- if you conclude it's not 5 confidential it won't be considered, we'll be given the 6 opportunity to present it publicly at that point if we 7 concur? 8 CHAIR FOERSTER: If we don't agree with you 9 that it warrants confidential treatment then you have 10 to make the choice of whether you want it included in it our deliberations or not and if you want it included in 12 our deliberations it has to be considered as 13 nonconfidential. If we -- if we feel it does not 14 warrant confidentiality we won't include it unless it's 15 public. 16 MR. LAUGHLIN: Unless it's public? 17 CHAIR FOERSTER: Yeah. 18 MR. LAUGHLIN: Thank you. 19 CHAIR FOERSTER: And it -- the main reason for 20 this is should this go to a court, you know, a court is 21 going to need to feel that we protected your 22 confidentiality, but we've done our best to provide the 23 public with nonconfidential information. 24 COMMISSIONER SEAMOUNT: Well, provide the 25 public with what they need to know to make sure we made 63 • 1 a fair and impartial decision. 2 CHAIR FOERSTER: That too. 3 COMMISSIONER SEAMOUNT: I think you said that 4 sort of. 5 CHAIR FOERSTER: I meant to. Okay. So go 6 ahead. 7 COMMISSIONER SEAMOUNT: Page 7, I think we'll 8 have the same issue with this graph. Can you describe 9 it, please? 10 MR. LAUGHLIN: It is the Prudhoe oil pool 11 voidage from oil, water and gas. It does have some 12 forward prediction of production, but there is the 13 historical portion as well which is noncon -- is that 14 -- we can talk about. 15 COMMISSIONER SEAMOUNT: There's a what? 16 CHAIR FOERSTER: It's the history part. 17 MR. LAUGHLIN: History piece that you can get 18 most of this from the public sources except for the 19 forward prediction from 2015 onward. 20 CHAIR FOERSTER: So from mid 2015 on it's your 21 projection and that -- you want that to be 22 confidential. Okay. And the verbiage at the bottom? 23 MR. LAUGHLIN: Yeah, I can speak to that, 24 that's nonconfidential. 25 CHAIR FOERSTER: Okay. All right. I think 64 0 • 1 we'll have to take a recess to talk before we can forge 2 ahead on what we want confidential and non -- what we 3 agree with them on and don't. But it -- this is 4 important. 5 COMMISSIONER SEAMOUNT: It looks to me like 6 page 8 is -- has already been presented in the..... 7 MR. LAUGHLIN: Yes, it has. 8 COMMISSIONER SEAMOUNT: Okay. So that's not 9 confidential. 10 MR. LAUGHLIN: Yeah, many of these slides we 11 have in this section are actually holdovers from the 12 previous to allow context to what we're presenting. 13 COMMISSIONER SEAMOUNT: Page 9. 14 MR. LAUGHLIN: Same thing. 15 COMMISSIONER SEAMOUNT: Not confidential? 16 MR. LAUGHLIN: No, nonconfidential. 17 CHAIR FOERSTER: So at the end of this we'll 18 probably be asking you guys to resubmit a redacted 19 version of this just so that the public can see what 20 they're not getting to see. Does that make sense, see 21 the gaps. We'd like a redacted version of this 22 document that's got holes in it so the public can say, 23 okay, that's what I don't get to see. 24 MR. LAUGHLIN: We can do that. 25 CHAIR FOERSTER: Okay. 65 0 • 1 COMMISSIONER SEAMOUNT: Okay. At page 10 and 2 11 are decline profiles? 3 MR. LAUGHLIN: That's correct. We consider 4 those forward predictions..... 5 CHAIR FOERSTER: Okay. 6 MR. LAUGHLIN: .....and confidential. 7 COMMISSIONER SEAMOUNT: Okay. Well, we -- I 8 have the same concerns over those. 9 CHAIR FOERSTER: Okay. 10 COMMISSIONER SEAMOUNT: I mean, that's -- 11 that's what this is all about. At page 12 could you 12 describe that, that..... 13 MR. LAUGHLIN: Predication results and gas 14 treatment plant gas supply. And that one has forward 15 predictions as well and detailed curves associated with 16 that prediction. 17 CHAIR FOERSTER: Okay. 18 COMMISSIONER SEAMOUNT: Could you explain again 19 to me, to us, why forward predictions would be 20 confidential? 21 MR. LAUGHLIN: They consist of our engineering 22 analysis actually provided through our full field model 23 proprietary tool that we currently use. 24 COMMISSIONER SEAMOUNT: Okay. 25 CHAIR FOERSTER: We just want to get this •• 1 dialogue on the record and we want to get your thoughts 2 and justifications into our head so that during our 3 next recess we can come to some agreement with some 4 consulting from our legal counsel and then before we go 5 into confidential testimony we'll lay out what we feel 6 should be confidential and shouldn't..... 7 MR. LAUGHLIN: I understand. 8 CHAIR FOERSTER: .....and then we'll move 9 forward. We're not trying to pull any punches or 10 anything, we're just trying to be as fair to everybody 11 as we can. So you want to go into 13? 12 COMMISSIONER SEAMOUNT: Okay. Page 13, could 13 you describe what it shows? 14 MR. LAUGHLIN: Prediction results and average 15 reservoir pressure. And the decline of pressure due to 16 offtake of gas from the reservoir. 17 COMMISSIONER SEAMOUNT: You con -- do you 18 consider the verbiage confidential? 19 MR. LAUGHLIN: No. 20 CHAIR FOERSTER: The..... 21 COMMISSIONER SEAMOUNT: But you consider the 22 graph confidential? 23 MR. LAUGHLIN: I do. 24 CHAIR FOERSTER: Okay. 25 COMMISSIONER SEAMOUNT: Okay. Page 14, can you 67 1 describe that and what would be -- what you would 2 consider confidential and what not confidential? 3 MR. LAUGHLIN: The major gas sales and maximum 4 allowable gas offtake sensitivity cases and oil 5 reference case from the Prudhoe oil pool, its oil and 6 NGL offtake. The confidential section is -- are the 7 curves associated with the recovery. They have come 8 from our model, but we've discussed the table on the 9 left-hand side which basically talks about recovery in 10 cumulative BOEs. 11 COMMISSIONER SEAMOUNT: Okay. Good. Okay. 12 Page 15, same questions. 13 MR. LAUGHLIN: Key prediction results and the 14 BOE production. And this is -- again the graph at the 15 top of the page discusses or illustrates the recovery 16 from both gas and oil. 17 CHAIR FOERSTER: And..... 18 MR. LAUGHLIN: And it is a prediction from our 19 full field model. 20 COMMISSIONER SEAMOUNT: I -- did we discuss the 21 option that -- that if we don't need it..... 22 CHAIR FOERSTER: Then we won't -- then 23 we'll..... 24 COMMISSIONER SEAMOUNT: .....(indiscernible - 25 simultaneous speech) don't need to see it, right? 1 CHAIR FOERSTER: Right. 2 COMMISSIONER SEAMOUNT: We don't need it for a 3 decision. 4 CHAIR FOERSTER: If we don't need it for..... 5 COMMISSIONER SEAMOUNT: Okay. 6 CHAIR FOERSTER: .....so if we don't need it to 7 make a decision we can take it off the table and if 8 you're unwilling to make it public, but we think it's 9 public we'll take it off the table. 10 MR. LAUGHLIN: We understand. 11 CHAIR FOERSTER: Okay. All right. 12 COMMISSIONER SEAMOUNT: Okay. On page..... 13 CHAIR FOERSTER: What about the verbiage on 14 that page. 15 COMMISSIONER SEAMOUNT: .....page 15 is the 16 verbiage confidential? 17 MR. LAUGHLIN: No, because basically we've 18 stated that. 19 COMMISSIONER SEAMOUNT: Okay. Page 16? 20 MR. LAUGHLIN: I would not have any issues with 21 this being confidential. 22 COMMISSIONER SEAMOUNT: Okay. 23 CHAIR FOERSTER: That whole page is 24 nonconfidential. 25 COMMISSIONER SEAMOUNT: Page 17 doesn't look •E 0 • 1 confidential; is that true? 2 MR. LAUGHLIN: Page 17 was presented in the 3 earlier section. 4 CHAIR FOERSTER: Okay. 5 COMMISSIONER SEAMOUNT: Page 18, I assume you 6 want to keep the graph confidential? 7 MR. LAUGHLIN: Yes, please. 8 CHAIR FOERSTER: And the verbiage is 9 nonconfidential? 10 MR. LAUGHLIN: Nonconfidential. 11 CHAIR FOERSTER: Okay. 12 COMMISSIONER SEAMOUNT: Page 19, can you 13 describe what that shows? 14 MR. LAUGHLIN: That one talks about the 15 additional topic that this Commission staff has asked 16 us to investigate which was the Point Thomson gas 17 returning to Prudhoe Bay for injection purposes prior 18 to the gas start up. Verbiage is fine. The graph is 19 basically a pressure plot of the change in pressure due 20 to the increase injection from Point Thomson into 21 Prudhoe. 22 CHAIR FOERSTER: So verbiage nonconfidential, 23 graph confidential? 24 MR. LAUGHLIN: Yes. 25 COMMISSIONER SEAMOUNT: Page 20. 70 • s 1 MR. LAUGHLIN: Has already been presented in 2 the previous section. 3 COMMISSIONER SEAMOUNT: Page 21. 4 MR. LAUGHLIN: Has already been previously 5 presented. 6 COMMISSIONER SEAMOUNT: Page 22, can you 7 describe that slide? 8 MR. LAUGHLIN: Gas treatment plant gas supply 9 and CO2 byproduct volumes and how it is managed as part 10 of the area injection order. The graphs I would 11 consider confidential, the verbiage does not appear 12 confidential. 13 COMMISSIONER SEAMOUNT: Page 23. 14 MR. LAUGHLIN: The verbiage looks 15 nonconfidential. 16 CHAIR FOERSTER: Okay. 17 MR. LAUGHLIN: It's CO2 handling limitations. 18 COMMISSIONER SEAMOUNT: The whole graph's not 19 confidential? 20 MR. LAUGHLIN: There's not -- on..... 21 CHAIR FOERSTER: The whole page..... 22 MR. LAUGHLIN: .....page 23 there is no graph. 23 CHAIR FOERSTER: .....the whole page is 24 nonconfidential. 25 COMMISSIONER SEAMOUNT: So the whole page is 71 1 nonconfidential, but you did not show this in the..... 2 CHAIR FOERSTER: That's fine. 3 COMMISSIONER SEAMOUNT: That's fine? Okay. 4 CHAIR FOERSTER: They don't care, we can -- 5 this can be public, made available to the public. And 6 we're keeping a record of what you said confidential 7 and non, but you're going to provide us a redacted 8 version of this that has the confidential stuff taken 9 out and the nonconfidential stuff left in. Okay. 10 COMMISSIONER SEAMOUNT: Okay. Page 24, can you 11 describe that, please? 12 MR. LAUGHLIN: CO2 injection locations that 13 we've investigated. And that -- the verbiage is 14 nonconfidential and I really don't -- I'm not too 15 concerned by the graph or the presentation illustration 16 at the bottom. 17 CHAIR FOERSTER: So you have no problem with 18 that being nonconfidential? 19 MR. LAUGHLIN: I have no issues with that. 20 CHAIR FOERSTER: So why is that picture 21 something you flow through the model less confidential 22 than the one you showed on page 4 that you want 23 confidential, the reservoir model grid on page 4, I 24 mean, if this is a reservoir model grid on page 24 why 25 is it less confidential than the one on page 4? 72 1 MR. LAUGHLIN: This one, the second one or the 2 last one actually has a prediction illustration so 3 these are predictive illustrations of what it looks 4 like in the future. 5 CHAIR FOERSTER: The one on page 4 has 6 predictive in it? 7 MR. LAUGHLIN: Page 20. 8 CHAIR FOERSTER: And so -- but I thought you 9 said you didn't have a problem with it being 10 nonconfidential? 11 MR. LAUGHLIN: Yeah, you're right, I don't. I 12 get confused. 13 CHAIR FOERSTER: But it's predictive? 14 MR. LAUGHLIN: I could live with either of them 15 being nonconfidential. 16 CHAIR FOERSTER: So the one on page 4 is 17 nonconfidential as well? 18 MR. LAUGHLIN: Yeah, I could live with that. 19 CHAIR FOERSTER: Okay. You understand 20 that..... 21 MR. LAUGHLIN: I understand that..... 22 CHAIR FOERSTER: .....as an operator your 23 reflex is to call in confidential, but our job is to 24 make sure that we question that and make sure that it 25 truly is, not just because you want it to be, but 73 0 s 1 because it really warrants it. 2 Okay. So and I want to thank BP and I want to 3 thank the rest of the folks in the room for their 4 patience in tromping through this, but because in our 5 opinion this is a very important part of what we're 6 doing. 7 COMMISSIONER SEAMOUNT: You gave me the boring 8 part, didn't you? 9 CHAIR FOERSTER: I did. 10 COMMISSIONER SEAMOUNT: Okay. Page..... 11 CHAIR FOERSTER: Because I knew you'd make it 12 less boring. Talk about fish, come on. 13 COMMISSIONER SEAMOUNT: That's confidential. 14 CHAIR FOERSTER: Okay. 15 COMMISSIONER SEAMOUNT: Okay. Page 25, can you 16 describe what's on there and what is confidential -- 17 what you consider confidential and what you don't? 18 MR. LAUGHLIN: The CO2 injection location and 19 the Prudhoe oil pool recovery. I would consider the 20 graphs confidential on the left-hand side and on the 21 right-hand side we've discussed most of those numbers 22 already. 23 CHAIR FOERSTER: So the numbers are not 24 confidential? 25 MR. LAUGHLIN: That would be my impression. 74 1 CHAIR FOERSTER: And the verbiage at the 2 bottom? 3 MR. LAUGHLIN: Nonconfidential. 4 CHAIR FOERSTER: Okay. 5 COMMISSIONER SEAMOUNT: Page 26, please 6 describe and why it is confidential? 7 MR. LAUGHLIN: It's a distribution of CO2 in 8 the gas phase in the reservoir through a prediction out 9 of our full field model. 10 CHAIR FOERSTER: Okay. And how is it different 11 from the pictures shown on the other two? 12 MR. LAUGHLIN: It's smaller. Sorry. It's a 13 little bit of humor. 14 CHAIR FOERSTER: And more colors. 15 MR. LAUGHLIN: Amount of humor. 16 CHAIR FOERSTER: Better use of the primary 17 color spectrum. 18 MR. LAUGHLIN: Yeah. 19 CHAIR FOERSTER: So why do these -- should 20 these be treated as confidential and the others not? 21 MR. LAUGHLIN: I'm fine with them not being 22 confidential. 23 CHAIR FOERSTER: Is your legal counsel fine 24 with that as well? 25 MR. LAUGHLIN: He's squirming so..... 75 9 0 1 CHAIR FOERSTER: I know, I was watching that. 2 And nobody else in the room could see that. 3 MR. LAUGHLIN: Nonconfidential. 4 CHAIR FOERSTER: Nonconfidential. Okay. Thank 5 you. 6 COMMISSIONER SEAMOUNT: Page 27. 7 MR. LAUGHLIN: The graph on the right-hand side 8 discusses the additional topic of interest, the 9 sensitivity injection of CO2 from the Point Thomson 10 unit gas. The graph on the right is confidential. The 11 verbiage is not on the left-hand side. 12 COMMISSIONER SEAMOUNT: Page 28. 13 MR. LAUGHLIN: The verbiage is not 14 confidential. 15 COMMISSIONER SEAMOUNT: So that slide is 16 nonconfidential? 17 MR. LAUGHLIN: Yes, please. 18 COMMISSIONER SEAMOUNT: And page 29? 19 MR. LAUGHLIN: This is unit derived data and as 20 a owner we will not..... 21 COMMISSIONER SEAMOUNT: Pardon me? 22 MR. LAUGHLIN: As an owner we cannot talk about 23 this as nonconfidential. 24 COMMISSIONER SEAMOUNT: This is 25 nonconfidential? 76 1 MR. LAUGHLIN: This is confidential..... 2 CHAIR FOERSTER: Yeah. 3 MR. LAUGHLIN: .....because we are speaking as 4 unit owner on this. 5 COMMISSIONER SEAMOUNT: Okay. And you haven't 6 gotten together with the other interested parties to 7 determine whether you can release this or not; is that 8 correct, or would you..... 9 CHAIR FOERSTER: It's also engineering 10 interpretative data, isn't it? 11 MR. LAUGHLIN: It's engineering interpretative. 12 CHAIR FOERSTER: Yeah. Okay. 13 COMMISSIONER SEAMOUNT: And this slide is 14 titled CO2 injection recovery range estimates for Point 15 McIntyre, Aurora and Borealis and Orion and Borealis. 16 CHAIR FOERSTER: And Polaris. 17 MR. LAUGHLIN: Polaris. 18 COMMISSIONER SEAMOUNT: I mean, Polaris. 19 CHAIR FOERSTER: Yeah. 20 MR. LAUGHLIN: That's correct. 21 CHAIR FOERSTER: Okay. 22 COMMISSIONER SEAMOUNT: How could I get those 23 two names mixed up. 24 CHAIR FOERSTER: Okay. 25 COMMISSIONER SEAMOUNT: Is the verbiage at the 77 1 bottom confidential? 2 MR. LAUGHLIN: No. 3 COMMISSIONER SEAMOUNT: Okay. Page 30? 4 MR. LAUGHLIN: Has been previously presented. 5 CHAIR FOERSTER: So it's nonconfidential? 6 MR. LAUGHLIN: Nonconfidential. 7 COMMISSIONER SEAMOUNT: Page 31? 8 MR. LAUGHLIN: Nonconfidential. 9 COMMISSIONER SEAMOUNT: And that's it. 10 CHAIR FOERSTER: Okay. 11 COMMISSIONER SEAMOUNT: Thank you, Mr. Laughlin 12 and..... 13 CHAIR FOERSTER: Associates. 14 COMMISSIONER SEAMOUNT: .....associates, 15 attorneys, advisors. 16 CHAIR FOERSTER: So do you have any additional 17 questions for BP at this time? 18 COMMISSIONER SEAMOUNT: I have no additional 19 questions. 20 CHAIR FOERSTER: Okay. Nor do I. It's five 21 minute to 11:00. I would like to proceed with Conoco's 22 testimony and see if we can't at least make some 23 headway on it before lunch. I think five to 11:00 is a 24 bit early for lunch. How do you feel about that? 25 COMMISSIONER SEAMOUNT: I'm not hungry. • 0 1 CHAIR FOERSTER: Okay. 2 UNIDENTIFIED VOICE: Can we take five minutes? 3 CHAIR FOERSTER: Okay. We're going to take a 4 five minute recess. I'm not sure why, but we're going 5 to take a five minute recess. 6 (Off record) 7 (On record) 8 CHAIR FOERSTER: Okay. We're back on the 9 record at 11:00 o'clock. And I apologize to Conoco 10 because I failed to ask you guys if you were 11 comfortable with soldiering on, are you? 12 MR. REINBOLD: In terms of proceeding with the 13 hearings, yes. 14 CHAIR FOERSTER: Yes. 15 COMMISSIONER SEAMOUNT: And we'll -- what, 16 we'll 17 CHAIR FOERSTER: We'll shoot for noonish. So -- 18 but we'll try to be as flexible as we can to let you 19 get in your -- we'll definitely get in everything that 20 you want to say and we'll try to be as continuous with 21 it so that it's as -- flows comfortably and logically 22 for you guys. But we won't go until 1:00. 23 And hang on one second. Off the record for a 24 second. 25 (Off record) 79 1 (On record) 2 CHAIR FOERSTER: And just for the good of the 3 order we have consulted with our attorney and BP, we're 4 comfortable with the items that we've agreed -- that 5 you have said that you want to be confidential, we're 6 comfortable with you guys holding them confidential. 7 We'll accept their confidentiality, however we will 8 require that you present us as we discussed a redacted 9 version of your confidential testimony and we would 10 also like before we go in camera for you to give for 11 the public record a characterization of what a decline 12 curve looks -- you know, looks like and what it is 13 intended to do and what predictions look like, what 14 they're intended to do just so the public can have an 15 understanding for what those things are that we're 16 redacting. 17 Okay. All right. Now having done that I want 18 you both to raise your right hand. 19 (Oath administered) 20 MR. REINBOLD: Yes. 21 MR. STRAMP: Yes, I do. 22 CHAIR FOERSTER: Okay. Now for the record I'd 23 like for each of you to give us your name, who you 24 represent and if you'd like to be considered as an 25 expert and then what that area of expertise is and then 1 give us an opportunity to acknowledge whether or not 2 you're going to be accepted as an expert. And you can 3 do that together at the start or you can do it 4 chronologically as, you know, one of you do it and then 5 do your testimony and then the other do it and give his 6 testimony, but if you think you might be tag teaming or 7 interrupting each other then let's do it all up front. 8 MR. REINBOLD: Okay. We'll do it all up front, 9 please. Okay. Well, good morning, my name is..... 10 CHAIR FOERSTER: And can you guys in the back 11 hear? 12 (No comments) 13 CHAIR FOERSTER: I didn't think so. 14 MR. REINBOLD: Let me try to speak up a little 15 bit. Is that a little better? 16 CHAIR FOERSTER: Can everyone hear in the back? 17 (No comments) 18 CHAIR FOERSTER: Okay. Try to focus on the -- 19 getting that low voice right into that mic. 20 MR. REINBOLD: Is there anyway we could turn 21 the mics up so I don't have to crouch way over. 22 CHAIR FOERSTER: There you go. 23 COMMISSIONER SEAMOUNT: There you go. 24 CHAIR FOERSTER: There you go. That was good. 25 MR. REINBOLD: Yeah, that's going to be tough. 1 COMMISSIONER SEAMOUNT: Pull it closer. 2 ERIC REINBOLD 3 previously sworn, called as a witness on behalf of 4 ConocoPhillips, testified as follows on: 5 DIRECT EXAMINATION 6 MR. REINBOLD: Thank you. My name is Eric 7 Reinbold, I'm the ConocoPhillips subsurface development 8 manager for Prudhoe Bay. I'm here with my colleague, 9 Ryan Stramp, I'll let him introduce himself here in a 10 moment. I'll be providing a brief summary of the 11 comments submitted on behalf of ConocoPhillips and 12 Chevron, USA. 13 As the Commission's aware both Chevron and 14 ConocoPhillips are working interest owners in the 15 Prudhoe Bay unit. So I would like to be recognized as 16 an expert in reservoir engineering and reservoir 17 management. A little bit of background on myself. I'm 18 a petroleum engineer by education. I have a degree, a 19 BS degree from the University of Alaska, Fairbanks. In 20 1985 I went to work with ARCO, ARCO here in 1985 and 21 I've worked most of my career, spanning 30 years. 22 CHAIR FOERSTER: (Indiscernible) at ARCO said I 23 request a moment of silent grief. Okay. Now you may 24 proceed. 25 MR. REINBOLD: Completely agree. Thank you. 1 So most of my career has been spent working oil fields 2 here on the North Slope. I started a career in the 3 Kuparuk River field as a production engineer. I was 4 involved in many early drill site developments at 5 Kuparuk, a lot of the work around fracturing and gas 6 optimization, a lot of the work around just learning to 7 manage a very large reservoir. I've also worked in the 8 Alpine area, I was responsible for the field 9 development plans for both the Nanook field and the 10 Fiord field. Worked a bit of Alpine as well from a 11 reservoir management perspective. I spent quite a bit 12 of time working the Manakut (ph) reservoir and some of 13 the jukne (ph) fields in the early 190s. I spent time 14 in upstream technology working gas (indiscernible) 15 processes, looking at experimental work to help us 16 understand the behavior of miscible gas flooding at 17 high pressure particularly for the Kuparuk field. I've 18 worked overseas, I worked in the North Sea in a 19 redevelopment program/study of the Eldfisk field, I was 20 predominantly responsible for history matching and 21 reservoir modeling of the Eldfisk field in support of 22 that development. I returned from that assignment in 23 2006, back into the Prudhoe Bay organization, I've been 24 responsible for the other side of the subsurface 25 development plans for Prudhoe Bay and all of the 1 satellite fields within the Prudhoe Bay unit. And as I 2 stated I am the subsurface development manager at this 3 point for the greater..... 4 CHAIR FOERSTER: Did you say it and I missed 5 what your educational background is? 6 MR. REINBOLD: Yes, petroleum engineering from 7 the University of Alaska. 8 CHAIR FOERSTER: Fairbanks? 9 MR. REINBOLD: That's correct. And it's cold 10 up there. 11 CHAIR FOERSTER: Except when it's hot. 12 Commissioner Seamount, do you have any questions? 13 COMMISSIONER SEAMOUNT: I have no questions. I 14 have -- I would consider Mr. Reinbold as an expert 15 witness in reservoir engineering and development. And 16 he actually went to a really good school. 17 CHAIR FOERSTER: I have no..... 18 MR. REINBOLD: Thank you. 19 CHAIR FOERSTER: .....I have no conflicts in 20 the state, they don't have a football team. 21 MR. REINBOLD: Great hockey team though. 22 CHAIR FOERSTER: And I don't have any questions 23 for you either. And I also have no problems accepting 24 you as an expert. So are you guys going to tag team. 25 MR. STRAMP: I'll go through my..... 1 CHAIR FOERSTER: Okay. 2 MR. STRAMP: .....statement first. My name is 3 Ryan Stramp..... 4 CHAIR FOERSTER: Can you guys in the back hear? 5 Okay. 6 RYAN STRAMP 7 previously sworn, called as a witness on behalf of 8 ConocoPhillips, testified as follows on: 9 DIRECT EXAMINATION 10 MR. STRAMP: Okay. My name's Ryan Stramp, I'm 11 representing ConocoPhillips today. I am currently in a 12 position of the planning and development coordinator 13 for ConocoPhillips. I'm here today primarily to answer 14 questions as needed, but I would like to be identified 15 as an expert witness in the area of North Slope oil and 16 gas facilities and project development planning. 17 A little bit of my background. In my current 18 role as a planning and development coordinator I work 19 very closely -- well, we work in a group that manages 20 our interest I guess first of all in the Prudhoe Bay 21 and Point Thomson fields. They're operated by others, 22 but we still work very closely with the staff of BP and 23 Exxon that do directly operate those fields as well as 24 other ConocoPhillips staff related to planning and 25 execution of facilities projects at both of those 1 Prudhoe and Point Thomson areas. I've been working in 2 my current position for 12 years, overall I have 38 3 years of industry experience with the last 34 of those 4 years being in Alaska. 5 Educationally I have a BS degree in petroleum 6 from, sorry, Cathy, University of Oklahoma. We don't 7 have much of a football team this year I don't think, 8 but..... 9 CHAIR FOERSTER: It's (indiscernible)..... 10 MR. STRAMP: My overall work experience 11 includes assignments in production engineering, 12 reservoir engineering, operations supervision, facility 13 planning, project engineering and project coordination. 14 I've spent approximately 25 years of my career working 15 specifically in the areas -- in areas related to Alaska 16 North Slope operations, project engineering, project 17 coordination and general field development planning of 18 North Slope fields. Projects and project evaluations 19 I've been involved in in Alaska include the power 20 expansion at Kuparuk where we added the frame five 21 turbine generator, multiple Kuparuk drill site 22 developments including being the coordinator for the 23 Tarn and Meltwater new drill site developments, at 24 Prudhoe Bay analyzing and selecting the optimum way 25 that we are choosing to renew our facilities that are 0 • 1 quite aged and how to make them safe and operable for 2 decades to come including replacement of the low 3 pressure compressors at the flow stations. We've been 4 working for quite some time evaluating options to 5 development the Prudhoe Bay west end opportunities 6 including the Z pad expansion project which has moved 7 forward. Over the past years I've also been involved 8 in the Prudhoe or Point Thomson unit IPS project and 9 with planning activities associated with the upstream 10 gas supply for the potential LNG project. 11 CHAIR FOERSTER: Okay. Do..... 12 MR. STRAMP: So based upon these credentials I 13 would like to be considered as an expert witness as I 14 said in the area of Alaska North Slope oil and gas 15 facilities and project development planning. 16 CHAIR FOERSTER: Thank you. Commissioner 17 Seamount, do you have any questions for this witness? 18 COMMISSIONER SEAMOUNT: Mr. Stramp, which 19 school in Oklahoma did you go to? 20 MR. STRAMP: The University of Oklahoma. 21 COMMISSIONER SEAMOUNT: University. So we just 22 happen to be -- we'll be down there next month, do you 23 want us to relay anything to your ex -professors? 24 MR. STRAMP: I'm not sure any of them are 25 surviving at this point in time unfortunately. MN 1 COMMISSIONER SEAMOUNT: I have no problems with 2 considering Mr. Stramp an..... 3 CHAIR FOERSTER: Okay. 4 COMMISSIONER SEAMOUNT: .....expert witness. 5 CHAIR FOERSTER: I have no problems with 6 acknowledging Mr. Stramp as an expert, but I do feel at 7 this point that it's important for fairness that I 8 convey that Mr. Stramp used to work for me and at that 9 time and since that time I've had the ultimate in 10 respect for him as a -- personal and professional. 11 However I do not feel that that would keep me from 12 making an impartial judgment in this case because the 13 witnesses for BP have garnered nothing but my respect 14 as professionals as well. So I would like BP to take 15 this opportunity to weigh whether they have a problem 16 with me listening to Mr. Stramp's testimony. 17 UNIDENTIFIED VOICE: No objection. 18 CHAIR FOERSTER: Okay. Okay. All right. Then 19 you may proceed. 20 MR. REINBOLD: Okay. Thank you, Commissioner 21 Foerster, Commissioner Seamount, I appreciate the 22 opportunity to provide comment. I'll provide the 23 comments on behalf of ConocoPhillips and Chevron, Ryan, 24 my colleague here will be here to assist me in the 25 event that you have questions concerning the surface ::3 0 1 activity. 2 So first of all I would like to compliment BP 3 on a job well done in their development of -- their 4 robust development plans for the AKLNG project. As a 5 working interest owner we have been involved in all of 6 the development work around the full field model, 7 including the construction of the geologic model that 8 is the basis for that dynamic simulation work that's 9 been done. We've been actively involved all along in 10 the context of helping develop that development plan in 11 such a way that it presents the most robust project for 12 the working interest owner group. I'd also like to 13 thank BP for a very good summary of the AKLNG project 14 as a whole, we appreciate that. 15 So I'll begin my formal comments with 16 ConocoPhillips and Chevron support BP's request to 17 increase the rule 9 maximum level offtake rate from the 18 Prudhoe oil specifically. However we request that the 19 Commission approve an annual average maximum offtake 20 rate of 3.6 billion cubic feet per day. This we 21 believe is adequate to fill the AKLNG facility and 22 provide certainty. We want that weight and we'll 23 explain in more detail in a few moments, but we want 24 that weight to be the ruling by the agencies rather 25 than the requested 4.1 billion cubic feet a day. 1 As the Commission is aware the Prudhoe Bay 2 working interest owners have been working closely to 3 support a rule 9 increase request as an important part 4 of making possible potential major gas sales from 5 Prudhoe Bay through the AKLNG project. The AKLNG 6 project is nearing completion of the current prefeed 7 engineering phase as BP elaborated and is expected to 8 enter feed in this next year, 2016. Increasing rule 9, 9 the maximum allowable offtake rate will provide 10 additional certainty, we recognize that, to support 11 ongoing progress and project development. For that 12 reason we do believe that now is the right time to make 13 an increase in the rule 9 allowable maximum gas offtake 14 rate as BP has also pointed out. 15 We support a 3.6 billion cubic feet a day 16 maximum allowable offtake rate because it's the weight 17 that's needed to supply the AKLNG project while 18 minimizing the liquid impacts of gas offtake at Prudhoe 19 Bay. AKLNG was designed to receive 75 percent of its 20 feed from the Prudhoe Bay unit and the remaining 25 21 from the Point Thomson unit. The 75 percent feed to 22 the AKLNG project from Prudhoe Bay requires an annual 23 offtake, a minimum annual offtake of 3.3 billion cubic 24 feet a day. That's consistent with the numbers that BP 25 presented in their table. We're requesting an M1 0 • 1 additional .3 billion cubic feet a day which would 2 accommodate a couple of things. It would accommodate 3 the possibility that the AKLNG project had excess 4 capacity, but it would also accommodate the event in 5 which the other unit, the Point Thomson unit, were down 6 for any significant period of time. 3.6 billion cubic 7 feet a day would allow Prudhoe Bay to accommodate four 8 months of downtime at the Point Thomson unit in every 9 single calendar year. We believe that's a worst case 10 scenario and we just don't believe that that's a -- 11 even in the realm of possibility to be honest. We 12 believe that the worst case scenario is extremely 13 unlikely and no major North Slope field has ever 14 experienced anything of the (indiscernible) of a four 15 month downtime event. 16 We also believe it's very unlikely that the 17 Point Thomson unit would deliver less gas than 18 anticipated. The Point Thomson operator has provided 19 very high quality information regarding Point Thomson 20 reservoir and has designed a robust development plan 21 which we've also monitored and contributed to very 22 closely. We believe the Point Thomson reservoir and 23 its delivery capacity is quite robust. Although 3.6 24 would be sufficient to fill the excess capacity that 25 3.6 would have filled, the 300 million cubic feet a day 91 0 E 1 that I referred to as .3 billion, although it would 2 cover up to a 35 percent deficiency in Point Thomson's 3 rate, we believe that that shortfall, that kind of 4 shortfall is highly unlikely. Further in the unlikely 5 event that Prudhoe Bay was required to fill the AKLNG 6 plant, to backfill a problem with the other unit, we 7 believe there would be quite a bit of -- quite a bit of 8 warning that that kind of an event was coming, whether 9 it was a facility issue, a deliverability issue, we 10 would see that coming based on the ongoing monitoring 11 of the reservoir and the development plans. 12 In that event, the event in which we saw 13 something coming, we believe there's more than 14 sufficient time for the working interest owners to work 15 with the Commission to consider a possible further 16 increase in the Prudhoe offtake -- allowable offtake 17 rate. Given the time available we believe that the 18 Commission should defer decision on increasing the 19 Prudhoe offtake rate above 3.6 billion cubic feet a day 20 only if and unless additional information becomes 21 available that makes that request necessary. To assist 22 in the Commission's consideration of any such future 23 request ConocoPhillips and Chevron have requested that 24 the Commission provide administrative approval for 25 future changes in the offtake rate. 92 0 1 And finally before I leave the point of the 2 allowable field gas offtake rate I -- regarding the 3 allowable, we do agree with BP's comments and their 4 testimony this morning that the higher, in their terms, 5 extreme rate, was a (indiscernible) sensitivity case 6 and yields essentially equivalent expected ultimate 7 recovery relative to the base case. And again the base 8 case is 3.3 billion cubic feet a day. We're asking for 9 3.6. Okay. So the extreme case yields essentially an 10 equivalent expected ultimate recovery. 11 Given essentially equivalent ultimate recovery 12 we do believe that it's prudent not to pull the field 13 any harder than is necessary. As we know that this 14 would potentially impact liquid recovery from Prudhoe 15 Bay and secondly the 3.6 request that we make is fully 16 adequate to supply the AKLNG facility from Prudhoe 17 Bay's share -- with Prudhoe Bay's share and it is the 18 current design basis for the project. 19 Okay. I'm going to pivot now and I want to 20 talk a little bit about our request for the change to 21 the area injection orders. 22 CHAIR FOERSTER: Okay. Would you like to ask 23 questions relating to gas offtake now or would you like 24 to address all questions at the end? 25 COMMISSIONER SEAMOUNT: Well, I just had one M 0 0 1 question right now. You talked about minimizing 2 liquids loss so are you going to go into how much it's 3 going to be minimized? 4 CHAIR FOERSTER: I think he said that there was 5 -- that it's a wash between what they're asking for and 6 what BP's asking for. 7 MR. REINBOLD: Yeah, I think I can speak to 8 that. We recognize that gas sales in what is 9 essentially a gas reservoir today will impact ultimate 10 liquid recovery from the field, that's just fundamental 11 physics, there's no way to get around that. We do 12 believe that it should be minimized and that not 13 setting a very high and unrealistic extreme offtake 14 rate guards against that. A 3.6 offtake limit guards 15 against that liquid impact. 16 COMMISSIONER SEAMOUNT: Thank you. 17 CHAIR FOERSTER: Okay. So you guys view a 18 daily allowable limit as not being a daily limit, but 19 as a limit that's averaged over the year? 20 MR. REINBOLD: Yes. Thank you, that's a good 21 clarification. So as you know the rule 9 offtake rate 22 is an annual limit and so the limits we're talking 23 about today are that -- are those annual limits. We do 24 recognize that in the event of a downtime whether it's 25 a day, a week or a month, Prudhoe Bay would be required 94 • 0 1 to fill the full (indiscernible) capacity so, yes, on a 2 daily basis we would go to a full offtake, pool offtake 3 of 4.1 bcf per day, but we're requesting that the 4 annual average offtake be limited such that the 5 duration of that 4.1 pull on Prudhoe Bay be of limited 6 duration and not allowed to be for the full 365 days of 7 the year as requested by BP and ExxonMobil. 8 CHAIR FOERSTER: Okay. I have a couple of 9 clarifications. I'm a little confused because I 10 thought I heard you say that the impacting losses is 11 about a wash in the different cases? 12 MR. REINBOLD: Yes. So as you -- as you're 13 aware, Commissioner Foerster, models are very 14 uncertain. The modeling work that they've done I 15 believe is very robust, they've done a great job and 16 we've been involved. The modeling work does indicate 17 that pulling the field harder essentially yields the 18 same ultimate recovery when you balance the liquid 19 impacts with the gas benefits, however we know and we 20 know from the work that the agency have completed, the 21 Baskovich (ph) study back in 2007, that pulling the 22 field harder directionally impacts liquids. We also 23 know that when we calculate the total EOR, that's a 24 composite of the liquid impacts offset by gas benefits 25 and we have much higher certainty in our view about the 95 1 liquid impacts because they come at us right away, 2 within a matter of a couple years we are substantially 3 down on liquid rate. The gas impacts are at the end of 4 field life after the field comes off of plateau rates. 5 The certainty on the gas resource is much lower than 6 the certainty on the liquid impacts. We would prefer 7 to keep the field rate lower to ensure that we don't 8 suffer those impacts that we're highly confident will 9 occur at high rates. 10 CHAIR FOERSTER: Okay. So BP is saying that 11 they want to produce at the 3.6, but there are times 12 that they will need to go up to the 4.1 and you're 13 saying that that might happen, but you want to make 14 sure that bad things don't happen. Do you have a 15 reason to believe that BP would operate for other than 16 the best interests of greater ultimate recovery? 17 MR. REINBOLD: We don't really understand why 18 they would need a 4.1 billion cubic feet a day offtake 19 rate (indiscernible - simultaneous speech)..... 20 CHAIR FOERSTER: Have you asked them that? As 21 co -owners when you don't understand something don't you 22 ask each other about these things? 23 MR. REINBOLD: Sure. So if -- what they've 24 communicated this morning is that they need it for 25 project certainty. zz 1 CHAIR FOERSTER: But you didn't ask them 2 earlier, I mean, you came in with a 25 page complaint 3 that you disagreed with them without asking them why? 4 MR. REINBOLD: This has -- has certainly been 5 under discussion within the working interest owner 6 group for a number of months and we've had quite a bit 7 of discussion about it. We've been pretty clear that 8 we view the 4.1 billion as a -- as an (indiscernible) 9 rate for a very short period of time and we just 10 weren't able to close on this agreement. 11 CHAIR FOERSTER: Okay. So BP is characterizing 12 this as wanting to have flexibility to go up and down 13 as operating conditions require that they do that, but 14 you're saying that you don't trust them to use good oil 15 field practices to make that decision in the best 16 interests of total field operation? 17 MR. REINBOLD: Yeah, so essentially we 18 recognize the need to cover short term periods of 19 disruption for Point Thomson, but we think it's prudent 20 to simply be careful and not pull the Prudhoe Bay 21 reservoir down any harder than we need to and 3.6 22 billion cubic feet a day we believe provides plenty of 23 excess capacity in order to accommodate disruptions at 24 Point Thomson. 25 CHAIR FOERSTER: Okay. Okay. So I hope BP's 97 1 been listening to my questions because I'm going to ask 2 you to justify the other end of it from your 3 perspective. 4 So do you have any other questions at this time 5 or can they proceed to..... 6 COMMISSIONER SEAMOUNT: They can proceed. 7 CHAIR FOERSTER: Okay. All right. Please 8 proceed. 9 MR. REINBOLD: All right. Thank you. So I'll 10 shift now to the discussion of our request on the area 11 injection orders. ConocoPhillips and Chevron also 12 support BP's request for authorization to inject CO2 13 and other trace components separated at the AKLNG gas 14 treatment plant for the purposes of enhanced recovery 15 and pressure maintenance. BP has done good work in 16 identifying potential FOR opportunities. There are 17 many years before the AKLNG starts up as premised in 18 2025, in the intervening time the Prudhoe Bay working 19 interest owners will continue to look for FOR 20 opportunities within the Prudhoe Bay unit. If however 21 we do not identify viable FOR opportunities we would 22 like the opportunity or the permission to inject the 23 CO2 as disposal in class two Prudhoe Bay wells. We 24 recognize that the Commission would require additional 25 information to grant that disposal request and 9• 1 obviously we'll work with the operator to make that 2 possible. 3 I guess in summary ConocoPhillips and Chevron 4 do support the request for the rule 9 increase that 5 BP's made, we simply want to restate it to the lower 6 3.6 billion. And we also support the request for the 7 CO2 injection for the purposes of FOR and pressure 8 maintenance. Again we simply want to modify that to 9 also include the possibility of disposal to provide 10 project certainty just as BP is requesting certainty. 11 We do believe that the Commission -- we would 12 like the Commission to approve an offtake rate of 3.6 13 billion cubic feet a day and this is the -- this is the 14 offtake rate necessary in our view to supply the AKLNG 15 project as it is designed today. 16 And additionally again we do support the 17 Commission's -- we do request that the Commission also 18 amend the area injection orders to include disposal. 19 There is one more point before I close I wanted 20 to address in BP's statement, their prefiled testimony, 21 and it was a statement that they brought up again this 22 morning in the context of project certainty. They 23 indicated that they require -- they may require 24 approval of 4.1 billion cubic feet a day on an annual 25 basis in order to support their LNG marketing efforts. 1 Obviously LNG marketing is very important to the 2 project, but we do not understand why the 3.6 request 3 that we're making here would not also support that 4 need. 5 CHAIR FOERSTER: Did you ask them? 6 MR. REINBOLD: At this point, no. This is kind 7 of a new revelation to us. 8 CHAIR FOERSTER: Okay. What you heard them say 9 this morning was new? 10 MR. REINBOLD: That's correct. 11 CHAIR FOERSTER: Okay. 12 MR. REINBOLD: Yeah. So, in fact, I was 13 prepared here to ask that it would be helpful if BP and 14 Exxon could further explain their concerns. 15 CHAIR FOERSTER: So do you guys need a marriage 16 counselor? 17 MR. REINBOLD: That might be helpful. 18 CHAIR FOERSTER: Okay. 19 MR. REINBOLD: So LNG will be marketed from 20 both Prudhoe Bay and Point Thomson, we know that at 21 that point, that's the basis of design for the project. 22 Point Thomson is a world class gas reservoir and Point 23 Thomson, their operator, has in our view provided very 24 high quality information regarding the reservoir and 25 its deliverability. In fact, the Point Thomson 100 1 operator as you're aware has applied for 1.1 billion 2 cubic feet a day as an offtake rate. Based on this 3 high quality reservoir information and the robust 4 development plan which again we've been involved in, 5 indicates that a 3.6 offtake from Prudhoe Bay should be 6 more than sufficient, here they're asking for an 7 offtake rate of 1.1 billion compared to a project 8 design of 800 million or .8 b's, so their project in 9 their view has an opportunity to surpass the project 10 design rate. So coupled with this view of adequate 11 supply from Point Thomson we believe that our request 12 for 3.6 is consistent with good oil field engineering 13 practices and will support development of the AKLNG 14 project and provide adequate certainty to secure LNG 15 supply. 16 CHAIR FOERSTER: Okay. 17 MR. REINBOLD: That concludes my comments and 18 I'd be happy to answer any questions you may have or my 19 colleague here, Ryan, as well if there are surface 20 related issues. Thank you. 21 CHAIR FOERSTER: Okay. Do you have any 22 questions? 23 COMMISSIONER SEAMOUNT: Does this conclude -- 24 does this conclude ConocoPhillip's testimony? 25 MR. REINBOLD: Yes, it sure does. 101 1 COMMISSIONER SEAMOUNT: Okay. I have a -- I 2 guess I just have a comment. I'm not sure that we have 3 jurisdiction over CO2 disposal, it may be the federal 4 government and that would be a class six well. 5 MR. REINBOLD: Yes, actually I do have a letter 6 that we can share with you from the EPA to the regional 7 directors regarding their direction on the use of class 8 two wells for disposal. I'll be happy to share that 9 with you. 10 COMMISSIONER SEAMOUNT: Okay. Thank you. 11 CHAIR FOERSTER: Okay. That would be good. So 12 given that waste and the prevention of waste and to 13 greater ultimate recovery is our primary object -- are 14 our primary objectives I have -- you know, just is you 15 don't fully trust BP to do what's best for the 16 reservoir, I have to have that lack of trust, why 17 should I give you authority to dispose of the CO2 when 18 I've heard from both you and BP that there are 19 reservoirs whose recovery could be increased by 20 injecting it there, why should I trust that you're not 21 going to dispose of it when you can inject it? 22 MR. REINBOLD: Sure. That's a very fair 23 question. As you know we all operate within the 24 constraints of good oil field engineering practices. 25 We try to maximize recovery that is -- that is possible 102 0 • 1 within the constraints around us. And we're certainly 2 looking at those opportunities as you're aware from the 3 workshops that were conducted and the confidential 4 information that BP's going to share with the agencies, 5 there has been a tremendous amount of work done on the 6 FOR flooding, the opportunities within the Prudhoe Bay 7 unit, the things that we have proven over here today 8 amongst the working interest owners at Prudhoe Bay. 9 Certainly there could be other opportunities, I -- we 10 certainly hope there are, we'd like to see this 11 (indiscernible) used for beneficial use. 12 CHAIR FOERSTER: Does your company have any 13 projects on the North Slope that could benefit from CO2 14 or natural gas injection? 15 MR. REINBOLD: I would..... 16 CHAIR FOERSTER: (Indiscernible - simultaneous 17 speech) gas injection too. So..... 18 MR. REINBOLD: Yeah. Certainly natural gas 19 injection, we're using natural gas in the form of 20 miscible injectant in just about pool within the 21 Prudhoe Bay unit and at Alpine and its satellite fields 22 and within the Kuparuk River unit and its satellites as 23 well. So, yes, natural gas is being used for 24 hydrocarbon miscible flooding across the North Slope 25 and certainly you are correct, CO2 is a potential FOR 103 1 opportunity on the North Slope, it does improve viscous 2 oil recovery, however it's a very difficult proposition 3 when all considered the capital cost to conduct that 4 flood and the operating cost to manage the CO2 return 5 and the corrosion issues involved, so it's a very 6 complex and difficult problem to go at, but we will 7 certainly make a go of it if we can make a viable 8 project we would use the CO2 for that purpose. 9 CHAIR FOERSTER: You just said that lots of 10 fields on the North Slope are benefitting from natural 11 gas injection, so what does -- do the results presented 12 in the full field model which you guys participated in 13 so I think you can probably answer for BP and if they 14 don't like your answer they can correct you, so do the 15 model results reflect the losses that are going to 16 occur in all of those operations in the net greater 17 ultimate recovery numbers that BP presented? 18 MR. REINBOLD: That's a very good question and 19 I'm sure BP can (indiscernible) on that in their 20 answer, but in effect the full field model is a model 21 of (indiscernible) Prudhoe reservoir. It does however 22 account for the input of production from all of the 23 satellites within the Prudhoe Bay unit so it is a 24 (indiscernible) process. 25 CHAIR FOERSTER: It's a (indiscernible)..... 104 • 0 1 MR. REINBOLD: Yeah, exactly. If you want to 2 account for the change in miscible injectant stream you 3 would need to come back into the model with a -- with a 4 new forecast of the benefits of miscible injectant in 5 the offset satellite fields. So let me make -- maybe 6 make my answer a little more crisp. Yes, but it's a 7 complex..... 8 CHAIR FOERSTER: But it doesn't include the 9 losses at Alpine or Kuparuk or other places that are 10 currently benefiting from using natural gas? 11 MR. REINBOLD: Okay. I see where you're -- 12 what your question is. We are not exporting any of the 13 miscible injectant intermediate components, I mean, 14 things like propane and butane, we are currently only 15 exporting natural gas or resident gas from the CGF to 16 Kuparuk. 17 CHAIR FOERSTER: Is that planned to continue 18 throughout Kuparuk's field life? 19 MR. REINBOLD: Yes, it -- yes, it is and..... 20 CHAIR FOERSTER: Okay. So there will be no 21 losses? 22 MR. REINBOLD: Correct. 23 CHAIR FOERSTER: Okay. And is that true for 24 Alpine as well? 25 MR. REINBOLD: That's correct. There's no 105 0 0 1 export from Prudhoe Bay to the Alpine field. 2 CHAIR FOERSTER: Okay. Do you know of any 3 other -- other operator fields that are not benefitting 4 from CO2 or natural gas that might, and I know they're 5 not your operations and you can give me that blah, 6 blah, blah, but they are from similar fields in 7 comparable reservoirs? 8 MR. REINBOLD: Yes, there are some 9 (indiscernible) fields and, yes, CO2 flooding does 10 work. 11 CHAIR FOERSTER: Okay. Okay. So in summary 12 the -- let me make sure I've captured this correctly, 13 the only basis for the difference between your 14 recommended offtake rate and BP's recommended offtake 15 rate is that you want us to put a tighter rein on them 16 to limit their discretion so that they don't pull too 17 much from Prudhoe Bay? 18 MR. REINBOLD: Essentially, I think I rephrased 19 that a bit and suggested that the -- that the 20 (indiscernible) should be a -- the rate necessary for 21 the (indiscernible), but that a (indiscernible) 22 constraint on the maximum field gas offtake on an 23 annual basis. 24 CHAIR FOERSTER: Okay. Do you have any other 25 questions? 106 0 • 1 COMMISSIONER SEAMOUNT: I have none. 2 CHAIR FOERSTER: Okay. I think this would be a 3 good time to recess for lunch and when we come back 4 we'll probably -- I know we will have some more 5 questions for BP and then we'll want to go in -- then 6 we'll let anybody else who wants to testify testify and 7 then we'll go into the confidential portion of the 8 testimony. So at 11:38 we're going to recess and we 9 will reconvene at, what do you think, 1:00 o'clock? 10 COMMISSIONER SEAMOUNT: Yes. 11 CHAIR FOERSTER: Okay. We're recessed at 12 11:38, we're reconvening at 1:00. 13 (Off record) 14 (On record) 15 CHAIR FOERSTER: We're back on the record, 16 recess is over. All right. There are a few things 17 that we need to do before we go in camera for BP. 18 First now that everybody's had lunch and time to 19 reflect, is there anyone who has not testified other 20 than BP and Conoco who wishes to do so at this time? 21 (No comments) 22 CHAIR FOERSTER: Does BP or Conoco have any 23 additional testimony -- public testimony that they we 24 would like to give at this time? 25 (No comments) 107 0 0 1 CHAIR FOERSTER: Okay. So what we have left to 2 do, we have some questions for BP, we're going to go 3 over what items of information have not been provided 4 to us today, but we require and decide how long to 5 leave the record open to receive those and then BP is 6 going to summarize what they intend to show 7 confidentially, but they're going to summarize it 8 nonconfidentially for the public so that the public has 9 an idea of what it is. And please it -- I think -- I 10 think our review of what should be redacted and what 11 shouldn't kind of gives the public an idea of what 12 they're not going to hear. But we're going to go over 13 that again just to make sure that BP knows what we want 14 from -- in a redacted summary. And then BP -- we'll 15 then go in camera for BP to give us the confidential 16 testimony, then we will reconvene so that if anyone has 17 thought of anything for the good of the public record 18 they can have that opportunity at that time to put it 19 on the record and then we will adjourn. 20 Okay. So would the BP representatives come 21 back up so that we can ask them some questions. Don't 22 fight over who gets to come. And can the people in the 23 back still hear us? 24 (No comments) 25 CHAIR FOERSTER: Okay. So I think it's pretty 1: 0 1 clear what we want to ask you. Why is your number 2 different from Conoco's? 3 MR. VANTYLE: For the record, Madam Chair, Dave 4 Vantyle again with BP. There's a couple of reasons, a 5 couple of things I'd like to touch on regarding that 6 question. And from my perspective initially, then I'll 7 give an opportunity if that's all right for my 8 colleague to also respond. 9 CHAIR FOERSTER: That's fine. 10 MR. VANTYLE: The one big advantage -- again 11 this is from looking at this from the perspective of BP 12 as a member of the Alaska LNG project. The offtake 13 rate, the deliverability flexibility that's offered by 14 Prudhoe Bay is a tremendous advantage, a tremendous 15 asset to the LNG project. Now there was a discussion 16 earlier about a comment that I had made as related to 17 marketing. And one thing I wanted to say to clarify is 18 we certainly can't -- I mean, the companies talk about 19 details on marketing because we are competitors and we 20 certainly comply with antitrust laws and whatnot and 21 there's limitations on what we can discuss. We can 22 certainly talk about that in general terms as I did 23 earlier. And in that context the Alaska LNG project 24 can provide a unique opportunity in the marketplace as 25 I mentioned and Prudhoe has tremendous deliverability. 109 1 It can support -- that deliverability can support cases 2 where the LNG plant operates at over design, it can 3 accommodate operational disruptions and those could be 4 both at Point Thomson or at Prudhoe Bay itself where we 5 might have a disruption in the near term that can be 6 made up by later volumes. There could be changes, 7 increases in North Slope field use that were not 8 currently baked into our assumptions. We had 9 assumptions for all these things and I guess the only 10 thing we can guarantee about those is the future will 11 be somewhat different and we think they're good 12 assumptions at this stage of the project. We'll know 13 more as things mature and as time passes. There can be 14 increases in in state use here in Alaska. If you limit 15 the flexibility that (indiscernible) of deliverability 16 can offer through Prudhoe Bay volumes then the Alaska 17 LNG project we expect will see that reflected in how 18 buyers see the project, the big advantage could be 19 taken away as compared to other projects delivering 20 volumes. And (indiscernible) as I mentioned be seen 21 through lenders who would be lending money to either 22 the project or to individual members in the project. 23 Now in a sense it's like insurance, you hope you don't 24 need it, but in the event one of these things happens 25 it's a wonderful thing to have to ensure that your LNG 110 • 1 deliveries and whatnot continue. So the 4.1 we see 2 offers a tremendous amount of flexibility and 3 capitalizes on an inherent advantage that we have for 4 the Alaska LNG project. 5 CHAIR FOERSTER: Okay. So let me make sure I 6 understand. You -all are worried about flexibility in 7 deliverability to different options and commercial -- 8 want to be able to respond to different commercial 9 opportunities, but forgive me, but we don't give a crap 10 about that. We're here today to encourage greater 11 ultimate recovery and prevent waste. So if you guys 12 have commercial squabbles or battles or strategic 13 positions, they have no place here. What we're 14 concerned with is what is the answer for greater 15 ultimate recovery. 16 MR. LAUGHLIN: And we'll demonstrate that -- 17 this is Bruce Laughlin. And we'll demonstrate that in 18 the confidential section, that technically there is no 19 difference and no impact to the reservoir other than -- 20 in fact, even at the higher rate we actually recover 21 more hydrocarbons than what we would have done with the 22 3.3 bcf a day which is our normal operating condition. 23 So we're not asking that that be the project that goes 24 forward at a full 4.1 for all 15 years or 16 years is 25 the plateau length, we're just asking for that 111 1 flexibility in case an event may occur that we still 2 need to ensure capacity is delivered to the GTP. 3 CHAIR FOERSTER: Okay. So you have the same 4 opinion or different opinion that Conoco's that the 5 daily allowable rate that we give you is not the 6 maximum that can be produced in a given day, but it's 7 the maximum averaged out over the year? 8 MR. LAUGHLIN: My impression at least as I read 9 the rule 9 that was in place for the 2.7 was that it 10 was an annual average calendar year rate. 11 CHAIR FOERSTER: Okay. So a deliverability -- 12 excuse me, a gas offtake allowable of 3.6 would allow 13 you to go higher or lower so that you could average out 14 3.6 over the year, but a deliverability -- I mean, a 15 gas take -- offtake allowable of 4.1 would allow you to 16 exceed that number as well. Okay. So ConocoPhillips 17 expressed concerns over -- although they didn't put it 18 this way, it comes across to me as concerns over BP's 19 ability to use good oil field practices not to put the 20 air (ph) reserves at waste -- the risk of waste. Do 21 you -- can you explain to me why they have that 22 concern? 23 MR. LAUGHLIN: The difference between 3.6 and 24 4.1 is really insignificant in the oil recovery bases 25 for which they're asking for. The 4.1 still recovers 112 1 more hydrocarbons for the ultimate good of Alaska and 2 as your remit for the AOGCC, ultimate recovery in 3 Prudhoe Bay. 4 CHAIR FOERSTER: Now that was the answer to the 5 question I'd asked previously so I'll ask this one 6 again. Can you think of any reason that Conoco has for 7 doubting your ability to act as a good operator to 8 encourage greater ultimate recovery? 9 MR. LAUGHLIN: You'll have to ask them, I 10 really..... 11 CHAIR FOERSTER: I did. 12 MR. LAUGHLIN: .....can't answer that. 13 CHAIR FOERSTER: Okay. Do you have any other 14 questions at this time? 15 COMMISSIONER SEAMOUNT: Not at this time. 16 CHAIR FOERSTER: Okay. Let's see, where are 17 we. That's all the questions we have for you at this 18 time, but keep in mind that all of you that are under 19 oath are still under oath and we may have questions 20 later and (indiscernible) for your confidential 21 testimony. 22 So at this time I'd like to list on the record 23 for Conoco and BP what we feel is outstanding that we 24 will need from you guys and then we'll talk about how 25 long we want to keep the record open to get those 113 1 things. 2 Conoco, during your testimony referred to a 3 letter from the EPA and we would like to have that 4 letter provided to us. It was include -- it referenced 5 -- it was referenced in your testimony, we'd like that 6 letter to be included in the public record. How long 7 will it take you to be able to provide that letter to 8 us? 9 (No audible response) 10 CHAIR FOERSTER: Okay. That's good. We won't 11 need to -- well, could you get a copy to -- all right, 12 that's taken care of. 13 We asked BP if they had a case and were 14 prepared to present that to us that optimized solely on 15 greater ultimate recovery to the exclusion of 16 commercial opportunities and that sort of thing. And 17 are we going to see that? 18 MR. LAUGHLIN: We have some slides in the 19 non..... 20 CHAIR FOERSTER: Okay. If that is not provided 21 to our satisfaction during the confidential period we 22 will leave that -- how long -- if that run has not been 23 run and you need to go back and do something how long 24 will you need the record left open to do that? 25 MR. LAUGHLIN: Most of that run is the -- we're 114 1 going to show -- we'll show you a five year delay and 2 what the impact of that is from ultimate recovery. 3 CHAIR FOERSTER: Okay. So -- I'm going to ask 4 one more time because I'm having a hard time being 5 clear today. I don't understand that, but how long 6 will it take you to provide for us a case that simply 7 optimizes based on greater ultimate total hydrocarbon 8 recovery without regard to what -- letting timing 9 driving the model or letting opportunities drive the 10 model, how long will it take you to provide us that 11 run? 12 MR. LAUGHLIN: That run is done. 13 CHAIR FOERSTER: Okay. So that should be 14 provided today? 15 MR. LAUGHLIN: We can provide -- we can provide 16 the digits that go along with that run. 17 CHAIR FOERSTER: Okay. 18 COMMISSIONER SEAMOUNT: Are you talking 19 regardless of economics. 20 CHAIR FOERSTER: Regardless of economics? 21 MR. LAUGHLIN: Correct. 22 CHAIR FOERSTER: Okay. And we're going to go 23 back over with you the -- what's confidential and 24 what's not confidential in the confidential submission 25 and we would like a redacted version of that. How long 115 0 0 1 will we need to leave the record open so that you can 2 provide that to the Commission? 3 MR. LAUGHLIN: Early next week. 4 CHAIR FOERSTER: Okay. So what we'll do is 5 we'll agree that at the end of today we're going to 6 leave the record open for 10 calendar days so that you 7 can provide that. That's -- is there anything else? 8 COMMISSIONER SEAMOUNT: I can't think of 9 anything. 10 CHAIR FOERSTER: Okay. But what we're -- we're 11 thinking 10 calendar days and I wanted to get that on 12 the record before I forget to say it later, but if 13 anything comes up during the confidential portion of 14 your testimony that requires that we revisit that we 15 will do so. 16 Okay. So let's look at the confidential 17 portion and go back over and for the sake of time I'm 18 going to just quickly state slide by slide what we -- 19 what I think we agreed was confidential versus non. 20 And I'm just going to keep my lips flapping until you 21 tell me to stop. 22 UNIDENTIFIED VOICE: Cathy, the tenth day is 23 actually a Sunday so do you want to make it 11 days? 24 CHAIR FOERSTER: Eleven calendar days. Thank 25 you. We'll leave it open 11 calendar days. 116 0 1 Okay. Slide one, not confidential. 2 MR. LAUGHLIN: Correct. 3 CHAIR FOERSTER: Slide two, not confidential. 4 MR. LAUGHLIN: Correct. 5 CHAIR FOERSTER: Slide three, not confidential. 6 Slide four, the graph and the diagram, the modeling 7 diagram, confidential. Everything else on that -- on 8 slide four is not confidential. Slide five is not 9 confidential. Slide six, the graph is confidential, 10 but nothing else. Slide seven, the historical portion 11 of the graph is not confidential, the predictive 12 portion is confidential. And nothing else on that 13 graph is -- on that page is confidential. Slide eight, 14 nothing is confidential. Slide nine, nothing is 15 confidential. Slide 10, the entire slide except the 16 heading is confidential. Slide 11, the entire slide 17 except the heading is confidential. Slide 12, the 18 graph is confidential, but the verbiage and the heading 19 are nonconfidential. Slide 13, the same, the heading 20 and the verbiage is not confidential, but the graph is. 21 Slide 14, the graph -- again the graph is confidential, 22 the table is not confidential, the verbiage and the 23 heading are not confidential. Slide 15, again heading 24 and verbiage not confidential, graph confidential. 25 Slide 16, nothing is confidential. Slide 17, nothing 117 1 is confidential. Slide 18, the graph is confidential, 2 nothing else is confidential. Slide 19, the graph is 3 confidential, nothing else is confidential. Slide 20 4 and 21, nothing is confidential. Slide 22, the two 5 graphs are confidential, nothing else is confidential. 6 Slide 23, nothing is confidential. Slide 24, nothing 7 is confidential. Slide 25, the graph is confidential, 8 nothing else is confidential. Slide 26, nothing is 9 confidential. Slide 27, the graph is confidential, 10 nothing else is confidential. Slide 28, nothing is 11 confidential. Slide 29, the heading is not 12 confidential and the two bullet points at the bottom 13 are not confidential, but the table of information is 14 confidential. Slide 30, nothing is confidential. 15 Slide 31, nothing is confidential. 16 (Indiscernible)..... 17 MR. LAUGHLIN: That works. 18 CHAIR FOERSTER: Okay. And so within 11 19 calendar days we will have a resubmission of this that 20 will go -- become part of the public record and you 21 will redact only those things that we agreed to today 22 to redact? 23 MR. LAUGHLIN: That's correct. 24 CHAIR FOERSTER: Okay. So before we go into 25 the confidential testimony I would appreciate if for 118 1 the record -- for the public record, BP would summarize 2 a characterization of what will be presented in the 3 confidential portion of this testimony. 4 MR. LAUGHLIN: What we will be submitting for 5 the confidential portion of this presentation is a 6 discussion of the full field model, the quality and its 7 uses. We're also be looking at forward prediction of 8 the oil reference case. We'll be discussing some of 9 the assumptions associated with that oil reference 10 case. We'll give a description of the gas delivery and 11 CO2 handling which we've already discussed in the 12 previous section. We'll talk about the major gas sales 13 reference case profile and how it is appropriate for 14 what we're looking forward into the future with. We'll 15 also discuss the maximum allowable gas offtake profile 16 and how that is currently being used for the analysis 17 that we have performed. We'll also look at the 18 expected recovery comparison which will help to address 19 some of the issues that people have raised regarding 20 whether there's waste or damage to the reservoir. 21 We'll look at expected major gas sale start date 22 sensitivity which is part of your question that you had 23 asked earlier and we'll give an answer for that piece 24 of it. We'll then progress into the area injection 25 order modification and then we'll talk about CO2 119 1 studies that have already been conducted and how those 2 have pros and cons for the different areas that we'll 3 be addressing. And then we'll also look at the Prudhoe 4 oil pool and non Prudhoe oil pool CO2 recovery 5 estimates and what the impact of various locations that 6 we've injected CO2 into the reservoir. 7 CHAIR FOERSTER: Okay. Now given that 8 prevention of waste and promotion of greater ultimate 9 recovery are the two keystones of our purpose of being 10 here -- our purpose of being here today, after your 11 confidential testimony we may ask you to give a 12 characterization of that -- the answer to my 13 question..... 14 MR. LAUGHLIN: That would be fine. 15 CHAIR FOERSTER: .....on the public record..... 16 MR. LAUGHLIN: That would be..... 17 CHAIR FOERSTER: .....because that is -- that 18 is really why I'm here today, I think that's why Dan's 19 here today so and I imagine that's why people who are 20 listening to this and watching it are here today so we -- 21 it's only fair to the public that they get that 22 characterization at the end of this. We can't keep the 23 real reason we're here and the real reason for our 24 decision a secret. 25 So do you have any questions, comments? 120 • • 1 COMMISSIONER SEAMOUNT: No. 2 UNIDENTIFIED VOICE: I have a comment. The 7th 3 is actually Labor Day so..... 4 CHAIR FOERSTER: (Indiscernible)..... 5 UNIDENTIFIED VOICE: Yeah. 6 CHAIR FOERSTER: .....(indiscernible) 13. 7 Twelve days. Okay. I understand that the 8 technologists and technicians in the room need three or 9 four minutes to tee up for a confidential session. So 10 if BP would use those three or four minutes to clear 11 the room of people that they don't want in the room and 12 we're staying out of that. 13 MR. LAUGHLIN: We would like to just really 14 publicly state that the DNR, Division of Oil and Gas 15 personnel are sufficient for our purposes, ExxonMobil 16 and BP have no issues with that. 17 CHAIR FOERSTER: With DNR. And does 18 ConocoPhillips or Chevron have any problem with DNR, 19 Division of Oil and Gas people staying in the room? 20 (No comments) 21 CHAIR FOERSTER: I'm not seeing anybody say 22 yes. So if you're not with Conoco, Chevron, BP, Exxon, 23 the AOGCC or DNR's Division of Oil and Gas, you're 24 asked to leave now. 25 COMMISSIONER SEAMOUNT: What about AOGA? 121 1 CHAIR FOERSTER: How about AOGA, are they told 2 to leave too because I see AOGA leaving? 3 MR. LAUGHLIN: Yes. 4 CHAIR FOERSTER: They're asked -- because they 5 represent other operators as well, that's true. 6 So, BP, the monkey's on your back to make sure 7 all the -- all the people you don't want here are gone. 8 (Off record) 9 (Confidential Portion) 10 (On record) 11 CHAIR FOERSTER: We're ready to go back on the 12 record, ma'am. I have a couple more questions for BP 13 and then I have a question for Conoco and then we can 14 have last words and -- there. So my first question for 15 BP is in this scenario that you guys have painted with 16 this commercial opportunity what happens if someone 17 discovers and chooses to monetize and make available 18 for sale some of that 150 tcf of undiscovered gas that 19 the USGS says is up there on the North Slope, where 20 does that gas fit into this scenario? The engineer 21 looked like I need help from someone. 22 MR. LAUGHLIN: I don't need help from someone. 23 CHAIR FOERSTER: Yeah. So would that someone 24 come up and help and introduce yourself and say who you 25 are for the record. 122 1 MR. VANTYLE: Madam Chair, Dave Vantyle again 2 with BP. Could you restate the question one more time, 3 just..... 4 CHAIR FOERSTER: Sure. 5 MR. VANTYLE: Thank you. 6 CHAIR FOERSTER: In this scenario that you guys 7 have laid out with this commercial opportunity with a 8 line that carries this much gas and -- what happens and 9 where -- what happens if someone discovers an is able 10 to commercialize some of that 150 tcf of undiscovered 11 gas that the USGS says is up on the North Slope, where 12 does that gas fit into this scenario? 13 MR. VANTYLE: Madam Chairman, there's a number 14 of things that could occur. That party -- one of the 15 things that we've outlined in the heads of agreement 16 that was published, this is the AKLNG project heads of 17 agreement in 2014, was that the LNG project itself 18 would be expandable, would offer terms for third party 19 access. So someone who found new volumes could 20 approach the AKLNG project for that project to expand 21 to make additional space for those volumes. That would 22 be one possibility. 23 CHAIR FOERSTER: Line looping (ph) and 24 compression? 25 MR. VANTYLE: It could be any combination of 123 1 things. Certainly the line will be expandable, you 2 could add depending on the volume that was discovered 3 an additional train, LNG train, at the -- at the back 4 end, loop the line, adding for compression. With in 5 field compression alone we expect that the project 6 would be expandable by just short of 1 bcf a day. 7 CHAIR FOERSTER: Okay. The AOGCC has recently 8 adopted the practice of putting sunset clauses into our 9 orders because field operating conditions change, 10 operators change, lots of things change. How will BP 11 and its partners be impacted by a sunset clause because 12 it's likely that there will be one in the order that 13 comes out from this? 14 MR. VANTYLE: Madam Chair, could you describe 15 the nature of the sunset clause? 16 CHAIR FOERSTER: The sunset clause says that 17 this order will only be good for X number of years and 18 must be revisited at that time to take into account 19 changes in operating practices, changes in technology, 20 other changes that normally occur with time. 21 MR. VANTYLE: Yeah. Madam Chair, the -- one of 22 the things that we really hope to achieve through the 23 order is certainty that helps underpin as we discussed 24 previously the sales and purchase agreements that we 25 would be entering into which typically for an LNG 124 1 project would be in the -- you know, could be as much 2 as 30 years. The export license that we've petitioned 3 the DOE for is in that range. So another regulatory 4 matter that shortens that period would be viewed as a 5 risk by..... 6 CHAIR FOERSTER: Kind of like you guys like tax 7 certainty, but our Legislature convenes every year. 8 That was the joke for the -- two corners of the room. 9 Okay. But I just -- I just want to signal to you that 10 that is a prevailing practice in the AOGCC and it's 11 likely to occur in an order that comes out. 12 Did you have any other questions for BP at this 13 time? 14 COMMISSIONER SEAMOUNT: No, I have none. 15 CHAIR FOERSTER: Okay. I do have a couple 16 questions for Conoco unless BP has any other statements 17 they'd like to make before or have we worn you out? 18 MR. LAUGHLIN: Worn me out. I'll admit that. 19 CHAIR FOERSTER: Well, I will compliment BP and 20 its partners on the quality of technical analysis that 21 we've come to expect from you guys and thank you for 22 that. 23 MR. LAUGHLIN: Thank you very much. 24 MR. VANTYLE: Thank you. 25 COMMISSIONER SEAMOUNT: I agree with that 125 1 statement. 2 CHAIR FOERSTER: If the folks from Conoco would 3 come back up I do have two questions for you guys. And 4 introduce yourself again for -- just for the record. 5 MR. REINBOLD: Commissioner Foerster, my name 6 is Eric Reinbold again from ConocoPhillips. 7 CHAIR FOERSTER: Okay. Thank you. The first 8 question I have for you is a question that I asked of 9 BP and they said I'd have to ask you. Why are you 10 proposing that we sequester the CO2 from this project. 11 MR. REINBOLD: Yes, your question, one of 12 things in CO2 in our proposal is simply restated in the 13 appropriate interval and I'm not -- I'm intentionally 14 not being specific in that regard, we're simply 15 requesting that condition number 2 provide the 16 flexibility that could be important to us in terms of 17 making this project happen. The operator tend to view 18 it as a whole have looked at potential disposal options 19 down the structure of Prudhoe Bay, and that is a 20 possibility there are issues, but that might be a 21 possibility and we want that possibility to be explored 22 further. 23 CHAIR FOERSTER: So down structure in the -- in 24 the Prudhoe Bay -- in the Prudhoe oil pool? 25 MR. REINBOLD: That's correct. 126 1 CHAIR FOERSTER: In the water leg? 2 MR. REINBOLD: Yeah, that's correct. 3 CHAIR FOERSTER: Okay. So could you explain to 4 us what in the EPA letter makes it okay to call 5 (indiscernible) sequestration of CO2 class two instead 6 of class six because I don't read that in this letter? 7 MR. REINBOLD: Yeah, actually I'm not an expert 8 on UIC so I'm really probably not the right person to 9 ask that question. 10 CHAIR FOERSTER: Okay. You've got 12 days, 11 give us a response. 12 MR. REINBOLD: All right. Thank you. 13 CHAIR FOERSTER: Do you have any other 14 questions? 15 COMMISSIONER SEAMOUNT: I have none. 16 CHAIR FOERSTER: All right. I'm looking at 17 what I promised we would do before we adjourn and I've 18 run out of things. So I will make one last offer to 19 anyone in the room who feels compelled to get up here 20 and speak to do so. 21 (No comments) 22 CHAIR FOERSTER: And I'm not seeing anyone 23 jumping up enthusiastically. I am going to remind BP 24 and Conoco that we're leaving the record open for 12 25 days so that you can respond with the information we've 127 0 • 1 requested you to provide. And once we get that 2 information we will provide it to the other parties and 3 within that 12 days we'll provide -- we'll give you 24 4 hours after the end of that 12 days if you have a 5 problem with what the other guy sent us you can request 6 that we keep the record open longer and for you to 7 respond and we will do so. Does that -- is that a 8 comfortable solution for everybody in the room? 9 (No comments) 10 CHAIR FOERSTER: Okay. Before we get into 11 anything else I'm going to hurriedly adjourn. 12 (Recessed - 1:34 p.m.) 13 (END OF PROCEEDINGS) 128 1 C E R T I F I C A T E 2 UNITED STATES OF AMERICA ) 3 )ss 4 STATE OF ALASKA ) 5 6 I, Salena A. Hile, Notary Public in and for the 7 state of Alaska, residing in Anchorage in said state, 8 do hereby certify that the foregoing matter: Docket 9 No.: AIO 15-032, AIO 15-033, CO 15-09 was transcribed 10 to the best of our ability; Pages 01 through 129 11 IN WITNESS WHEREOF I have hereunto set my hand 12 and affixed my seal this 1st day of September 2015. 13 14 15 Salena A. Hile 16 Notary Public, State of Alaska 17 My Commission Expires: 09/16/2018 129 • • NAME STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION Public Hearing Docket Numbers: AIO 15-032, AIO 15-033, and CO 15-09 Prudhoe Bay Unit August 27, 2015 at 9am AFFILIATION Testify (yes or no) Tr 1S , L A0 r(C. h 0 D., L�Ael-AZ-10-1 ) ✓r,-, �),!..5h" (4 T lit ' a.1 t-V�G C�T\Ifiv 2 b *I WK Ak I'Q S n U n �oltih N O C l �Nkx� C 0 f �ja 6Hk (4d:6 PZA i 0fftMA-�-(606 N� JVPat (-o cv C', N a I VII) "I - j6,, �4 &,e i �� / lq-,r-xdA) 07ti W/ (— - A/C) • • a ` to"54-*L/ ,yT Ps or n z)) -15vn so- ,' eS 1,40'1/ r . 0 Tom Lakosh 3301 Eureka Street, A 12 Anchorage, Alaska 99503 phone/fax (907) 563-7380 email: lkosh@gci.net August 27, 2015 RECEIVED Cathy P. Foerster Commission Chair AUG 27 2015 t:, Alaska Oil and Gas Conservation Commission AOGCC 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Sent via email to: Jody.Colombie@alaska.gov and samantha.carlisle@alaska.gov Re: Consolidated Application for Amendment of Prudhoe Oil Pool Rule The BP/Exxon application under consideration at today's public hearing should be rejected because the BPU operator must make the application as representative of all lessees who must agree on a future plan production that must be approved by DNR. ConocoPhillips clearly objects to the requested gas off -take volume and the unit lessees must first submit the proposed gas production plan through the unit operator to DNR under unit consensus rules and not as separate competing interests to AGOCC. The proposed gas off -take amounts should similarly be rejected as they do not fairly consider new proposed uses of POP gas such as a local LNG plant in the planning stages and power production for the pipeline's Gas Treatment Plant or the pipeline compressors. The applicants should be required to document these other proposed uses in consideration of their higher value added and increased pressure drops on oil production fields. The application should be rejected as it fails to provide the public sufficient information to insure their rights to maximum production of hydrocarbons on the unit. The information must minimally show that there is sufficient reinjection of CO2 to maintain POP pressures for continuing oil production at maximum rates. Where the CO2 available from the GTP falls far short of the gas removed from POP, the commission should require CO2 capture and injection from all power production available in the area. The commission should also recommend applicants investigate advanced carbon capture and power production technology such as supercritical CO2 turbines and/or post combustion CO2 capture to insure that the lowest cost for FOR and pool pressure maintenance can be achieved. The CO2 available from S-CO2 turbines may be more effective for FOR given the higher pressures and temperatures that may be available from the turbine exhaust/heat recuperation system. 9 • Where miscible injectants such as natural gas liquids used in conjunction with hot CO2 have been shown to substantially enhance oil recovery, including recovery of under - produced heavy oils, the AGOCC should not approve this application unless and until the commission and the public can revisit the efficacy of CO2 injection with the newly available NGLs from Point Thomson. Where applicants have previously failed to disclose or employ injection of available CO2 from all sources to provide for maximum hydrocarbon production from state leases, the AGOCC must retroactively evaluate the value of lost production and assess fines to recuperate lessor's losses to date in addition to mandating maximum FOR using CO2 and miscible injectants in the future. The requested maximization of CO2 capture and injection will not only improve production on state leases in the near term, but can set industry standards that could substantially reduce the carbon footprint of the gas and power production industries as a whole. These practices may help minimize or reverse climate change in Alaska to allow for longer drilling seasons and still greater annual oil production as is the mandate for the AGGCC. The AGOCC must definitively determine whether CO2 capture and injection is a viable substitute for natural gas reinjection as it is clear that the natural gas off -take now has a viable market to produce value for the owner citizens of Alaska and new technologies for carbon capture from raw well gas and power production may drive the economics of gas off -take where CO2 injection can be used to maintain pool pressures and enhance oil migration to production wells. The AGOCC must remain vigilant in its assessment of FOR opportunities going forward and demand that lessees adopt new CO2 capture and injection technologies as they become commercially available as they may present a viable alternative for maintaining maximum hydrocarbon liquids and gas production consistent with lease provisions. The public hearing process should be continued until the application can be amended to clearly show the public owners of the hydrocarbon resources that the maximum production of all leased hydrocarbon reserves will be maintained. The applicants' confidential submissions must be minimally redacted to preserve trade secrets while allowing a fair public review of the possible gas and oil production alternatives consistent with their constitutional rights and lessees obligations to extract hydrocarbon resources at their maximum sustainable rate. We should not be forced to leave oil in the ground to produce gas for sale where CO2 can be economically captured from any, or all local sources and injected to maintain pool pressures and enhance oil recovery. Sincerely, Tom Lakosh `}�4EtJ STgTfi UNITED STATES ENVIRONMENTAL PROTECTION AGENCY Awl WASHINGTON D C 20460 q� PRO, APPI ? 3 '?015 Of FWE OF WAtER (MEMORANDUM FROM: Peter C. Grevatt, Director Office of Ground Water and Drinking Nt ater TO: Regional Water Division Directors SUBJECT: Key Principles in EPA's Underground Injection Control Program Class VI Rule Related to Transition of Class II Enhanced Oil or Gas Recovery Wells to Class VI Most states have primary enforcement responsibility (i.e., primacy) for the Class II Underground Injection Control program for oil or gas -related injection activities, while EPA Regions currently retain direct implementation authority for the Class VI program in every state. The shared implementation of the UIC program necessitates a clear articulation and common understanding of the potential for transition of enhanced recovery wells from Class II to Class VI, consistent with EPA's Class VI Rule. This memo is intended to emphasize the key principles in EPA's UIC Class VI Rule related to the transition from Class II to Class VI for ER wells that inject carbon dioxide for long-term storage. As Regions work with states on implementation of the Class VI program, I encourage you to assist states in submitting primacy applications for all well classes, including Class VI. EPA recognizes the importance of geologic sequestration of anthropogenic CO2 for climate change mitigation. The UIC Class VI Rule was developed to facilitate GS and ensure protection of underground sources of drinking water from the particular risks that large scale CO2 injection for purposes of long- term storage may pose. The following are key principles related to the transition of ER wells that store CO2 from Class 11 operations to the Class VI program: 1. Geologic storage of COz can continue to be permitted under the UIC Class 11 program. ER wells across the U.S. are currently permitted as UIC Class II wells. CO2 storage associated with Class lI wells is a common occurrence. and CO2 can be safely stored where injected through Class II -permitted wells for the purpose of oil or gas -related recovery. 2. Use of anthropogenic CO2 in ER operations does not necessitate a Class VI permit. ER operations can continue to be permitted as Class I1 wells, regardless of the source of CO,,. An owner or operator of an ER operation can switch from using a natural source to an anthropogenic source of CO2 without triggering the need for a Class VI permit. intemet Address CURLr • hhp liwwwepa gov Recycled?Recyclable • Panted with Vegetable Oil Based Inks on tpp's',, Postconsurrier Process Chlorine Free Recycled Paper 0 • 3. Class VI site closure requirements are not required for Class II CO: injection operations. A Class II well that has been used fbr injection of anthropogenic or non-anthropogenic COs and has been operated within its permit conditions can be closed as a Class II well. 4. f ER operations that are focused on oil or gas production will be managed under the Class II program. If oil or gas recovery is no longer a significant aspect of a Class II permitted ER operation, the key factor in determining the potential need to transition a COz ER operation from Class 11 to Class VI is the increased risk to USDWs related to significant storage of COz in the reservoir, where the regulatory tools of the Class II program cannot successfully manage the risk. The most direct indicator of increased risk to USDWs is increased pressure in the injection zone related to the significant storage of CO2. Increases in pressure with the potential to impact USDWs should first be addressed using tools within the Class 11 program. Transition to Class VI should only be considered if the Class II tools are insufficient to manage the increased risk. 5. The Class II and Class VI directors should work together to address the potential need for transition of any individual operation from a Class II to a Class VI permit. The Class II program director (in most cases a state official) will have the relevant data on pressure and volume of CO? injected into Class II ER operations, which will influence any transition decision. EPA encourages the Class II director to contact the Class VI director where he/she believes the risk has changed as a result of significant storage of CO2 in the reservoir. b. - The best implementation approach is for states to administer both the Class II and the Class VI UIC programs. EPA encourages states to apply f'or primacy for all well classes, including Class VI. Based on our conversations with states, in most cases, states who are approved for primacy for the Class VI program are expected to administer the program through their oil and gas program. The Office of Ground Water and Drinking Water is currently working with the U.S. Department of Energy, state associations, EPA Regions and stakeholders to finalize technical guidance focused on risk factors discussed in the Class VI Rule at 40 CFR 144.19. As we complete the final guidance, we will work to ensure that these key principles remain clear. Please contact me or have your staff contact Ron Bergman at 202-564-3823 if we can be of assistance to you on these or other UIC program issues. ' The key regulation, " Transitioning from Class 11 to Class VI," codified at 40 CFR 144.19, states that owners or operators that are injecting carbon dioxide fur the primary purpose of long-term storage into an oil and gas reservoir must apply for and obtain a Class V I GS permit svlren there is an increaser) risk to USDIPs compared to Class H operations. Prudhoe Oil Pool Major Gas Sales Presentation to the AOGC( by BPXA as an individual Prudhoe Bay Unit working interest owner Objectives • General overview of the Alaska LNG project Support Bule 9 Application for amendment of CO 341 D Bule 9 for the Prudhoe Oil • Pool (POP) Technical justification for increasing the maximum allowable gas offtake from 2.7 to 4.1 BCFD Address several topics of interest for the AOGCC Support Application for A10 Modification of A10 3A and A10 4F Technical justification for request to inject CO2-byproduct into the POP for Enhanced Recovery and Pressure Maintenance Alaska GasTreatment Plant (GTP) • 3.3 BSCFD peak export rate • Three trains • CO2 removed for i injection at PBU Liquefaction Facility • Natural gas is cooled to -260 deg F • 3 trains dehydrate, and liquefy gas to produce up to 20 million tons of LNG each year LNG Storage & Marine Terminal • LNG storage tanks • Two jetties for LNG carriers Nl8SK8 • GNSIIK .• OWHOPHfNt CORP An integrated liquefied natural gas export project that would provide access to gas for Alaskans Rea,,fnit Sea Subject to Change p o Point 'homson � ------ 31 'i i i Y x o I{ GOOD :AIRBANKS I DELTA UNCTION -------- --- TOK AGE : ALDEZ Sow `Gulf of A77 iskd-,ryk�I Source - AK LNG Point Thomson Transmission Line (PTTL) • -60 miles, 32" diameter above ground Prudhoe Bay Transmission Line (PBTL) • —1 mile, 60" diameter above ground Gas Pipeline • 800+ mile 42" diameter below ground gas pipeline • 6-10 compressor stations • Up to 5 in -state off -take points Artists renditions of LNG and GTP 0 ConocoPhillips E�onMobil %�j TransCanada 3 by 0 The Major Gas Sales (MGS) Reference Case (3.3 BSCFD) and the Maximum Allowable Gas (MAG) Sensitivity Case (4.1 BSCFD) both demonstrate significant additional hydrocarbon recovery from POP as a result of major gas sales Results of the MGS reference case demonstrate that POP is capable of delivering: Approximately 22 Trillion Standard Cubic Feet (TSCF) of hydrocarbon sales gas or 3.8 billion Barrels of Oil Equivalent (BOE) A gas sales plateau length of 20+ years Continued oil development and production The MAG sensitivity case produces an equivalent ultimate hydrocarbon recovery of between 17.7 and 17.8 billion BOE's An increase in Rule 9 gas offtake to an annual average of 4.1 billion standard cubic feet per day (BSCFD) is consistent with good oil field engineering practices; and positions the Prudhoe Bay Unit working interest owners to access the MGS opportunity afforded by the Alaska LNG Project, and therefore should be approved 0 • PO P -Basis Alaska LNG Project has advised gas supply to the GTP must be maintained during normal operations at a rate of —3.5 BSCFD annual average untreated gas GTP feed rate of —3.5 BSCFD rate allows for 0.4 - 0.5 BSCFD for in -State gas demand and —2.7 BSCFD to satisfy LNG facility inlet demand POP's total gas offtake would also include lease fuel, minor North Slope sales and Miscible Injectant (MI) used outside of the POP in Prudhoe Bay Unit satellites. 4.1 BSCFD allows POP flexibility- to supply the full GTP feed rate in the event of supply disruptions from other fields to accommodate improved facility performance and allow operational flexibility POP Offta ke — MGS Reference Case (Normal Operations) —2.7 POP Offtake — MAG Sensitivity Case * Higher supply rate due to higher CO2 concentrations in POP than in other fields 0 0 Gas OfFtake Produce gas from existing well stock Optimize offtake with: Targeted re -completion for gas Injector to producer conversions Two redundant offtake points at Central Gas Facility (CGF) Upgrade select equipment to ensure reliable gas delivery AKLNG Project participants are designing the GTP to return the CO2 byproduct to PBU Control Conceptual CO2 receipt coo Module Module @ and distribution system cGr. . 0.5 miles CO2 from GTP APEX PL I- 1 miles) WP W CO2 Receipt and Injection Injection into Eileen West End (EWE) through new pipeline to existing wells at well pads W and Z EWE is the most promising option. Additional CO2 injection options outside POP will be evaluated for additional enhanced recovery opportunity Backup capability could be FS2 and the Apex injectors by • • The current field activity prepares for MGS: Active drilling program Rig workovers to maintain healthy well stock Continued Gas Cap Water Injection (GCWI) Active non -rig well work programs Waterflood and M I management BPXA and the other unit owners will continue to actively manage field optimization of the depletion strategy to enhance field performance into the future C7 The Major Gas Sales (MGS) Reference Case (3.3 BSCFD) and the Maximum Allowable Gas (MAG) Sensitivity Case (4.1 BSCFD) both demonstrate significant additional hydrocarbon recovery from POP as a result of major gas sales Results of the MGS reference case demonstrate that POP is capable of delivering: Approximately 22 Trillion Standard Cubic Feet (TSCF) of hydrocarbon sales gas or 3.8 billion Barrels of Oil Equivalent (BOE) A gas sales plateau length of 20+ years Continued oil development and production The MAG sensitivity case produces an equivalent ultimate hydrocarbon recovery of between 17.7 and 17.8 billion BOE's An increase in Rule 9 gas offtake to an annual average of 4.1 billion standard cubic feet per day (BSCFD) is consistent with good oil field engineering practices; and positions the Prudhoe Bay Unit working interest owners access the MGS opportunity afforded by the Alaska LNG Project, and therefore should be approved • r� by Objective Requesting modification to AlO 3A and 4F for the POP Explain technical benefits and implications of injection CO2 into POP • Summary CO2 handling limitations impact CO2 injection development options POP is injecting a similar amount of CO2 under current field operations EWE is the most promising location for CO2 injection within the POP Additional CO2 from outside sources generates negligible changes to POP reservoir outcomes BPXA has studied and anticipates that the PBU working interest owners will continue to evaluate potential locations where CO2 injection may be economically i beneficial for enhanced recovery and pressure maintenance - n* Discussion of the Full Field Model and the quality and uses Forward prediction of the Oil Reference Case Detailed discussion of comparative cases and assumptions Description of gas delivery and CO2 handling MGS Reference Case profile MAG Sensitivity Case profile Expected recovery comparison MGS start date sensitivity AlO modification CO2 studies already con ducted POP and non -POP CO2 recovery estimates BPXA Presentation All opinions, assessments and analyses (including forward looking or predictions of future activities) in this presentation are those of BP Exploration (Alaska) Inc., in its capacity as an individual working interest owner in the Prudhoe Bay Unit. The PBU FFM consists of three parts: (1) historical PBU operational data; (ii) a set of reasoned assumptions about future PBU activities; (items (1) and (ii) are collectively referred to as the "FFM Inputs"); and (iii) a BPXA proprietary and trade secret process consisting of software code and algorithms owned by or licensed to BPXA (the "FFM Tool"). Full Field Model runs (sometimes referred to as cases or scenarios) are generated by inputting the FFM Inputs into the FFM Tool. FFM runs are meant to be predictive of future circumstances or consequences that could occur, depending on the FFM Inputs. Because of the proprietary and trade secret processes that BPXA employs in the use of the FFM Tool, it is not possible to derive • the details of PBU operational or technical data (e.g., specific geological data) from FFM runs. BPXA uses the FFM Tool to generate FFM runs for both itself and, upon request, for the PBU working interest owners. All references in this testimony to the FFM (or to PBU FFM) are a reference to FFM Inputs plus the FFM Tool. ExxonMobil Production Company P. O. Box 196601 Anchorage, Alaska 99519-6601 907-561-5331 Telephone 906-564-3677 Facsimile August 27, 2015 Ms. Cathy P. Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West 71h Avenue, Suite 100 Anchorage, Alaska 99501 Cory Ouarles Alaska Production Manager E�onMobil Production RECEIVED AUG 27 2015 AOGCC Re: Consolidated Application for Amendment of Prudhoe Oil Pool Rule 9 and Modification of Prudhoe Bay Unit Area Injection Orders AIO 3A and AIO 4F Dear Chair Foerster: On July 17, 2015, BP Exploration (Alaska) Inc. (BPXA) filed with the Commission a Consolidated Application for Amendment of Prudhoe Oil Pool Rule 9 and Modification of Prudhoe Bay Unit Area Injection Order AIO 3A and AIO 4F (the Application) which was filed on behalf of ExxonMobil Alaska Production Inc. (ExxonMobil) as an individual working interest owner in the Prudhoe Bay Unit. ExxonMobil supports the request to increase the maximum annual average gas offtake rate for the Prudhoe Oil Pool from the current 2.7 billion standard cubic feet per day to 4.1 billion standard cubic feet per day. ExxonMobil also supports the request to modify Area Injection Orders AIO 3A and AIO 4F to authorize injection of a byproduct stream from the Alaska LNG Project Gas Treatment Plant, composed of CO2, and other effluent gases from sources within or outside the Prudhoe Bay Unit. The application seeks approvals from the Commission that will support work by the parties in the Alaska LNG Project, and allow progress to the next, front-end engineering and design, stage for that project. A maximum annual average gas offtake rate of 4.1 billion standard cubic feet per day, and modification of the Area Injection Orders to allow injection of COZ is in accordance with good oil field engineering practice. The requested actions are appropriate for the Commission to take. ExxonMobil also supports the pre -filed testimony, witness presentations, and other supporting evidence presented by BPXA to the Commission in support of the Application. ExxonMobil respectfully asks that the Commission approve the request set forth in the application by BPXA. Sincerely, a' CEQ:J c xc: Commissioner Daniel T. Seamount Dave P. Lachance, BPXA A Division of Exxon Mobil Corporation 0 0 Dave Lachance Vice President Alaska Reservoir Development August 25, 2015 Via Hand Delivery Cathy P. Foerster Commission Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, AK 99508 USA Direct 907 564 4855 Mobile 907 538 1719 Main 907 564 5111 dave.lachance@bp.com RECEIVED AUG 2 5 2015 AOGCC Re: Docket Numbers: AIO 15-032 AIO 15-033 and CO 15-09 Prudhoe Oil Pool BPXA Written Testimony in support of Consolidated Application for Amendment of Prudhoe Oil Pool Rule 9 and Modification of Prudhoe Bay Unit Area Injection Orders AIO 3A and AIO 4F Dear Chair Foerster: BP Exploration (Alaska) Inc. submits, on behalf of itself and ExxonMobil Production Inc., as applicants in the above referenced matter, and respectfully requests that the Commission accept the enclosed written and sworn testimony. Depending upon the testimony, if any, presented by others at the public hearing, BPXA reserves the right to present additional testimony at the public hearing, or by post -hearing submission if so authorized by the Commission. Please note that the portion of sworn testimony contained in the Confidential Appendix is confidential, and BPXA requests that such information be held confidential pursuant to AS 31.05.035(d), 20 AAC 25.537(b) and AS 45.50.910 et seq., as well as Section 11.4 of the Prudhoe Bay Unit Agreement. The Confidential Appendix is enclosed in a separate envelope and marked confidential. Sincerely, Dave P. Lachance Vice President, Reservoir Development BPXA Written Testimony • • Application to Amend POP Rule 9 and Modify AIOs August 25, 2015 Page 2 Attachment cc via email: Ernesto Daza, BPXA (ernesto.daza@bp.com) John Dittrich, BPXA Oohn.dittrich@bp.com) George Lyle, Guess & Rudd (glyle@guessrudd.com) Chris Wyatt, BPXA (chris.wyatt@bp.com) Gilbert Wong, EMAP (gilbert.wong@exxonmobil.com) Gerry Smith, EMAP (Gerry.b.smith@exxonmobil.com) Steve Luna, EMAP (charles.s.luna@exxonmobil.com) Brian Gross, EMAP O.brian.gross@exxonmobil.com) Jon Schultz, CPAI(Jon.Schultz@conocophillips.com) Eric Reinbold, CPAI (Eric.W.Reinbold@conocophillips.com) John Evans, CPAI(John.R.Evans@conocophillips.com) Phil Ayer, CUSA (pmayer@chevron.com) Angie Bible, CUSA (abible@chevron.com) • 0 STATE OF ALASKA Alaska Oil and Gas Conservation Commission Docket Numbers: AIO 15-032, AIO 15-033 and CO 15-09 Application for Amendment of Pool Rule 9 and Modification of AIOs Prudhoe Oil Pool, Prudhoe Bay Field Written Submittal of BP Exploration (Alaska), Inc. Submitted August 25, 2015 Commissioners: RECEIVED AUG 2 5 2015 AOGCC This submission and the accompanying appendices are a component of the application by BP (Exploration) Alaska, Inc. ("BPXA") as an individual working interest owner ("WIO") in the Prudhoe Bay Unit ("PBU") and not as PBU operator, on behalf of itself and PBU WIO ExxonMobil Alaska Production Inc. ("EMAP"), to the Alaska Oil and Gas Conservation Commission ("AOGCC" or "Commission"), for an amendment of Prudhoe Oil Pool ("POP") Rule 9 of Conservation Order ("CO") 341 D and modification of PBU Area Injection Orders ("AIOs") 3A and 4F. INTRODUCTION The application requests that the Commission amend the maximum annual average gas offtake rate for the POP in CO 341 D Rule 9, from 2.7 billion standard cubic feet per day ("bscf/d") to 4.1 bscf/d. As demonstrated in the application and this testimony, a maximum annual average gas offtake rate of 4.1 bscf/d is in accordance with good oil field engineering practices and should be approved by the Commission. The application also requests that the Commission modify AIOs 3A and 4F to authorize the injection of CO2 for enhanced hydrocarbon recovery and reservoir pressure maintenance, from sources both within and outside the PBU. As demonstrated in the application and this testimony, the requested modification of AIOs 3A and 4F is in accordance with good oil field engineering practices and should be approved by the Commission. BPXA and EMAP are filing this application with the Commission so each PBU WIO has the ability to access the opportunity presented by the Alaska LNG Project (the "AK LNG Project") to progress major gas sales of Prudhoe Bay Unit natural gas ("PBMGS"). As the Commission knows, affiliates of the three largest PBU WIOs — BPXA, EMAP and ConocoPhillips Alaska, Inc. ("CPAP') are all working with the State of Alaska to develop the AK LNG Project. BPXA will provide a witness at the public hearing to testify further on the AK LNG Project from BPXA's perspective. 1 Written Submittal of BPOloration (Alaska) Inc. 0 Application for Amendment of POP CO 341D Rule 9 and AIOs 3A and 4F This application and the requested approvals are necessary at this time for several reasons: (i) The requested approvals are needed so BPXA, EMAP and the other PBU WIOs have the ability to access the opportunity presented by the AK LNG Project for progressing PBMGS. The AK LNG Project participants have informed the PBU WIOs that the approvals requested in this application are necessary at this time to support progression of the project beyond pre -FEED engineering stage of development. The requested approvals are just one of many regulatory and facility planning activities on which the PBU WIOs have been diligently working to prepare for PBMGS. (ii) The requested approvals support individual PBU WIO and State of Alaska internal preparations i'or major gas sales, including preparations for marketing each party's respective share of PBU gas. BPXA and EMAP collectively own 63 percent of the working interests in the oil and gas leases that comprise the PBU. The ability of each PBU WIO and the State of Alaska (assuming an election by the State to take gas royalty in kind) to market its gas is fundamental to the success of the PBMGS opportunity presented by the AK LNG Project. LNG buyers will demand certainty of gas supplies to the AK LNG Project system, and without the certainty provided by the requested approvals, BPXA and EMAP respective LNG marketing efforts to monetize their shares of PBU gas production would be impeded. The inability of each company to progress its individual gas marketing efforts would hinder progress of the AK LNG Project. BPXA is submitting this sworn testimony in the form of this written narrative and associated exhibits. This testimony is provided by BPXA as an individual PBU WIO. BPXA has consulted and coordinated with PBU WIO EMAP in the preparation of this testimony, and has their support in the application. The assessments contained in this testimony have been discussed with the other PBU WIOs, CPAI and Chevron U.S.A. Inc. ("CUSA"). Section I of this submission identifies the witness who is submitting this written testimony on behalf of BPXA. Section II provides a brief summary of this testimony. Section III contains the substance of the testimony in support of an amendment to CO 341D Rule 9. Section IV contains the substance of testimony in support of modification of AIOs 3A and 4F. Section IT, which is being separately submitted to the Commission as a Confidential Appendix to preserve confidentiality, contains confidential information and figures referenced in this testimony that BPXA requests be held confidential by the Commission pursuant to AS 31.05.035(d), 20 AAC 25.537(b) and AS 45.50.910 et seq. Pa Written Submittal of BP Exploration (Alaska) Inc. Application for Amendment of POP CO 341D Rule 9 and AIOs 3A and 4F SECTION I BPXA WITNESS This narrative submission is the testimony of Mr. Bruce Laughlin. His business address is 900 E. Benson Blvd., Anchorage, Alaska 99508. Mr. Laughlin received a Bachelor of Science Degree from Pennsylvania State University and a Masters of Science degree from Texas A&M University. Mr. Laughlin's current title at BPXA is Reservoir Management Team Leader. In his present position, Mr. Laughlin supervises BPXA and contract staff focused on delivering long term oil and gas production opportunities for BPXA's PBU assets, including the POP. His team comprises reservoir engineers, geologists and geophysicists. Mr. Laughlin has the training, experience and knowledge relevant and necessary to provide the opinions included in this testimony; in particular as to analytical and dynamic simulation of field depletion mechanisms. Mr. Laughlin has previously testified before the AOGCC as an expert in January 2014 in relation to the "Inquiry Into Gas Liquids Disposition." BPXA respectfully requests that the Commission qualify Mr. Laughlin as an expert in these proceedings in accordance with 20 AAC 25.540(c)(5). Mr. Laughlin will be present, and made available to the Commissioners for questions, at the public hearing on this application to amend POP Rule 9. As noted above, BPXA will provide at least one non -expert witness at the public hearing to testify on the AK LNG Project from BPXA's perspective. That testimony is not included in this filing. SECTION II SUMMARY OF SUBMITTAL A. The Requested Amendment Will Support Progress On The AK LNG Project BPXA and EMAP consider this request to amend the gas offtake rate in Rule 9 of CO 341 D as a significant step for PBU development. The PBU WIOs and the AOGCC have long contemplated a major gas sale project. The participants in the AK LNG Project (which include the State of Alaska and affiliates of BPXA, EMAP and CPAI) have publicly stated that they are progressing plans for an integrated LNG project with a scheduled start-up in 2025. The requested amendment of CO 341 D Rule 9 to increase the maximum annual average gas offtake rate from 2.7 bscf/d to 4.1 bscf/d facilitates that opportunity by providing the flexibility to supply both expected normal and full sustained gas feed rates to the AK LNG Project Gas Treatment Plant ("GTP") from the POP. The AK LNG Project participants have informed the PBU WIOs that the GTP is being designed for sustained receipt of feed gas at the GTP at an annual average rate of 3.5 bscf/d. (The filings by the AK LNG Project with FERC state that the GTP will have an initial gas treating capacity of up to 4.3 bscf/d of feed gas.) BPXA expects that under 3 Written Submittal of BP Xploration (Alaska) Inc. • Application for Amendment of POP CO 341 D Rule 9 and AIOs 3A and 4F normal operating circumstances, after a one-year operations ramp -up period beginning in 2025, approximately three -fourths of the gas delivered to the GTP is anticipated to be from the POP (2.7 bscf/d) and one-fourth is anticipated to be from Point Thomson or other sources (0.8 bscf/d). (Please refer to AK LNG project draft Resource Reports filed with FERC, cited in the application). To support this level of gas delivery to the GTP from the POP, a minimum annual average gas offtake rate of 3.3 bscf/d from the POP would be required (2.7 bscf/d to the GTP and additional gas offtake of approximately 0.6 bscf/d annual average used for fuel, field operations and minor local gas sales). However, because the GTP is being designed for sustained receipt of feed gas at an average annual rate of 3.5 bscf/d, if the supply of gas to the GTP from the Point Thomson Unit or other sources does not occur as expected or is interrupted, up to 100 percent of the gas supply to the GTP from the POP would be required to maintain uninterrupted gas deliveries to the AK LNG Project. To allow the flexibility for the POP to be the source for up to 100 percent of the feed gas supplied to the GTP in those circumstances, and to avoid disruptions to GTP operations and resulting disruptions to PBU operations that could result from interruptions in a sustained stable supply of gas to the GTP, BPXA and EMAP are requesting AOGCC authorization for a maximum annual average gas off -take of 4.1 bscf/d (3.6 bscf/d to the inlet of the GTP plus 0.5 bscf/d for fuel, field operations and minor local gas sales). Note that in the 100 percent POP case, the feed gas inlet to the GTP must be slightly greater than 3.5 bscf/d to yield an equivalent hydrocarbon gas delivery to the downstream gas offtake points and the LNG liquefaction facility because the CO2 percentage of the POP feed gas stream is greater than in the Point Thomson feed gas stream. The POP fuel gas requirements in the 100 percent POP case drops slightly from 0.6 bscf/d to 0.5 bscf/d since less POP gas is re -injected into the Prudhoe reservoir. A 4.1 bscf/d offtake rate for the POP also would accommodate improved facility performance and allow operational flexibility. The GTP is being designed to receive, treat and ship gas to the liquefaction facility, and to return CO2 by-product to the PBU for injection. Similar to the requested amendment of Rule 9 addressed above, the requested modifications to the AIOs are being requested at this time to support the joint efforts of the State of Alaska and the other participants in the AK LNG Project to progress the project to the front-end engineering and design (FEED) development stage. As more specifically addressed below, modifications of the AIOs are based upon the AK LNG Project design plan for injection of the GTP CO2 by- product into the POP. B. There Is A High Degree Of Confidence In The Current Full Field Model Results The PBU Full Field Model ("FFM') consists of three parts: (i) historical PBU operational data; (ii) a set of reasoned assumptions about future PBU activities; (items (i) and (ii) are collectively referred to as the "FFM Inputs"); and (iii) a BPXA proprietary and trade secret process consisting of software code and algorithms owned by or licensed to BPXA (the "FFM Tool"). Full Field Model runs (sometimes referred to as model scenarios) are generated by inputting the FFM Inputs into the FFM Tool ("FFM Runs"). 4 Written Submittal of BP Exploration (Alaska) Inc. Application for Amendment of POP CO 341D Rule 9 and AIOs 3A and 4F FFM Runs are meant to be predictive of future circumstances or consequences that could occur, depending on the FFM Inputs. Because of the proprietary and trade secret processes that BPXA employs in the use of the FFM Tool, it is not possible to derive the details of PBU operational or technical data (e.g., specific geological data) from FFM Runs. BPXA uses the FFM Tool to generate FFM Runs for both itself and, upon request, for the PBU WIOs. All references in this submission to the FFM are a reference to FFM Inputs plus the FFM Tool. References to and discussions of FFM modeling, scenarios, runs and similar statements are references to FFM Runs. The AOGCC and the PBU WIOs have evaluated and reviewed the potential effects of a PBMGS project on oil production and hydrocarbon recovery from the POP at various stages of field development, most recently in 20071. The PBU WIOs informed and discussed with AOGCC staff, in a series of workshops held earlier this year, upgrades that BPXA has made to the FFM since 2006. Over the past several years the underlying geologic and dynamic data have been extensively reviewed and agreed by the WIOs with the State of Alaska to determine the historic and predictive behavior. The upgrades that have been made by BPXA to the FFM include: increased model resolution; improved and updated well breakage and repair assumptions and data; segregation of drilling by type and area to align assumptions and predictions with potential drilling schedules; use of an improved fuel gas usage algorithm; and improved and updated satellite field flow assumptions and data. Moreover, with substantial updated production and flow history, the FFM history match has been updated to 2014 and improved to include gas cap water injection ("GCWF') impacts on reservoir pressure projections. The updated and recalibrated FFM provides a higher degree of confidence in its predictive capabilities. C. The PBMGS Gas Reference Case The FFM was used to generate an FFM Run of the estimated increase in ultimate hydrocarbon recovery from the POP for a PBMGS case beginning in 2025 and assumed to end in 2055, with a total annual average gas offtake rate of 3.3 bscf/d including all uses, (the "gas reference case"), as well as the estimated ultimate hydrocarbon recovery from the POP. BPXA's assessment of the gas reference case is that hydrocarbon recovery is increased by approximately 3.8 billion barrels of oil equivalent ("BOE") or 22 trillion standard cubic feet of gas ("tscf'). Combined with oil, condensate and NGLs production, BPXA's 1 The Commission has long understood that the gas off -take rate in Rule 9 of CO 341 D would have to be revised for major gas sales. See the July 10, 2007 Report Of The Commission Inquiry Into Amending Rule 9 and December 5, 2005 Report On Commission Inquiry Into Potential Revision of Gas Offtake Limit. Written Submittal of BP Exploration (Alaska) Inc. • Application for Amendment of POP CO 341 D Rule 9 and AIOs 3A and 4F assessment is that total hydrocarbon recovery from the POP under the gas reference case is approximately 17.7 billion BOE; a net increase of 3.6 billion BOE from the current oil reference case. The details of BPXA's assessment of the gas reference case are discussed in Section V (the Confidential Appendix). D. The PBMGS Full GTP Inlet Supply Case (The Application Request) The FFM was also used to generate an FFM Run evaluating a scenario where the requested total annual average gas offtake rate from the POP of 4.1 bscf/d was applied for an assumed AK LNG Project life of 30 years (i.e., assuming no gas delivery to the GTP from other fields) (the '!full GTP inlet supply case"). This case has been compared to the gas reference case. BPXA's assessment of the full GTP inlet supply case is that slightly more BOEs are recovered than in the gas reference case (17.8 billion instead of 17.7 billion BOEs) due to higher gas recovery that offsets additional impacts on oil production. The details of BPXA's assessment of the full GTP inlet supply case are discussed in Section V (the Confidential Appendix). E. Reference Case Sensitivities The FFM also was used to test the sensitivity of reference case predicted oil and gas recovery to a robust set of alternative assumptions and development scenarios. This type of analysis is often undertaken by BPXA, using its FFM Tool, in conjunction with BPXA and the other PBU WIOs development of specific development plans. Apart from in -place volumes, the most sensitive parameters identified are CO2 injection location (for enhanced hydrocarbon and pressure maintenance), and well breakage. BPXA's assessment of the results of these analyses is that the sensitivity of liquid and total hydrocarbon recovery is negligible (less than 1 percent). The details of BPXA's analysis are discussed in Section V (the Confidential Appendix) F. CO2 Injection into the POP The AK LNG Project participants have indicated that the GTP is being designed to deliver 350 to 450 mmscf/d of CO2 byproduct to PBU for injection. Greater than 90 percent of the total CO2 volume will originate from gas delivered to the GTP from PBU. The additional hydrocarbon recovery associated with PBMGS is 3.8 billion BOE. This additional hydrocarbon recovery is dependent upon CO2 being received at PBU from the GTP. Reservoir studies have been conducted to look at several possible injection locations for enhanced hydrocarbon recovery and pressure maintenance, and initially the Eileen West End ("EWE") area has been identified as the most promising, but the specific location in the POP has not been determined. BPXA and EMAP will continue to work with the PBU WIOs, the Commission and the Alaska Department of Natural Resources to determine one or more locations for injection of CO2 for enhanced 2 • 0 Written Submittal of BP Exploration (Alaska) Inc. Application for Amendment of POP CO 341D Rule 9 and AIOs 3A and 4F hydrocarbon recovery and pressure maintenance. G. Conclusion The POP is the most robust resource on the North Slope, with more than 35 years of production history and operations. BPXA and EMAP are seeking a maximum annual average gas off -take rate of 4.1 bscf/d to allow for the full inlet gas delivery to the GTP and related LNG facilities to be supplied from the POP. This off -take rate will provide BPXA and EMAP, the other PBU WIOs (CPAI and CUSA) and the State of Alaska with flexibility, and allow use of POP gas to cover any gas supply disruptions to the GTP that may occur from other gas supply fields. BPXA and EMAP are also seeking a modification of AIOs 3A and 4F to authorize the injection of CO2 into the POP for enhanced hydrocarbon recovery and reservoir pressure maintenance purposes, from sources both within and outside the PBU. BPXA is confident in the results of the updated and enhanced FFM. BPXA's assessment of the studies and the FFM Runs that have been performed using the FFM is that: (i) total BOE hydrocarbon recovery for the POP is substantially increased with a PBMGS project by approximately 3.8 billion BOE or 22 tscf of gas. Combined with oil, condensate and NGLs production, total hydrocarbon recovery from the POP under the gas reference case is approximately 17.7 billion BOE, a net increase of 3.6 billion BOE from the current oil reference case; (ii) the total BOE hydrocarbon recovery from the POP at the requested full GTP inlet supply case off -take rate (17.8 billion BOE) is comparable to the gas reference case off -take rate (17.7 billion BOE), a difference of less than 1 percent; (iii) ultimate hydrocarbon recovery is relatively insensitive to alternative assumptions and scenarios (less than 1 percent); and (iv) EWE is initially the most promising location for injecting CO2 for enhanced hydrocarbon recovery and pressure maintenance. SECTION III AMENDMENT OF CO 341D RULE 9 TO INCREASE THE MAXIMUM GAS OFF -TAKE TO 4.1 bscf/d IS PRUDENT, APPROPRIATE AND NECESSARY TO PROGRESS THE AK LNG PROJECT A. POP Rule 9 Gas Off -Take Rate CO 341D Rule 9 limits the maximum annual average gas offtake from the POP to 2.7 bscf/d. Currently, approximately 0.6 bscf/d from the POP is used for fuel, field operations and minor local gas sales. This level of other gas usage is anticipated to 7 Written Submittal of BP Bxploration (Alaska) Inc. • Application for Amendment of POP CO 341D Rule 9 and AIOs 3A and 4F remain stable. Accordingly, under Rule 9, an annual average gas off -take of approximately 2.1 bscf/d would be available for gas pipeline delivery for major gas sales. This offtake level is not adequate to allow sufficient gas delivery from the POP to the AK LNG GTP for PBMGS. (Please note that unless otherwise indicated, references to AK LNG public statements in this submission are to the draft Resource Reports filed with FERC as referenced in the application.) 1. AK LNG Proiect The participants in the AK LNG Project, including the affiliates of both BPXA and EMAP and the State of Alaska, have informed the PBU WIOs that the design of the AK LNG facilities is premised on a sustained annual average gas supply rate of 3.5 bscf/d to the GTP. (AK LNG Project participants have publicly stated that the GTP will have an initial gas treating capacity of up to 4.3 bscf/d of feed gas.) The AK LNG Project participants have also publicly stated that the GTP is being designed to receive, treat, and ship gas to the Liquefaction Plant, and to return for reinjection into the POP the by- product primarily consisting of CO2. 2. POP Gas Supply to AK LNG The AK LNG Project participants have publicly stated that under normal operating circumstances, they anticipate that —3/4 of the feed gas to the GTP (2.7 bscf/d) will be from the POP, and the remaining 1 /4 of the feed gas (0.8 bscf/d) will be from Point Thomson or other sources. BPXA and EMAP together will provide approximately 69 percent of the total hydrocarbon resources from these fields to the AK LNG Project. BPXA and EMAP's assessment is that the POP will be able to deliver gas to the GTP for 30 years under this scenario. 3. Amendment of Rule 9 CO 341D Rule 9 limits the maximum annual average gas off -take from the POP to 2.7 bscf/d. Currently, approximately 0.6 bscf/d of gas from the POP is used for fuel, field operations and minor local gas sales. This level of other gas usage is anticipated to remain stable in the future. Therefore, the current 2.7 bscf/d off -take limit is insufficient to meet the gas delivery inlet capacity of the AK LNG GTP under even normal operating conditions, which assume delivery of 0.8 bscf/d from Point Thomson or other sources (current POP offtake limit of 2.7 bscf/d minus 0.6 bscf/d gas for fuel, field operations and minor local sales only allows 2.1 bscf/d to the GTP, which combined with 0.8 bscf/d from Point Thomson or other sources does not meet AK LNG Project design for a sustained annual average gas supply rate of 3.5 bscf/d of feed gas to the GTP). Under the circumstance where gas delivery to the GTP from Point Thomson and other sources does not occur as expected or suffers a supply interruption, a total gas offtake of 4.1 bscf/d would be required from the POP (3.6 bscf/d to the GTP + 0.5 bscf/d for fuel, field operations and minor local sales) to allow the full supply of inlet gas supply to the 8 • 9 Written Submittal of BP Exploration (Alaska) Inc. Application for Amendment of POP CO 341 D Rule 9 and AIOs 3A and 4F GTP. B. Full Field Model And Data Improvements BPXA has made many updates to the FFM since the AOGCC last considered analyses of a PBMGS in 2007. The following is a high level summary of those updates. Section V of the Confidential Appendix contains a comprehensive and more detailed discussion of these confidential FFM improvements. BPXA has continuously updated the FFM since its original development. Over many years of historical production and development updates, the model continues to narrow the assumptions and improvement needs. The physical constraints associated with facility limits, pipeline networks, drilling and well work activity all contribute to better understanding of the shape of the model and the property distribution. With improved computer processors, refinements to the grid resolution have given better understanding to the flow characteristics between wells. The FFM has been used internally by BPXA to inform its analysis, from a PBU WIO perspective, of drilling projects, the gas cap water injection project, surface facility debottlenecking projects, as well as previous PBMGS analyses. BPXA has also provided FFM Runs to the PBU WIOs to inform their analysis of similar projects. As a result of these FFM refinements and updated data, BPXA's assessment of the FFM is that the current history match predicts each fluid phase within 1 percent of actual field data. Therefore, BPXA considers the current FFM to be highly reliable. C. FFM Assumptions And Analyses In order to assess hydrocarbon recovery for a PBMGS development scenario compared to an oil production scenario, a reference case set of assumptions was developed and incorporated in the FFM to reflect both sound engineering principles and a development program that recognizes economic considerations. The following is a high level summary of those assumptions. Section V of the Confidential Appendix contains a comprehensive discussion and details of these assumptions. In order to perform a valid analysis of the benefits for PBMGS, the model requires assumptions about both oil -focused operations and a PBMGS. In this analysis, the following assumptions were made for the oil reference case and the gas reference case. 1. The Oil Reference Case The oil reference case assumed the following activities will continue. Among these assumptions are activities that have been implemented with the view toward PBMGS. • Active development drilling program • Rig workovers to maintain healthy well stock E Written Submittal of BP Vloration (Alaska) Inc. • Application for Amendment of POP CO 341 D Rule 9 and AIOs 3A and 4F • Continued Gas Cap Water Injection • Normal Turnaround activities for facility maintenance 2. The PBMGS Gas Reference Case The gas reference case includes many of the same activities assumed for the oil reference case. The reason for these assumption sets to be the same is to give a more valid consideration of the benefits on a like -for -like comparison. There are certain additions to the assumptions that must be incorporated to manage a gas analysis. The following are the assumptions associated with the gas reference case. • Same development drilling program as the oil reference case • January 2025 gas sales startup date with a 1 year ramp to full delivery • Annual average gas supply to the GTP —2.7 bscf/d • Normal annual turnaround maintenance events • GTP by-product COZ injected into the Eileen West End of the POP • Conversion of the apex gas injectors to gas producers late in project life • Rig workovers to keep healthy well stock until the end of the project • Perforations to add gas production to the project • 30 year total project life As noted earlier, the gas reference case shows PBMGS will increase ultimate hydrocarbon recovery from the POP by approximately 22 tscf or 3.8 BOE. 3. The PBMGS Full GTP Inlet Supply Case Comparison The full GTP inlet supply case incorporates one change. The annual average gas supply to the GTP is increased from —2.7 bscf/d to a rate of 3.6 bscf/d. (3.6 bscf/d is used because the gross inlet volume of gas will be slightly higher in this modeled case due to the higher COZ content in POP gas compared to the blended gas stream expected from other gas fields.) As noted earlier, the full GTP inlet supply case recovers slightly more BOEs than the gas reference case (17.8 instead of 17.7 billion BOEs) due to higher gas recovery that offsets additional impacts on oil production. 4. Imnacts of Sensitivities The impacts of the sensitivities on gas sales, oil recovery and BOE recovery were evaluated. Apart from in -place volumes, the most sensitive parameters identified are COZ injection location (for enhanced hydrocarbon and pressure maintenance), and well breakage. All of the other sensitivities have less than a 5 percent impact on total BOE recovery, with most sensitivities having a negligible impact (less than 1 percent impact). The impacts on gas production from the sensitivities tested have a greater effect on ultimate BOE recovery than the nominal positive impacts to oil recovery. These results 10 • • Written Submittal of BP Exploration (Alaska) Inc. Application for Amendment of POP CO 341D Rule 9 and AIOs 3A and 4F are discussed in Section V (the Confidential Appendix). SECTION IV MODIFICATION OF AIOS 3A AND 4F INJECTION OF CO2 FROM SOURCES WITHIN OR OUTSIDE OF PBU FOR ENHANCED HYDROCARBON RECOVERY AND PRESSURE MAINTENANCE A. AK LNG CO2 Byproduct Return The AK LNG Project participants (including affiliates of BPXA, EMAP and CPAI, and the State of Alaska) have informed BPXA that gas shipped through the AK LNG system pipelines to the liquefaction facility will need to be treated in the GTP to a CO2 specification of 50 ppm or less. AK LNG Project participants have publicly stated that the GTP is being designed on the basis that the byproduct from gas treated at the GTP, which BPXA expects will be dry and approximately greater than 99 percent CO2, will be transported to the PBU for further handling. See Figure 1 below for a conceptual depiction of a CO2 distribution system. Conceptual CO2 receipt Coe Control Module and distribution system CGF ....ti 0 5 miles CO2 f.�] from GTP APEX PL 1 m4esi GC-2 GC-1 ..... mres GC3 VliP c 4YP V. Figure 1 CO2 Distribution System B. Amendment of AIOs The AK LNG Project participants inform us that the GTP may deliver an annual average of 350 to 450 mmscf/d of CO2 byproduct to PBU for injection. Greater than 90 percent of the total CO2 volume will originate from gas delivered from PBU. AIOs 3A and 4F, however, currently only permit injection of gas (which includes the CO2 entrained in the gas) that is sourced from PBU gas processing facilities. The additional hydrocarbon recovery associated with PBMGS is 3.8 billion BOE. This 11 Written Submittal of BPOploration (Alaska) Inc. • Application for Amendment of POP CO 341 D Rule 9 and AIOs 3A and 4F additional hydrocarbon recovery is dependent upon the ability of PBU to receive CO2 from the GTP. Although the specific location for injection is still being evaluated, analysis of CO2 injection in POP shows there will be enhanced hydrocarbon recovery and pressure maintenance benefits. BPXA is therefore seeking a modification of AIOs 3A and 4F to authorize the injection Of CO2 into the POP for enhanced hydrocarbon recovery and reservoir pressure maintenance purposes, from sources both within and outside the PBU. Similar to the requested amendment of Rule 9 addressed above, the requested modifications to the AIOs are requested at this time to support the joint efforts of the State of Alaska and the other AK LNG Project participants to progress the AK LNG Project to the front-end engineering and design (FEED) development stage. Amendment of the AIOs at this time will also allow the PBU WIOs to pursue related PBU activities supporting this injection of GTP CO2. C. Assessment of CO2 Injection Various locations within the POP were evaluated to determine the hydrocarbon recovery associated with injection of CO2. These areas included the Gas Cap, Flow Station 2 area and Eileen West End. In past evaluations of PBMGS, the gas cap was considered as an option. Lower CO2 handling limits into the GTP and the rapid increase in CO2 from the POP that would occur demonstrates that this location is a less viable option given the impact on hydrocarbon recovery. The Flow Station 2 area was also evaluated and this area remains a potential location due to the availability of the miscible injection distribution system. Compared to the more promising Eileen West End location, the FS2 area was also determined to have higher returned CO2 concentrations and lower hydrocarbon recovery. Eileen West End provided the highest benefit from a hydrocarbon recovery perspective when compared to the other injection locations. Due to the large volume of CO2 that is currently injected into the POP through day to day operations as part of the overall gas reinjection stream (about 800 mscf/d), the volume of CO2 injected during PBMGS is essentially the same. The benefits of this injection are associated with increased pressure to the reservoir, thus improving oil recovery throughout the field and recovery of Miscible Injectant ("MT') currently trapped in the EWE area of the field. This MI can be utilized for additional FOR benefits. 12 Written Submittal of BP*Ioration (Alaska) Inc. Application for Amendment of POP CO 341 D Rule 9 and AIOs 3A and 4F HEW BPXA requests that the Commission authorize and recognize this submission as pre -filed written public testimony in support of its application. Based upon my expertise, knowledge, information and belief formed after reasonable inquiry, I certify and swear that the statements and information in Sections II through V of this submittal, including in the Confidential Appendix to this submittal, are true and accurate. Bruce Laughlin BP Exploration (Alaska), Inc. 13 0 0 E ConocoPhillips Alaska August 19, 2015 Catherine P. Foerster, Commission Chair Alaska Oil and Gas Conservation Commission 333 W. 7th Ave #100 Anchorage, Alaska, 99501-3539 RECEIVED AUG 19 2015 .AOGCC Jon Schultz Manager Greater Prudhoe Area P.O. Box 100360 Anchorage, AK 99510-0360 Phone: 907-265-1315 RE: Docket Numbers: AIO 15-032, AIO 15-033, CO 15-09 — Prudhoe Bay Unit ConocoPhillips Comments to BP Exploration (Alaska) Inc. (BPXA) and ExxonMobil Alaska Production, Inc. (EMAP) July 17, 2015 Consolidated Application for Amendment of Prudhoe Oil Pool Rule 9 and Modification of Prudhoe Bay Unit Area Injection Orders AIO 3A and AIO 4F Dear Commissioner Foerster, ConocoPhillips Alaska, Inc. (CPAI) submits, on behalf of itself and Chevron U.S.A. Inc. (CUSA), both Prudhoe Bay Unit (PBU) working interest owners, the following comments to the above -referenced application (BPXA and EMAP Consolidation Application), and respectfully requests that the Alaska Oil and Gas Conservation Commission (Commission): (i) Approve BPXA's and EMAP's request to increase the Rule 9 maximum allowable gas offtake rate, but to a maximum offtake rate of 3.6 billion standard cubic feet per day (bscf/d) annual average, rather than the 4.1 bscf/d annual average requested by BPXA and EMAP; (ii) Approve BPXA's and EMAP's request to modify relevant area injection orders to permit injection of carbon dioxide (CO2) and other gas treatment byproducts for purposes of enhanced oil recovery (EOR) and pressure maintenance; and, in addition to BPXA's and EMAP's request, also approve injection of CO2 and other gas treatment byproducts for disposal in appropriate intervals, in the event that FOR or pressure maintenance opportunities that result in increased POP hydrocarbon recovery are not identified; and (iii) Include in Rule 9 and relevant area injection orders provisions, as necessary, to permit administrative approval of future modifications. CPAI Comments to BPXA ana"EMAP Consolidated Application to Amendtle 9 and Modify AIOs Page 2 of 6 August 19, 2015 A. CPAI Supports BPXA's and EMAP's Request to Increase the Rule 9 Maximum Allowable Offtake Rate, But Requests the Commission Approve a Rate — 3.6 bscf/d — Commensurate With the AKLNG Design Basis and Reasonably Expected Gas Volume Needs As the Commission is aware, CPAI has been working closely with the other PBU working interest owners (WIOs), to support a request to the Commission to increase the current 2.7 bscf/d annual average Rule 9 maximum gas offtake rate for the Prudhoe Oil Pool (POP), as an important part of making possible potential major gas sales from PBU through the Alaska LNG Project (AKLNG). Affiliates of BPXA, EMAP and CPAI, together with agents of the State of Alaska, have advanced AKLNG pre -FEED engineering, and AKLNG is expected to enter FEED' next year. Increasing the Rule 9 maximum annual average offtake rate will provide additional certainty to support an AKLNG FEED decision, as well as subsequent decisions to construct and operate AKLNG. In this regard, CPAI always has supported, and continues to support, requesting that the Commission increase the Rule 9 maximum allowable POP offtake rate. As the Commission likely is aware, until June, CPAI supported considering an increase to the maximum annual average POP offtake to 4.1 bscf/d, where that daily rate would be available if the PBU WIOs determined to supply additional gas to the AKLNG gas treatment plant (GTP), in the event of a temporary non -POP gas supply disruption. As explained below, after further consideration, CPAI has determined that 3.6 bscf/d annual average POP offtake is more than sufficient to accommodate full AKLNG GTP supply from the POP for the full duration of any reasonably expected non -POP gas supply disruption. Accordingly, CPAI requests that the Commission approve 3.6 bscf/d as the Rule 9 maximum allowable annual average POP offtake rate. 1. Governor Walker's June 8 Letter Defined Reasonable Expectations For the Duration of Non -POP Gas Supply Disruption On June 8, Governor Walker sent a letter to BPXA, EMAP and CPAI. The Governor shared the June 8 letter with the Alaska Legislature on June 15.2 The Governor's letter provided helpful clarity regarding necessary gas supply terms to support AKLNG, including the duration of potential non -POP gas supply disruption. Appendix A of the Governor's June 8 letter lays out a preferred commercial structure comprised of two joint ventures: one receiving PBU gas and one receiving PTU gas (PTU being the non -POP gas supply source to AKLNG), and treating, transporting and liquefying the gas through AKLNG capacity reserved for each source of supply. Appendix A notes that the Prudhoe Bay joint venture and the Point Thomson joint venture may enter into certain mutual aid arrangements: one month of mutual aid per year, in case of downtime caused by operational issues; and two months of mutual aid on a one-time basis, in case of severe disruption. This proposal from the Governor defined reasonable expectations regarding maximum durations over which 100% POP offtake rate could be required: at most, one month on an annual basis; at most, two additional months, in case of once -in -field -life emergency. These maximum durations are conservative, safe assumptions, well in excess of typical industry or North Slope downtimes. So far as CPAI is aware, no major North Slope field ever has experienced an operational issue that caused the field to be entirely offline for three months. The longest major shutdown of which ' Front -End Engineering and Design (FEED) is the final engineering phase before AKLNG sanction, or final investment decision (FID). The AKLNG parties are expected to determine whether to enter FEED in 2016, and to determine whether to approve FID in 2019. 2 The Governor's June 15 and June 8 letters are Attachment 1 to these comments. CPAI Comments to BPXA ancTEMAP Consolidated Application to Amend Kule 9 and Modify AIOs Page 3 of 6 August 19, 2015 CPAI is aware occurred in October 2006 when approximately 30% of PBU production was shut in for 82 days, due to transit line issues. 2. 3.6 bscf/d Is the Appropriate Maximum POP Offtake Rate At This Time Taking into account the AKLNG design basis, premised POP and non -POP AKLNG supply, reasonable expectations regarding PTU downtime, minimization of PBU liquid impacts, and the basic premise that 4.1 bscf/d could be used as an excursion rate, available if the PBU WIOs determined to supply additional gas to the AKLNG GTP, in case of a temporary non -POP gas supply disruption, 3.6 bscf/d is the appropriate maximum annual average POP offtake rate at this time. 3.6 bscf/d annual average maximum offtake provides more than sufficient capacity, even in case of a worst - case 3 month period of 100% PTU downtime in a single year. In fact, a maximum annual average offtake of 3.6 bscf/d would allow for the PBU WIOs to supply 100% of AKLNG GTP inlet volume for approximately 4 months in one year .3 3. 3.6 bscf/d Annual Average Offtake Is More Than Sufficient for AKLNG AKLNG FEED is estimated to cost approximately $2 billion. Accordingly, the decision to enter FEED will require certainty on many issues to support such a large commitment. The current shared goal of BPXA, EMAP and CPAI is to secure an increase to the current Rule 9 maximum allowable offtake rate from the POP, to provide certainty regarding available POP gas, which would be a key factor supporting a 2016 AKLNG FEED decision, as well as subsequent decisions to build and operate AKLNG. A 3.6 bscf/d annual average rate would provide more than sufficient certainty regarding POP gas availability, based on reasonable expectations of maximum PTU downtime in any year. 4. The Commission Should Defer Consideration of an Offtake Rate Higher Than the 3.6 bscf/d Annual Average Rate Required for AKLNG The 3.6 bscf/d annual average POP offtake rate will be more than sufficient to supply AKLNG. However, if AKLNG does not proceed, and if another gas commercialization project is later developed, with different gas sources, or a different basis of design, then it would be appropriate for the Commission to reevaluate POP offtake in light of that new technical information, and then -current POP reservoir and other information. 5. PTU Is Premised to Provide 25% of the Gas to AKLNG; However, If PTU Start Up Is Materially Delayed or PTU Resources Are Materially Less Than Predicted, There Will Be More Than Sufficient Time to Amend the POP Offtake Rate, If Appropriate BPXA's and EMAP's application states that additional POP rate may be required "during startup of, or after gas production begins to decline from, other fields".4 CPAI does not entirely understand this statement. It may suggest that BPXA and EMAP perceive a real risk that PTU start-up will be materially delayed, after AKLNG start-up currently premised in 2025. CPAI also is a PTU owner, and is not aware of such a risk, especially in light of the extent of work that will have been completed by next year for IPS. As far as CPAI is aware, excepting TAPS, no North Slope project similar to (or larger than) PTU gas expansion has been delayed more than 3 months. Further, given the complexity and scope of AKLNG (currently estimated to 3 CPAI's requested 3.6 bscf/d POP maximum annual average offtake rate is comprised of 2.7 bscf/d normal AKLNG GTP supply, 0.6 bscf/d for fuel gas, other field operations, and minor North Slope sales, plus 0.3 bscf/d to allow for the POP to supply 100% of AKLNG GTP inlet volume for up to four months in one year. In this regard, if POP offtake occurred at 4.1 bscf/d for 4 months, and at 3.3 bscf/d for 8 months, then the annual average offtake rate would be approximately 3.6 bscf/d. 4 BPXA and EMAP Consolidated Application, at 4. CPAI Comments to BPXA JAMAP Consolidated Application to Amend Rule 9 and Modify AIOs Page 4 of 6 August 19, 2015 cost $45-$65 billion), it is much more likely that AKLNG — not PTU — would be the source of any material start-up delay. However, if AKLNG did start-up in 2025, and if PTU start-up were materially delayed after AKLNG start up, and the PBU WIOs wished to supply the AKLNG GTP during the period of PTU delay, CPAI anticipates the Commission could timely consider a short term increase to the Rule 9 offtake rate at that time. As construction progress will be closely tracked against critical path schedules, the PBU WIOs would know likely at least one year in advance if PTU start up would be delayed more than four months.5 In any event, given the low likelihood of material PTU delay — a successful AKLNG project is premised on simultaneous start-up of all project and related upstream systems — there is no need for the Commission to grant a POP annual average offtake rate higher than 3.6 bscf/d at this time. The same is true if, in relation to BPXA's and EMAP's statement that additional POP supply may be required "after gas production begins to decline from ... other fields".6 This statement appears to suggest that if PTU declines much faster than expected, supply from the POP will be needed to cover the difference. As far as CPAI is aware, this is unlikely. The PTU operator has provided very high quality information validating PTU resources. The IPS Project will provide additional validation. CPAI expects there will be a low likelihood that PTU will decline much faster than anticipated. However, in the unlikely event that PTU declines much faster than expected, and the PBU WIOs wished to supply additional gas from the POP, there would be sufficient time to request an appropriate Rule 9 increase.' AKLNG start-up currently is premised to occur in 2025. Accelerated PTU decline, if it were to occur, would occur many years after 2025 start-up. In sum, material PTU delay and materially accelerated PTU decline are both unlikely events. If either ever occurred, a PBU offtake increase could be timely considered by the PBU WIOs and the Commission, if appropriate, at that time. B. CPAI Supports BPXA's and EMAP's Request to Allow GTP Byproduct Injection for FOR and Pressure Maintenance, But Further Requests That the Commission Allow Disposal of GTP Byproducts in Appropriate Intervals Through Class II Wells CPAI supports BPXA's and EMAP's request to inject GTP byproducts, principally comprising CO2, into appropriate intervals within the PBU, for FOR and pressure maintenance. However, CPAI notes that the benefit BPXA and EMAP identify in connection with such injection — approximately 3.8 billion barrels of oil equivalent — is the total gas recovery associated with major gas sales into AKLNG.6 This additional recovery is very material, but it is not an FOR benefit. BPXA and EMAP have not identified actual FOR benefits in their application.9 However, AKLNG start up is premised to occur in 2025, so there are many years in which to investigate additional FOR opportunities. In this regard, CPAI requests that the Commission grant BPXA's and EMAP's 5 Further, unless AKLNG start up is to occur on the first of a calendar year, a 3.6 bscf/d maximum offtake rate would allow offtake from the POP at 4.1 bscf/d for longer than four months in that year (as the daily rates are averaged over the entire calendar year), which would afford additional flexibility. 6 BPXA and EMAP Consolidated Application, at 4. CPAI requests that the Commission include, as necessary, provisions in Rule 9 and relevant area injection orders to permit administrative approval of future modifications. 8 BPXA and EMAP Consolidated Application, at 5. 9 The Consolidated Application does not identify "an expected increase in incremental hydrocarbon recovery" from CO2 injection. 20 AAC 25.402(c)(14). • • CPAI Comments to BPXA and EMAP Consolidated Application to Amend Rule 9 and Modify AIOs Page 5 of 6 August 19, 2015 request to approve GTP byproduct injection for FOR and pressure maintenance, in anticipation that there may be FOR opportunities later identified. However, in the event that FOR opportunities are not later identified, CPAI also requests that the Commission approve disposal of GTP byproduct in appropriate intervals in Class II PBU wells.10 C. Supporting Information CPAI will have appropriate experts available at the public hearing to testify regarding these comments. Depending on the testimony presented by others, CPAI reserves the right to present additional testimony at the public hearing, or by post -hearing submission, if so authorized by the Commission. D. Conclusion Based on the above comments, CPAI respectfully requests that the Commission: (1) Approve BPXA's and EMAP's request to increase the Rule 9 maximum allowable offtake rate, but to a maximum offtake rate of 3.6 bscf/d annual average, rather than the 4.1 bscf/d annual average requested by BPXA and EMAP; (1I) Approve BPXA's and EMAP's request to modify relevant area injection orders to permit injection of CO2 and other gas treatment byproducts for purposes of FOR and pressure maintenance; and, in addition, also approve injection of CO2 and other gas treatment byproducts for disposal in appropriate PBU Intervals, in the event that FOR or pressure maintenance opportunities that result in increased POP hydrocarbon recovery are not identified; and (III) Include in Rule 9 and relevant area injection orders provisions, as necessary, to permit administrative approval of future modifications. Please contact Eric Reinbold at 907-263-4465 if the Commissioners or Commission staff have any questions regarding these comments. Please direct communications regarding procedural matters, including the public hearing, to John Evans, counsel for CPAI, at 907-265-6329. Sincerely, , Greater Prudhoe Area i, Inc. Concurring for Chevrq .S.A.Inc. J.M. WoliVer, NOJV Manager Chevron North America Exploration and Production Company, a division of Chevron U.S.A. Inc. 10 CPAI recognizes that the Commission will need additional information under 20 AAC 25.252 to approve a disposal request; however, this information can be readily provided by the PBU operator. Relevant to 20 AAC 25.252(c), as noted in BPXA's and EMAP's Consolidated Application, there is no risk of movement of fluids into sources of freshwater or underground drinking water. BPXA and EMAP Consolidated Application at 6. CPAI Comments to BPXA an*MAP Consolidated Application to Amend mule 9 and Modify AIOs Page 6 of 6 August 19, 2015 Attachment 1 — June 15 and June 8 Letters from the Governor of the State of Alaska cc via email. - Gilbert Wong, EMAP (gilbert.wong(nexxonmobil. com) Steve Luna, EMAP(charles.s.luna(@exxonmobil. com) Phil Ayer, CUSA (pmayer(a)-chevron.com) Angie Bible, CUSA (abible(o)_chevron.com) John Dittrich, BPXA (John. Dittrich(a-)-bp.com) George Lyle, Guess & Rudd (glyle(aD-guessrudd.com) Chris Wyatt, BPXA (Chris.Wyatt(a-)bp.com) Eric Reinbold, CPAI (Eric.W.Rein bold Co.conocophill ips.com) John Evans, CPAI (John.R.Evans(aD-conocophillips.com) 0 • Attachment 1 June 15 and June 8 Letters from the Governor of the State of Alaska See attached. STATE CAPITOL r 4 •!� P.O. Box 110001 Juneau, AK 9981 1-0001 907-465-3500 fax: 907-465-3532 Governor Bill Walker STATE OFALASKA June 15, 2015 The Honorable Kathy Giessel Alaska State Senate 716 W. 4th Ave. Suite 511 Anchorage AK, 99501 The Honorable Benjamin Nageak Alaska State House of Representatives State Capitol Room 126 Juneau AK, 99801 The Honorable Dave Talerico Alaska State House of Representatives 1292 Sadler Way Suite 328 Fairbanks AK, 99701 Dear Senate and House Resource Committee Chairs and Co -Chairs: 550 West Seventh Avenue, Suite 1700 Anchorage, AK 99501 907-269-7450 fax 907-269-7461 www.Gov.Alaska.Gov Governor@Alaska.Gov I want to inform you about the efforts of my administration to move the AK LNG project ahead. Attached is my letter dated June 8, 2015 to the heads of the producers' negotiating teams for the AK LNG project. We have identified a lack of urgency in the parties' resolution process. The methodology that the AK LNG team adopted for identifying problems and issues is excellent. However, there does not appear to be much process associated with resolving issues between the parties, and certainly not one with a sense of time urgency. It is time to build this gas pipeline to Nikiski, and therefore the state needs to take the lead and proactively mediate and find resolutions within a time frame that will keep the project on schedule. The attached letter proposes a time frame and process for moving the issues to resolution. To date, the producers have been working towards a 2"a quarter-2016 FEED decision. This meshes efficiently with a fall special session for legislative review of the proposed agreements. It also works well should voter consideration of a November 2016 constitutional amendment be required in addressing the fiscal certainty needs of the project. For these reasons, schedules should not be allowed to slide. Assuming that all the producers match the State's commitment to commercialize North Slope gas, we must push ourselves to close out these issues. The attached letter identifies the key issues requiring resolution and the state's position on those issues. My hope is that with clarity of focus and attention, the producers and the state can stay the course on their intended timeline and give Alaskans a gas pipeline project from the North Slope to Nikiski that will provide the next generation the revenues they need to build a prosperous future. Sincerely, • ill Walker Governor cc: Janet Weiss Dave VanTuyl Joe Marushack Pat Flood Bill McMahon Jim Flood • STATE CAPITOL 110 Box 110001 Juneau. AK 9981 1-0001 907-465-3500 far: 907-465-3532 June 8, 2015 Janet Weiss & Dave VanTyie BP Exploration Alaska, Inc. 900 E. Benson Blvd. Anchorage, AK 99508 Joe Marushack & Pat Flood ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 E V�{ Z4 Governor Bill Walker STATE OF ALASKA Bill McMahon & Jim Flood ExxonMobil Development Company Wellness 2, 5A.345 22777 Springwoods Village Parkway Spring, Texas 77389 Dear AK LNG Sponsors: S50 West, Seventh Avenue, Suite 1700 Anchorage. AK 99501 907-269 7450 fax 907-269-7461 www.Gov.Alaski.Gov Governor@Alaska.Gov A few weeks ago, we jointly set a goal to finalize the term sheets for all major project cnabling contracts by the middle of June. It is now June 8th. Despite the efforts of all parties, it is clear we are not on schedule to achieve this goal. There are at least two major issues and at least three smaller major issues. I have summarized the State's listing of those issues along with my comments. I am asking that this list be considered by the VAMOU on Tuesday to determine if consensus can be reached on the completeness of the list. The goal would be to gain agreement on a final list of major issues in order for our respective negotiating teams to share a common focus and issue prioritization. The resulting list would then be presented at the Sponsor Meeting on Wednesday with the Sponsor representatives tasked to resolve these major issues — especially the two large major issues. Resolution of these major sticking points will be a catalytic event enabling substantial progress on finalizing the terms of the project contracts. To the extent there are issues remaining after the Sponsor Meeting where the parties are substantially apart, I would like the State to engage in a shuttle diplomatic effort with producers, with a goal of gaining issue closure or at least a clear understanding of the extent of remaining disagreement. Following the best efforts of our teams to reach closure on the major issues, I 0 • would like to meet face to face during the week of June 15th with each Sponsor executive individually to attempt to resolve the remaining issues. I would like to resolve the major issues in these meetings so we can begin the process of drafting contracts The AK LNG team will be briefing the Legislature on the 161h of June in Kenai, Alaska. After months of expectation, the people of Alaska and their elected representatives are anxious for concrete progress. Large Major Issues 1. The largest issue is Joint Venture Marketing vs. Equity Marketing, The State believes it will be very difficult, if not impossible, for this project to proceed with the PBU and PTU fields with all the current participants outside a Joint Venture Marketing context. 2. Upstream issues — to the extent they are not resolved by Joint Venture Marketing. Most of the remaining upstream issues can be resolved through the use of separate Joint Ventures that would receive the gas from the PBU and PTU fields with support between the two Joint Ventures along the lines of the proposal attached as Appendix A. Other Major Issues 3. Fiscal Stability: It will only deal with the gas dedicated to this Project from PBU and PTU. It will not include oil. The State is willing to consider a 25 year term in order to facilitate integrated project financing. The State believes a Constitutional Amendment will provide the certainty that all parties would like. Attached as Exhibit B is an example of what I envision the constitutional amendment might look like. 4. 48 inch line: Constructing a 48 inch line will alleviate the issues of open access and expansion. The Producers have stated they do not need or want a 48 inch line. The State is willing to pay for this expansion subject to legislative approval, but it would own all the benefits of the increased size. The State would also pay for installing the valves, pads etc. to accommodate four more compressor stations that will be added when demand exists from new developments or fields. The State intends to use this expansion capacity to encourage open access. 5. East vs. West Cook Inlet crossing: It is my understanding that the studies for the two routes are under way but that the tentative conclusion at this point in time is that the Western Route is the preferred alternative. The Matsu Valley constitutes the second largest population base in the State of Alaska and has some of the highest industrial potential in the State. Consequently, the State strongly prefers the Eastern Route since the studies to date do not indicate any insurmountable obstacles. Also, the Eastern Route will better enable this Project to better fulfill the statutory domestic gas mandate. 0 • Sincerely, Bill Walker Governor Enclosure Appendix A — Joint Venture Marketing Model Appendix B — Sample Draft Constitutional Amendment cc: Dona Keppers, SOA, Deputy Commissioner of Revenue Dan Fauske, AGDC Steve Wright, SOA, Department of Natural Resources Audie P. Setters, SOA, Gas Team, General Manager 0 • =, V C7�„ Z C7 v� m J c v L u N Y l7 7 Z �+- L -0 > O O on a - *' Q C g C L t -1 m CL 3 t E 3 fII a m > Q- UJ c E cu ai m y Q +� c E +� L.+' s Z � ou ou M z a u m m m U am a O GJ H O Q 0 Q C O -P 7 O w Q VI LL _N CL Q) U u cv C m r_ m s X _N cQ C O u H VI J C O CL 0) -E C CL o a, '^ vE CL C m O 0 4-0 L C Q m _ > U 4-0 a1 L O L m f+ Q C aj O L O -P O +•+ Q O i C L � L � 4-0 C L 4 v a� O O m 4-1 O O � a- ° Y en 0 Y a 4� CL ro a � C C N 3 fO L L O y,i 4 O O t ) L "C N +5 U tC0Gm3 E L O �O Q O C U a w m L Q OL N C Q �- o _ 7 � U +�+ O m C C C aj Qa) OU C N> ->-� > U H Q H Q� E CS O LM r sr.. O L U1 C CO `m C N OL X N 'O O Q m Q- 00 h0 v 'L L a+ L O O. c O m i c O m —v u1 ` w O L Q u CD v 00 U. QJ m L O x }r 00 LU C • O • • O u v a Q. 0 C7 Z J Y Q O a m m C O 4-0 4-0 L O L H C G1 O C O LA .j O L a N m ftS t 4- 0 O O 0 • 9 APPENDIX B Sample Draft Constitutional Amendment * Section 1. Article IX, Constitution of the State of Alaska, is amended by adding a new section to read: Section 18. Suspension of Taxation by Contract Authorized by Law. Contracts approved by a majority of the legislature and entered into by the executive branch by December 31, 2017 to provide fiscal terms for a liquefied natural gas project, including a gas treatment plant, gas pipelines, and a liquefied natural gas plant and related facilities, as provided by law are constitutional under this article. Such contracts as originally executed shall be binding upon future legislatures as to terms of gas taxation, but any amendments to such contracts executed between the parties shall not bind future legislatures as to any aspect of taxation. 0 0 REVISED Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Re: Docket Numbers: AIO 15-032, AIO 15-033, and CO 15-09 Prudhoe Bay Unit Requested Modifications BP Exploration (Alaska) Inc., by letters dated July 17, 2015, requests the Alaska Oil and Gas Conservation Commission (AOGCC) modify Area Injection Orders 3A & 4F, and Conservation Order 341D authorize the injection of CO2 for enhanced recovery purposes and to increase the allowable gas offtake rate for the Prudhoe Oil Pool. The AOGCC previously scheduled a public hearing on this application for August 27, 2015 at 9:00 a.m. at 333 West 7th Avenue. By this revised noticed, the site of the public hearing is changed to 716 West 41h Avenue, Anchorage, Alaska 99501. Written comments regarding this application may be submitted to the AOGCC, at 333 West 71h Avenue, Anchorage, Alaska 99501. Comments must be received no later than the conclusion of the August 27, 2015 hearing. If you would like to attend the above Public Hearing but are unable to do so in person, the call in number is 1-844-586-9085 or you can watch live at akl.tv. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact the AOGCC's Special Assistant, Jody Colombie, at 793-1221, no later than August 20, 2015. P Cathy P. oerster Chair, Commissioner STATE OF ALASKA ADVERTISING ORDER NOTICE TO PUBLISHER SUBMIT INVOICE SHOWING ADVERTISING ORDER NO., CERTIFIED AFFIDAVIT OF PUBLICATION WITH ATTACHED COPY OFADVERTSMINL ADVERTISING ORDER NUMBER AO-16-004 FROM: Alaska Oil and Gas Conservation Commission AGENCY CONTACT: Jody Colombie/Samantha Carlisle DATE OF A.O. 07/23/15 AGENCY PHONE: 1(907) 793-1221 333 West 7th Avenue Anchorage, Alaska 99501 DATES ADVERTISEMENT REQUIRED: COMPANY CONTACT NAME: PHONE NUMBER: ASAP FAX NUMBER: (907)276-7542 TO PUBLISHER: Alaska Dispatch News SPECIAL INSTRUCTIONS: PO Box 149001 Anchorage, Alaska 99514 TYPE,OFADVI;R'1ISElENT: LEGAL DISPLAY CLASSIFIED OTHER (Specify below) DESCRIPTION PRICE Revised AIO-15-032, AIO-033 and CO-15-09 Initials of who prepared AO: Alaska Non -Taxable 92-600185 &VBiSiIT 1i�tiKoI :sFlovpvc:�t)}tRTISA�?G ' R....jV0........... rU$ e. ... ; !i ................... �riv�Rrfsivic�yr r::: Department of Administration Division of AOGCC 333 West 7th Avenue Anchorage, Alaska 99501 Page 1 of l Total of All Pa es $ REF y....................... T Number Amount Date Comments I PvN ADN84501 2 Ao AO-16-004 3 4 FIN AMOUNT SY CC PGN LGR ACCT FY DIST LIQ I 16 02140100 73451 16 2 3 4 5 Purchas g am)' itle: I tc t thority's Signa ore �_ I � Telephone Number 1. A.O. It a receiving agency name stapp on all invoices and documents reliiing to this purchase. 2. The slat i registered for tax free transactions under Chapter 32, IRS code. Reg ration number 92-73-0006 K. Items are for the exclusive use of the state and not for resale. ID ISTRIBUT1. ................ . >:»> i......:F;scal/Drigiii' I ..:.::::::.::::.. ;0 es::::P.... h .. (..... ....................... S......................................... . `s er:.fa::zed :Division Fisi ......... Form:02-901 Revised: 7/23/2015 270227 is0001368912 $ 194.24 AFFIDAVIT OF PUBLICATION AOGC; C ON STATE OF ALASKA THIRD JUDICIAL DISTRICT Leesa Little 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 July 24, 2015 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 24th day of July, 2015 Notary Public in and for The State of Alaska. Third Division Anchorage, Alaska MY COMMISSION EXPIRES Revised Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Docket Numbers: AIO 15-032, AIO 15-033, and CO 15-09 Prudhoe Bay Unit Requested Modifications BP Exploration (Alaska) Inc., by letters dated July 17, 2015, requests the Alaska Oil and Gas Conservation Commission (AOGCC) modify Area Injection Orders 3A & 4F, and Conservation Order 341D authorize the injection of CO2 for enhanced recovery purposes and to increase the allowable gas offtake rate for the Prudhoe OII Pool. The AOGCC previously scheduled a public hearing on this application for August 27, 2015 at 9:00 a.m. at 333 West 7th Avenue. By this revised noticed, the site of the public hearing is changed to 716 West 4th Avenue, Anchorage, Alaska 99501. 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 the conclusion of the August 27, 2015 hearing. If ywould like to attend the above Public Hearing but are unable to do soou in person, the call in number is 1-844-586-9085 or you can watch live at akl.ty. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact the AOGCC's Special Assistant, Jody Colombie, at 793-1221, no later than August 20, 2015. Cathy P. Foerster Chair, Commissioner AO-16-004 Published: July 24, 2015 Notary Public ERITNEY L, THOMPSON State of Alaska My 001`1111111110n Expires Feb 23, 2019 0 • Singh, Angela K (DOA) From: Colombie, Jody J (DOA) Sent: Thursday, July 23, 2015 2:32 PM To: Ballantine, Tab A (LAW); 'Salena'; Delbridge, Rena E (LAS); glyle@guessrudd.com; AKDCWeIIIntegrityCoordinator, Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew VanderJack, Anna Raff; Barbara F Fullmer; bbritch; Becca Hulme; bbohrer@ap.org; Bob Shavelson; Brian Havelock; Bruce Webb; Burdick, John D (DNR); Carrie Wong; Cliff Posey; Colleen Miller, Crandall, Krissell; D Lawrence; Dave Harbour; David Boelens; David Duffy, David House; David McCaleb; David Steingreaber; David Tetta; Davide Simeone; ddonkel@cfl.rr.com; Dean Gallegos; Delbridge, Rena E (LAS); DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Frank Molli; Gary Oskolkosf; George Pollock; ghammons; Gordon Pospisil; Greg Duggin; Gregg Nady; gspfoff; Jacki Rose; Jdarlington oarlington@gmail.com); Jeanne McPherren; Williams, Jennifer L (LAW); Jerry Hodgden; Jerry McCutcheon; Solnick, Jessica D (LAW); Jim Watt; Jim White; Joe Lastufka; news@radiokenai.com; John Adams; Easton, John R (DNR); Jon Goltz; Juanita Lovett; Judy Stanek; Houle, Julie (DNR); Julie Little; Kari Moriarty; Kazeem Adegbola; Keith Wiles; Kelly Sperback; Gregersen, Laura S (DNR); Leslie Smith; Lisa Parker; Louisiana Cutler, Luke Keller; Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Kremer, Marguerite C (DNR); Mary Cocklan-Vendl; Michael Calkins; Michael Duncan; Michael Moora; Mike Bill; mike@kbbi.org; Mikel Schultz; MJ Loveland; mkm7200; Morones, Mark P (DNR); Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nick W. Glover, Nikki Martin; NSK Problem Well Supv; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Renan Yanish; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Sternicki, Oliver R, Moothart, Steve R (DNR); Suzanne Gibson; sheffield@aoga.org; Tania Ramos; Ted Kramer; Davidson, Temple (DNR); Terence Dalton; Teresa Imm; Terry Templeman; Thor Cutler; Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater, Anne Hillman; Bajsarowicz, Caroline J; Brian Gross; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Don Shaw; Donna Vukich; Eric Lidji; Erik Opstad; Gary Orr; Smith, Graham O (PCO); Greg Mattson; Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Holly Pearen; Hyun, James J (DNR); Jason Bergerson; jill.a.mcleod@conocophillips.com; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Kenneth Luckey; King, Kathleen J (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Matt Gill; Franger, James M (DNR); Morgan, Kirk A (DNR); Pat Galvin; Bettis, Patricia K (DOA); Pete Dickinson; Peter Contreras; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Sarah Baker, Peterson, Shaun (DNR); Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); Todd, Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster; William Hutto; William Van Dyke; Ballantine, Tab A (LAW); Bender, Makana K (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Crisp, John H (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Herrera, Matthew F (DOA); Hill, Johnnie W (DOA); Hunt, Jennifer L (DOA); Jackson, Jasper C (DOA); Jones, Jeffery B (DOA); Kair, Michael N (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, To: A•la K (DOA); Wallace, Chris D (DOA) • Subject: Revised Public Notices Attachments: Revised Notice of Public Hearing, CO-15-08.pdf, Revised Notice of Hearing, Dockets AIO-15-32, AIO-15-33, CO-15-09.pdf Please disregard the Public Notices that I sent earlier, the website information was incorrect. I apologize for any inconvenience this may have caused you. James Gibbs Jack Hakkila Bernie Karl P.O. Box 1597 P.O. Box 190083 K&K Recycling Inc. Soldotna, AK 99669 Anchorage, AK 99519 P.O. Box 58055 Fairbanks, AK 99711 Gordon Severson Penny Vadla George Vaught, Jr. 3201 Westmar Cir. 399 W. Riverview Ave. P.O. Box 13557 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Dave P. Lachance Vice President Richard Wagner Darwin Waldsmith Alaska Reservoir Development P.O. Box 60868 P.O. Box 39309 BP Exploration (Alaska), Inc. Fairbanks, AK 99706 Ninilchik, AK 99639 P.O. Box 196612 Anchorage, AK 99508 Angela K. Singh 6 Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Re: Docket Numbers: AIO 15-032, AIO 15-033, and CO 15-09 Prudhoe Bay Unit Requested Modifications BP Exploration (Alaska) Inc., by letters dated July 17, 2015, requests the Alaska Oil and Gas Conservation Commission (AOGCC) modify Area Injection Orders 3A & 4F, and Conservation Order 341D authorize the injection of CO2 for enhanced recovery purposes and to increase the allowable gas offtake rate for the Prudhoe Oil Pool. The AOGCC has scheduled a public hearing on this application for August 27, 2015 at 9:00 a.m. at 333 West 7`h Avenue, Anchorage, Alaska 99501. Written comments regarding this application may be submitted to the AOGCC, at 333 West 71" Avenue, Anchorage, Alaska 99501. Comments must be received no later than the conclusion of the August 27, 2015 hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact the AOGCC's Special Assistant, Jody Colombie, at 793-1221, no later than August 20, 2015. Cathy P. oerster Chair, Commissioner • STATE OF ALASKA ADVERTISING ORDER NOTICE TO PUBLISHER SUBMIT INVOICE SHOWING ADVERTISING ORDER NO., CERTIFIED AFFIDAVIT OF PUBLICATION WITH ATTACHED COPY OFADVERTISMENT. ADVERTISING ORDERNUNBER AO-16-002 FROM: Alaska Oil and Gas Conservation Commission AGENCY CONTACT: Jody Colombie/Samantha Carlisle DATE OF A.O. 07/20/15 1(907) AGENCY PHONE: 793-1221 333 West 7th Avenue Anchorage, Alaska 99501 DATES ADVERTISEMENT REQUIRED: COMPANY CONTACT NAME: PHONE NUMBER: ASAP FAX NUMBER: (907)276-7542 TO PUBLISHER: Alaska Dispatch News SPECIAL INSTRUCTIONS: PO Box 149001 Anchorage, Alaska 99514 T •I E i+*I s � �i 9' LEGAL i p1SPLAY, 1 CLASSIFIED OTHER (Specify a,,. ruu DESCRIPTION below) PRICE AIO-15-032, AIO-15-033 and CO-15-09 Initials of who prepared AID: Alaska Non -Taxable 92-600185 sgtRDE .N ....> s iowlri ..... [iilsily :O;RDER NO.,: CERTIFIER AFIRDAVIT. OR: : ru>3 ;ieATION ITHATTAi'UED:coP:YOF: A...... SNIENT:YO:.::::::::::::::::: .................................. Department of Administration Division of AOGCC 333 West 7th Avenue Anchorage, Alaska 99501 Page 1 of 1 Total of All Pa es S - REF Type Number Amount Date Comments I PvN ADN84501 2 Ao AO-16-002 3 4 FIN AMOUNT Sy CC PGM LGR ACCT FY DIST LIQ 1 16 02140100 73451 16 2 3 4 urchasi A th i T le: =i.thor* r nature Telephone Number ,,ng agency name must appear on all invoices and docume is relating to this purchase. 1. .0Yncl�.._ 2. Theo is registered for tax free transactions under Chapter 32, IRS code. egistration number 92-73-0006 K. Items are for the exclusive use of the state and not for resale. . js'.. :. .. j ; :::.:.:.:.:...:.:.:.............::: ;....... ::............ :: i:::: is i::......::::::::..........::.....;.;.....;.;.....;.....;..'�.:.,.:.:. D .. TRIB.. T. QN.......... ... . ........................... ............ eceiviri':' 'v' ioir Isca'1 R iscal/Qrig nal AO:: ..::: Coples:: Pu............. . Division F. ..... r fazed DI Is F Form:02-901 Revised: 7/20/2015 270227 RECEIVED 0001368715 • • $ 169.34 JUL 3 0 2015 AOGFID T F PUBLICATION� AF AVI O STATE OF ALASKA THIRD JUDICIAL DISTRICT Leesa Little 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 July 21, 2015 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 21 st day of July, 2015 Notary Public in and for The State of Alaska. Third Division Anchorage, Alaska MY COMMISSION EXPIRES �3��19 Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Re: Docket Numbers: AIO 15-032, AIO 15-033, and CO 15-09 Prudhoe Bay Unit Requested Modifications BP Exploration (Alaska) Inc., by letters dated July 17, 2015, requests the Alaska Oil and Gas Conservation Commission (AOGCC) modify Area Injection Orders 3A & 4F, and Conservation Order 341D authorize the in of CO2 for enhanced recovery purposes and to increase the allowable gas offtake rate for the Prudhoe Oil Pool. The AOGCC has scheduled a public hearing on this application for August 27, 2015 at 9:00 a.m. at 333 West 7th Avenue, Anchorage, Alaska 99501. 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 the conclusion of the August 27, 2015 hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact the AOGCC's Special Assistant, Jody Colombie, at 793-1221, no later than August 20, 2015. AO-16-002 Published: July 21, 2015 Cathy P. Foerster Chair, Commissioner Notary public � BRI S EY L. THOMpSOjy My OOm State of Alaska misslon Expires Feb ?3 2019 • Singh, Angela K (DOA) From: Colombie, Jody 1 (DOA) Sent: Monday, July 20, 2015 1:07 PM To: Ballantine, Tab A (LAW); 'Nathan Hile (nwhcmatrix@hotmail.com)'; 'Salena'; glyle@guessrudd.com; Bender, Makana K (DOA); Bettis, Patricia K (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha 1 (DOA); Colombie, Jody 1 (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Guhl, Meredith D (DOA); Hunt, Jennifer L (DOA); Jackson, Jasper C (DOA); Kair, Michael N (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Wallace, Chris D (DOA); AKDCWellIntegrityCoordinator, Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew Vandedack; Anna Raff; Barbara F Fullmer; bbritch; Becca Hulme; bbohrer@ap.org; Bob Shavelson; Brian Havelock; Bruce Webb; Burdick, John D (DNR); Carrie Wong; Cliff Posey; Colleen Miller, Crandall, Krissell; D Lawrence; Dave Harbour, David Boelens; David Duffy; David House; David McCaleb; David Steingreaber; David Tetta; Davide Simeone; ddonkel@cfl.rr.com; Dean Gallegos; Delbridge, Rena E (LAS); DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Frank Molli; Gary Oskolkosf, George Pollock, ghammons; Gordon Pospisil; Greg Duggin; Gregg Nady; gspfoff, Jacki Rose; Jdarlington oarlington@gmail.com); Jeanne McPherren; Williams, Jennifer L (LAW); Jerry Hodgden; Jerry McCutcheon; Solnick, Jessica D (LAW); Jim Watt; Jim White; Joe Lastufka; news@radiokenai.com; John Adams; Easton, John R (DNR); Jon Goltz; Juanita Lovett; Judy Stanek; Houle, Julie (DNR); Julie Little; Kari Moriarty; Kazeem Adegbola; Keith Wiles; Kelly Sperback; Gregersen, Laura S (DNR); Leslie Smith; Lisa Parker, Louisiana Cutler, Luke Keller; Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark. ha nley@anadarko.com); Mark Landt; Mark Wedman; Kremer, Marguerite C (DNR); Mary Cocklan-Vendl; Michael Calkins; Michael Duncan; Michael Moora; Mike Bill; mike@kbbi.org; Mikel Schultz; MJ Loveland; mkm7200; Morones, Mark P (DNR); Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nick W. Glover, Nikki Martin; NSK Problem Well Supv; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Renan Yanish; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly, Sharmaine Copeland; Sharon Yarawsky, Shellenbaum, Diane P (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Sternicki, Oliver R; Moothart, Steve R (DNR); Suzanne Gibson; Sheffield@aoga.org; Tania Ramos; Ted Kramer, Davidson, Temple (DNR); Terence Dalton; Teresa Imm; Terry Templeman; Thor Cutler; Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater, Anne Hillman; Bajsarowicz, Caroline 1; Brian Gross; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Don Shaw; Donna Vukich; Eric Lidji; Erik Opstad; Gary Orr, Smith, Graham O (PCO); Greg Mattson; Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Holly Pearen; Hyun, lames 1 (DNR); Jason Bergerson; jill.a.mcleod@conocophillips.com; Jim Magill; Joe Longo; John Martineck, Josh Kindred; Kenneth Luckey; King, Kathleen J (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Matt Gill; Franger, James M (DNR); Morgan, Kirk A (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Sarah Baker, Peterson, Shaun (DNR); Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); Todd, Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster; William Hutto; William Van Dyke Subject: Public Notice (PBU Requested Modifications) AIO-15-32, AIO-15-033, CO-15-09 Attachments: Notice of Hearing, Dockets AIO-15-32, AIO-15-•CO-15-09.pdf James Gibbs Jack Hakkila Bernie Karl P.O. Box 1597 P.O. Box 190083 K&K Recycling Inc. Soldotna, AK 99669 Anchorage, AK 99519 P.O. Box 58055 Fairbanks, AK 99711 Gordon Severson Penny Vadla George Vaught, Jr. 3201 Westmar Cir. 399 W. Riverview Ave. P.O. Box 13557 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Dave P. Lachance Vice President Richard Wagner Darwin Waldsmith Alaska Reservoir Development P.O. Box 60868 P.O. Box 39309 BP Exploration (Alaska), Inc. Fairbanks, AK 99706 Ninilchik, AK 99639 P.O. Box 196612 Anchorage, AK 99508 �Z�IQ Angela K. Singh by Dave Lachance Vice President Alaska Reservoir Development July 17, 2015 Via Hand Delivery Cathy P. Foerster Commission Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 lut :I' '1 2015 AOGGG BP Exploration (Alaska)Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, AK 99508 USA Direct 907 564 4855 Mobile 907 538 1719 Main 907 564 5111 dave.lachance@bp.com Re: Consolidated Application for Amendment of Prudhoe Oil Pool Rule 9 and Modification of Prudhoe Bay Unit Area Injection Orders AIO 3A and AIO 4F Dear Chair Foerster: BP Exploration (Alaska) Inc., as an individual working interest owner (BPXA) in the Prudhoe Bay Unit (PBO, and not as PBU operator, on behalf of itself and PBU working interest owner ExxonMobil Alaska Production Inc. (EMAP), submits this consolidated application to the Alaska Oil and Gas Conservation Commission (AOGCC) to obtain two related authorizations: (i) Amendment of Rule 9 of Conservation Order (CO) 341 D for the Prudhoe Oil Pool (POP) to authorize an increase in the maximum annual average gas off - take limit from 2.7 billion standard cubic feet per day (bscf/d) to 4.1 bscf/d. (ii) Modification of AIO 3A and AIO 4F (collectively the AIOs) to authorize the injection of COZ for enhanced recovery and pressure maintenance from sources both inside, which is already authorized, and outside the Prudhoe Bay Unit. As related procedural matters, BPXA respectfully requests that, to the full extent allowed by the applicable regulations, the AOGCC: (i) consolidate proceedings pertaining to amendment of Rule 9 and modification of the AIOs because of their interrelated nature; (ii) provide notice of a public hearing on this application tentatively scheduled for on or about August 31, 2015 in accordance with 20 AAC 25.520 and 20 AAC 25.540; (iii) tentatively schedule a pre -hearing conference for on or about August 10, 2015 in accordance with 20 AAC 25.540(f); and • • Application to Amend POP Mule 9 and Modify AIOs July 17, 2015 Page - 2 (iv) allow the submission of pre -filed written testimony in support of the application pursuant to 20 AAC 25.540(c)(12) with the submitting witness(es) to be present at the public hearing to provide sworn testimony and respond to questions of the AOGCC, if any. Please note that the portion of this consolidated application contained in the Confidential Appendix is confidential, and BPXA requests that such information be held confidential pursuant to AS 31.05.035(d), 20 AAC 25.537(b), and AS 45.50.910 et seq. The Confidential Appendix is enclosed in a separate envelope and marked confidential. BPXA respectfully requests that the AOGCC make a decision on the matters addressed in this consolidated application on or before October 15, 2015. I. PRUDHOE OIL POOL RULE 9 AMENDMENT A. POP Maximum Annual Average Gas Off -Take Rate Rule 9, as adopted by the AOGCC in 1977, limits the maximum annual average gas off -take from the POP to 2.7 bscf/d. Approximately 0.6 bscf/d is currently used (and anticipated to continue to be used) for fuel, other field operations and minor local gas sales. Accordingly, under Rule 9, an annual average gas off -take of approximately 2.1 bscf/d would be available for major gas sales. BPXA and the other PBU working interest owners (individually referred to as a WIO and collectively as WIOs) and the AOGCC have long contemplated a major gas sales project involving gas from Prudhoe Bay (PBMGS). In accordance with good oil field engineering practices, at various stages of field development, the PBU WIOs have evaluated the potential effects of a PBMGS on oil production and hydrocarbon recovery from the POP based upon then - existing information and models. Gas production from the POP has been used for extraction of miscible injectant, manufacture of natural gas liquids, pressure maintenance, and enhanced oil recovery. Partly as a result of this POP gas utilization, liquid recovery from the POP has increased from the estimated 9.6 billion barrels in 1977 to over 12.2 billion barrels to date. The AOGCC held a public hearing in June 2007 and issued a report dated July 10, 2007 regarding possible amendment of Rule 9. The AOGCC concluded that no change was necessary to Rule 9 at that time. 1 The PBU WIOs have continued to prepare for a PBMGS and, because of progress by participants in the Alaska LNG Project (AK LNG) and related planning by the PBU 1 Report of the Commission Inquiry Into Amending Rule 9 ("Pool Off -Take Rates"), CO 341 D, For the Prudhoe Oil Pool, Prudhoe Bay Field. • . Application to Amend POP Rule 9 and Modify AIOs July 17, 2015 Page - 3 WIOs for a PBMGS, it is now appropriate for the AOGCC to amend Rule 9 to allow a greater gas off -take rate from the POP.2 B. Gas Off -Take for PBMGS The participants in AK LNG are progressing plans for an integrated LNG project, currently anticipated to start-up in 2025, consisting of a liquefaction facility and associated LNG storage and marine terminal facilities located in the Cook Inlet area, a large diameter gas pipeline approximately 800-miles in length (with gas off -take interconnection points to allow for in -state deliveries) connecting the liquefaction facility to a Gas Treatment Plant (GTP) on the North Slope, transmission lines between the GTP and producing fields, and various other associated facilities and infrastructure.3 On May 28, 2015 the U.S. Department of Energy conditionally granted authorization to AK LNG to export LNG to non -free trade agreement nations.4 The GTP is being designed by AK LNG to receive, treat, and ship gas to the Liquefaction Plant, and to send to the PBU a GTP by-product stream primarily consisting of carbon dioxide (CO2).5 The design of the AK LNG facilities is premised on maintaining an annual average gas supply rate of 3.5 bscf/d to the GTP .6 BPXA and EMAP plan to deliver part of the gas supply into the GTP from PBU (from the POP). C. Request to Increase POP Maximum Annual Average Off -take Rate There are several reasons why an amendment of Rule 9 to increase the maximum annual average gas off -take rate is being requested. Under expected normal operations of the GTP, approximately 75 percent of the gas supply (2.7 bscf/d) will be from the POP with approximately 25 percent of the gas (0.8 bscf/d) supplied from BPXA participated in PBMGS preparations in its capacity as a PBU WIO and facilitated discussions in its capacity as PBU operator. ' See AK LNG Preliminary Resource Report No. 1 at § 1.1, Docket No. PF 14-21-000 (doc. Number: USAKE-PT-SRREG-00-0001) (hereafter referred to as "Resource Report No. 1"), available at: https://elibLM.ferc.gov/idmws/file list.asp?document id=14300991. The AK LNG project is currently undergoing pre -filing review before the Federal Energy Regulatory Commission (FERC) at Docket No. PF 14-21-000. The applicants before FERC for the AK LNG project are the Alaska Gasline Development Corporation, BP Alaska LNG LLC, ConocoPhillips Alaska LNG Company, ExxonMobil Alaska LNG LLC, and TransCanada Alaska Midstream LP. See DOE/FE Order No. 3643 (FE Docket No. 14-96-LNG), available at: http://www.energy.gov/fe/downloads/order-3643-alaska-Ing-project-llc. 5 See Resource Report No. 1 at p.15. ° According to the current design, the GTP will have an annual average inlet gas treating capacity of up to 3.7 bscf/d, excluding planned/unplanned downtime. Id. Assuming 95% operating efficiency, the annual average gas supply requirement for the GTP is 3.5 bscf/d. • • Application to Amend POP Rule 9 and Modify AIOs July 17, 2015 Page - 4 other sources. Under normal operations, total POP gas off -take would occur at an annual average rate of approximately 3.3 bscf/d (2.7 bscf/d to the GTP plus 0.6 bscf/d for existing fuel use and minor local gas sales). The current Rule 9 off -take rate of 2.7 bscf/d is not sufficient to meet the annual average gas off -take from the POP under those circumstances. The Commission has long acknowledged that a change to the gas off -take rate from the POP would be needed to facilitate a major gas sale. In addition to POP gas supply under normal operating conditions, if the supply of gas from other sources is not delivered as expected (or during startup of, or after gas production begins to decline from, other fields), it is possible the POP would need to be the source for up to 100 percent of the gas BPXA and other parties will each need to supply to the GTP to cover gas supply commitments. In such circumstances, the total gas off -take from the POP could be up to 4.1 bscf/d (3.5 bscf/d to the GTP adjusted for the higher CO2 content of POP feed gas in comparison to the expected blended feed stream plus 0.6 bscf/d for existing fuel use and minor local sales). This application to amend Rule 9 requests an increase in the annual average off -take rate to 4.1 bscf/d to accommodate the maximum potential gas off -take from the POP in circumstances when non -POP gas supply to the GTP is not delivered as expected. D. Analysis of Increase in Gas Off -Take Upgrades to the PBU Full Field Model (FFM have been made since the AOGCC last considered POP gas off -take rates in 2007. In addition, model inputs incorporate updated production, drilling, well breakage data, and updated fuel gas algorithms. As a result of increased model resolution, other model refinements, and updated data, a greater degree of confidence in model results has been achieved regarding recovery mechanisms, well productivity, facility processing and compositional detail of oil and gas production. Analyses of the upgraded FFM were performed and presented by the PBU WIOs to AOGCC staff in workshops during April and May of this year. BPXA's assessment of the results is set forth in the Confidential Appendix to this application. BPXA believes that amendment of Rule 9 to allow a maximum annual average gas off -take rate of 4.1 bscf/d for the POP is consistent with good oilfield engineering practices, and appropriate action for the Commission to take. E. Timing for AOGCC Decision Amendment of Rule 9 is being requested at this time in consideration of current actions by the State of Alaska and the AK LNG parties, including BPXA's affiliate BP Alaska LNG LLC and EMAP's affiliate ExxonMobil Alaska LNG LLC, to progress the AK LNG project to the front- end engineering and design (FEED) development stage (which effort involves the expenditure of billions of dollars). To move to the FEED stage of project activity, a number of project -enabling 7 Resource Report No. 1 at 16, 18-19.Current GTP design contemplates that 25% of the supply into the facility will be gas delivered from the Point Thomson Unit. • Application to Amend POP Rule 9 and Modify AIOs July 17, 2015 Page - 5 actions have been identified.$ Amendment of Rule 9 to allow the flexibility to supply both ordinary and full feed gas rates to the GTP from PBU supports those activities. BPXA is requesting that the AOGCC render a decision by October 15, 2015 to facilitate those project - enabling actions. IL MODIFICATION OF AIOS A. Introduction As addressed in Sections I.A-.B above (incorporated into this request by reference), the GTP is being designed to receive, treat and ship gas to the liquefaction facility, and to return CO2 by- product to the PBU for injection. Gas will be received from multiple fields, including the POP at PBU. Similar to the requested amendment of Rule 9 addressed above, the requested modifications to the AIOs are being requested at this time to support the joint efforts of the State of Alaska and the AK LNG parties to progress the Alaska LNG Project to FEED development stage. As more specifically addressed below, modifications of the AIOs are based upon the Alaska LNG project design plan for re -injection of the GTP CO2 by-product into the POP. B. Request to Authorize Injection of CO2 1. Injection of CO2 by-product After treatment of feed gas at the GTP, the Alaska LNG Project design is to return CO2 by- product, which is greater than 99% dry CO2, to the Prudhoe Bay Unit for injection.9 BPXA's assessment is that PBMGS will enable an additional hydrocarbon recovery benefit of approximately 3.8 billion barrels of oil equivalent from the PBU, of which the injection of CO2 in the POP is a key step. BPXA's analysis and assumptions regarding CO2 injection is set forth in the Confidential Appendix to this application. Please refer to the Confidential Appendix for information provided to the Commission in support this application, pursuant to 20 AAC 25.402. 8 See Heads of Agreement for the Alaska LNG Project (Jan. 14, 2014). 9 Resource Report No. 1. • Application to Amend POP Rule 9 and Modify AIOs July 17, 2015 Page - 6 2. Modification of AIOs to authorize injection of GTP CO2 by-product will not allow or increase the risk of movement of fluids into sources of freshwater or underground drinking water Within the PBU, there are no subsurface sources of freshwater. Aquifer Exemption Order 1 states that all portions of aquifers lying directly below the Western Operating and K Pad areas of the Prudhoe Bay Unit are exempted for Class II injection activities. Based on data submitted to AOGCC, Finding 5 of AIO 4 covering the Eastern Operating Area states that "injection into, though, or above a fresh water aquifer or underground source of drinking water will not occur." The AIOs only authorize injection into an authorized injection strata. The orders contain requirements for periodic mechanical integrity testing and monitoring injection wells. Should a lack of injection zone isolation be indicated, the operator must notify the AOGCC and submit a plan of corrective action. The well must be shut-in if freshwater were threatened. As noted earlier in this Application, injection of PBU CO2 into the POP (as part of authorized PBU gas cycling operations) is already allowed by the Commission, and this request simply requests authorization for the injection of incremental CO2 from gas supplied to the GTP from other reservoirs. B. Requested modifications to AIOs BPXA requests, pursuant to 20 AAC 25.410(h), that the Commission approve the following modifications to the referenced Rule in each of the AIOs (requested modifications in bold and underlined text): 1. AREA INJECTION ORDER 3A (PRUDHOE OIL POOL) Rule 1. Authorized Injection Strata and Fluids for Enhanced Recovery Within the affected area and in the strata defined as those strata which correlate with the strata found in ARCO Alaska Inc. (Atlantic -Richfield -Humble) Prudhoe Bay State Well No. 1 between the measured depths of 8110 feet and 8680 feet the following fluids may be injected for purposes of pressure maintenance and enhanced oil recovery: a) Produced water and gas from Prudhoe Bay Unit processing facilities; b) CO2 and other GTP effluent gases from sources within or outside the Prudhoe Bay Unit; Enriched hydrocarbon gas; Non -hazardous water and water based fluids - (specifically seawater, source water, freshwater, domestic wastewater, equipment washwater, sump fluids, hydrotest fluids, firewater, and water with trace chemicals, and other water based fluids with a pH greater than 2 and less than 12.5 and flashpoint greater than 140 degrees F); • • Application to Amend POP Rule 9 and Modify AIOs July 17, 2015 Page - 7 !Le) Fluids introduced to production facilities for the purpose of oil production, plant operations, plant/piping integrity or well maintenance that become entrained in the produced water stream after oil, gas, and water separation in the facility. Specifically: i. Freeze protection fluids; ii. Fluids in mixtures of oil sent for hydrocarbon recycle; iii. Corrosion/scale inhibitor fluids; iv. Anti-foams/emulsion breakers; v. Glycols; vi. Radioactive tracer survey fluids eef Non -hazardous glycols and glycol mixtures; W Fluids that are used for their intended purpose within the oil production process. Specifically: i. Scavengers; ii. Biocides g.h Fluids to monitor or enhance reservoir performance. Specifically: i. Tracer survey fluids; ii. Well stimulation fluids; iii. Reservoir profile modification fluids. 2. AREA INJECTION ORDER 4F (PRUDHOE OIL POOL, PUT RIVER OIL POOL, LISBURNE OIL POOL. PT. MCINTYRE OIL POOL, WEST BEACH OIL POOL, AND STUMP ISLAND OIL POOL) Rule 1 Authorized Injection Strata and Fluids for Enhanced Recovery Within the affected area and the following strata: The Prudhoe Oil Pool strata defined as (i) the accumulations of oil that are common to and that correlate with the accumulations found in the Atlantic Richfield -Humble Prudhoe Bay State No. 1 well between the depths of 8,110 feet and 8,680 feet, and (ii) the accumulation of oil that is common to and correlates with the interval from 9,638 to 9,719 measured feet on the Borehole Compensated Sonic Log, Run 2, dated September 28, 1975, in the Atlantic Richfield -Exxon NGI No. 1 well, and that is in hydraulic communication with the gas cap of the former accumulations in the Sag River Formation. The latter accumulation is found within the following area: Umiat Meridian. T11N R14E: Sections: 1, 2, 11(N/2 and SE/4), 12, 13, 14(E/2), 23(NE/4), 24, 25(N/2); T11N R15E: Sections: 6, 7, 8, 17, 18, 19, 20, 29(N/2), 30(N/2); T12N R14E: Sections 35, 36 The Put River Oil Pool strata are defined as the sandstone reservoirs within the Southern, Central and Western lobes of the Put River Sandstone Member (PRS) of the Kalubik Formation that correlate with the interval 9,638 to 9,719 measured feet on the Borehole Compensated Sonic Log, Run 2--dated September 28, 1975--in the Atlantic Richfield - Exxon NGI No. I well, but excluding the PRS Northern Lobe reservoirs that are in • • Application to Amend POP Rule 9 and Modify AIOs July 17, 2015 Page - 8 pressure communication with the Prudhoe Oil Pool gas cap in the Sag River Formation. The Put River Oil Pool is found within the following area: Umiat Meridian. T11N R14E Sections: 3, 4, 9, 10, 11(SW/4), 14(W/2), 15, 16, 21, 22, 23(W/2 and SE/4), 25(S/2), 26, 27, 28, 33, 34, 35, 36; T11N R15E Sections: 29(S/2), 30(S/2), 31, 32; T10N R14E Sections: 1, 2, 3, 11, 12, 13, 14; T10N R15E Sections: 5, 6, 7, 8, 17, 18 The Lisburne Oil Pool strata correlate with and are common to the formations found in the ARCO Prudhoe Bay State No. 1 well between the measured depths of 8, 790-10,440. The Pt. Mcintyre Oil Pool strata correlate with and are common to the formations found in the Pt. Mcintyre No. 11 well between the measured depths of 9,908- 10,665 feet. The West Beach Oil Pool strata correlate with and are common to the formations found in the West Beach No.4 well between the measured depths of 14,458- 14,781 feet. The Stump Island Oil Pool enhanced recovery plans will be evaluated on a well - by -well basis in conjunction with Pt. Mcintyre Oil Pool development. The following fluids may be injected for pressure maintenance and enhanced recovery purposes: a) Produced water and gas from PBU processing facilities; b) CO., and other GTP effluent gases from sources within or outside the Prudhoe Bay Unit; hc) Enriched hydrocarbon gas; eA) Non -hazardous water and water based fluids -(specifically seawater, source water, freshwater, domestic wastewater, equipment washwater, sump fluids, hydrotest fluids, firewater, and water with trace chemicals, and other water based fluids with a pH greater than 2 and less than 12.5 and flashpoint greater than 140 degrees F); de) Fluids introduced to production facilities for the purpose of oil production, plant operations, plant/piping integrity or well maintenance that become entrained in the produced water stream after oil, gas, and water separation in the facility. Specifically: i. Freeze protection fluids; ii. Fluids in mixtures of oil sent for hydrocarbon recycle; iii. Corrosion/scale inhibitor fluids; iv. Anti-foams/emulsion breakers; v. Glycols 9 9 Application to Amend POP Rule 9 and Modify AIOs July 17, 2015 Page - 9 ef) Non -hazardous glycols and glycol mixtures; €g) Fluids that are used for their intended purpose within the oil production process. Specifically: i. Scavengers; ii. Biocides gh) Fluids to monitor or enhance reservoir performance. Specifically: i. Tracer survey fluids; ii. Well stimulation fluids; iii. Reservoir profile modification fluids. III. SUPPORTING INFORMATION This application provides comprehensive information and support for approval of the requested amendment of Rule 9 maximum annual average gas off -take rate for the POP to 4.1 bscf/d, as well as modification of the AIOs. Mr. Bruce Laughlin, as testifying witness, will be present at, and made available to, the AOGCC for questions at the public hearing with respect to this application. Depending upon the testimony, if any, presented by others at the public hearing, BPXA reserves the right to present additional testimony at the public hearing, or by post -hearing submission if so authorized by the Commission. IV. CONCLUSION Based upon this application, BPXA requests that the AOGCC: (i) amend Rule 9 of CO 341 D to establish a maximum annual average gas off -take rate of 4.1 bscf/d for the POP; and (ii) modify AIO 3A.002 and AIO 4F to authorize injection of CO2 from the PBU and other sources for the purposes of enhanced oil and gas recovery, and pressure maintenance. Please contact John Dittrich at 907-564-5075 if the Commissioners or AOGCC staff have any questions or clarification regarding this application. BPXA is represented in this matter by George Lyle of Guess & Rudd, 510 L Street, Suite 700, Anchorage, AK 99501, 907-793-2222. Please direct communications regarding procedural matters, including the pre -hearing and public hearing, to Mr. Lyle. We sincerely appreciate the time and attention of the Commissioners and the AOGCC staff to this application. Si rely, Dave P. Lachance Vice President, Reservoir Development Attachment cc: George Lyle