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Home My WebLink AboutCO 562 PETROLEUM NEWS · WEEK OF AUGUST 21. 2005 . NORTH SLOPE A9 ConocoPhillips applies for Nanuq pool roles Development drilling at Alpine satellite scheduled for this winter; two pools, Nanuq and Kuparuk, will be produced in late '06 By KRISTEN NELSON Petroleum News Editor-in-Chirf C onocoPhillips Ala:;\\.~, will begin producing oil from an Alpine satel- lite ficld, Nanuq, in the fourth quar- ter of 2006. The company told the Alaska Oil and Gas Conservation Commission in a pool rules application that the field will pro- duce fì"Om both the Nanuq and Kuparuk formations; the commission has sched- uled a hearing for OC!. 4. Chris Alonzo, ConocoPhillips Alaska's western North Slope develop- ment supervisor, said in the company's Aug. II application that construction of infrastructure to support Nanuq produc- tion, which will be from ncw Drill Site CD4, started last winter. First production from the Nanuq facilities is expected in the fourth quarter of 2006, Alonzo said. The shallower of the two oil pools, Nanuq, is in thc Torok formation, and directly overlies a deeper Kuparuk River formation pool. ConocoPhillips said it will implement a miscible water alternat- ing gas project for enhanced recovcry in both oil pools when production begins. The company said it will be applying to the State of Alaska and Arctic Slope Regional Corp. for the formation of Nanuq and Nanuq-Kuparuk participating areas later this year. Development drilling is scheduled to begin at CD4 in October and is expected to end in November 2007. Nanuq sandstone principal reservoir The principal reservoir at Nanuq is the Nanuq sandstone, "an Albian submarine hill system," with secondary production from the Nanuq-Kuparuk sandstone, ConocoPhillips told the commission. Four discovery and appraisal wells (Nalluq No. I, No.2, No.3 and No.5) have been drilled at the field and two of the wells, Nanuq No.3 and No.5, will be used in the development. In addition to production tests from these wells, a hori- zontal well, the CD 1-229, was completed from the Alpine CDI pad and production. tested for several weeks in 200 I, the com- pany said. Two merged 3-D seismic data sets, shot in 1996 and 2003, cover the area. The Nanuq reservoir is a stratigraphic trap; there are no major faults. Original oil and original gas cap gas in place in the Nanuq is part of the Colville River unit and working interest ownership of tIle Nanuq leases is lire same as leases al Alpinp: 78 percent ConocoPhillips Alaska and 22 percent Anadarko Petroleum. development area are estimated at H4 mil- lion to 169 million barrels of oil and zero to 40 billion cubic feet of natural gas. The Nanuq-Kuparuk reservoir is also a stratigraphic trap, with one mapped fÜult at the northern edge of the reservoir which ConocoPhillips said is not expect- ed to affect recovery. Original oil in place in the development area is estimated at 21 million to 36 million barrels. Production tests of the Nanuq interval ranged from gravities of 39 degrees API to 42 degrees API; the Kuparuk interval tested at 40 degrees API. ConocoPhillips said geochemical analysis indicates oils fì'om the Kuparuk and Nanuq reservoirs are elosely related. 0/ ~ ~~. . /ú' 04- ê-<¡ y Horizontal development Nineteen horizontal wells are planned fÜr Nanuq CD4 development, 16 to the Nauuq reservoir (nine producers and seven injectors) and three wells to the Kuparuk reservoir (two producers and one injector). ConocoPhillips said well design at Nanuq will be similar to Alpine, where develop- ment drilling began in 1999 and where 97 horizontal wells had been completed as of June I. The Nauuq oil pool will be drilled with undulating horizontal wells or lip to 7,000 feet; horizontal wells in the Kuparuk oil pool would be horizontal wells with lengths N ~ SCALE IN MILES I I I I 1 1 I , I o 2.5 5 10 February 13.2003 of 4,500 to 6,000 feet. The Nanuq CD4 pad is some four miles south of the main Alpine facilities. A 3.8- mile gravel road will connect a 9.3-acre gravel pad at Nallll4 with the main Alpine faeilities. There will be produced oil, water injection, miscible injectant and gas lift pipelines trom the Alpine production facili- ty to Nanuq; powerlincs will be suspended below the pipeline. Nanuq is part of the Colville River unit and working interest ownership of the Nanu4 leases is the same as leases fit Alpine: n percent ConocoPhillips Alaska and 22 perccnt Anadarko Petroleum. . . . STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage Alaska 99501 Re: THE APPLICATION OF ) Conservation Order No. 562 CONOCOPHILLIPS ALASKA, INC. ) for an order to establish pool rules for ) Colville River Field development ofthe Nanuq Oil Pool, ) Nanuq Oil Pool Colville River Unit, Arctic Slope, ) Colville River Unit Alaska ) December 6,2005 IT APPEARING THAT: 1. By application dated August 11, 2005, ConocoPhillips Alaska, Inc. ("ConocoPhillips") in its capacity as Unit Operator of the Colville River Unit ("CRU") requested an order from the Alaska Oil and Gas Conservation Commission ("Commission") to define the proposed Nanuq Oil Pool within the CRU, and to prescribe rules governing the development and operation ofthe pool. 2. Notice of a public hearing was published in the Anchorage Daily News on August 18,2005. 3. The Commission requested additional information from ConocoPhillips on August 5,2005. Supplemental information was received from ConocoPhillips on August 11,2005 and on September 29,2005. 4. The Commission held a public hearing October 4,2005 at 9:00 AM at the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska. Public comments and questions submitted during and immediately following the hearing have been considered by the Commission and have been incorporated into the record. FINDINGS: 1. Operator: ConocoPhillips is the Operator of the property in the area proposed for development. 2. Development Area: The proposed development area lies within the southern portion of CRU, approximately four miles south of the Alpine Central Facility on the Arctic Slope of Alaska. The Nanuq Oil Pool will be developed from a single, new drill site named CD4. 3. Owners and Landowners: All lands within the proposed development area are leased, lie within the Colville River Unit, and have the same working interest Index Conservation Order 562 Colville River Field, Nanuq Oil Pool 1. August 11, 2005 CPA request for hearing for Proposed Nanuq and Nanuq-Kuparuk Oil Pool, Colville River Field (Confidential portion held) 2. August 18, 2005 Notice of Hearing, affidavit of publication, address and e-mail notifications 3. August 19, 2005 Petroleum News request for a copy of application 4. August 23, 2005 Public request for hearing 5. August 30, 2005 Ken Byrd USGS request for portions of application 6. September 1, 2005 faxed copy of Public request for hearing to Jack Walker 7. --------------------- Various E-mail's 8. October 4, 2005 Transcript of hearing (Confidential testimony held) 9. October 4, 2005 Sign In Sheet for Hearing 10. November 7, 2005 Questions and Answers from hearing 11. November 14, 2006 Applications for the formations of the Nanuq Kuparuk and Nanuq Nanuq Participating Areas 12. February 08, 2007 CPA letter re: Gas Allowables (CO 443A.003, CO 562.001, CO 563.001 & CO 569.001) 13. ---------------------- AOGCC Background Information provided by Dave Roby 14. March 2, 2007 CPA request for Admin Approval CRU CD4 -217 (C0562-02) 15. December 14, 2010 CPA application for MPM Multiphase Metering System (Appendices 3 and 4 of application are held confidential) 16. June 16, 2015 CPA request for administrative approval to waive the monthly production allocation reporting requirement (CO 562.004) Corrected on 8/19/15. 17. February 28, 2018 CPA Request for Administrative Amendment, CRU 18. February 28, 2018 CPA Request to Amend Allowable Gas Offtake Rate, CRU (C0562.005) Conservation Order 562 Conservation Order 562 December 6, 2005 . . Page 2 ownership: 78 percent ConocoPhillips and 22 percent Anadarko Petroleum Company. The affected landowners are Arctic Slope Regional Corporation and the State of Alaska. 4. Delineation History: ConocoPhillips drilled the Nanuk No.1 discovery well in Section 19 of TllN, R5E, Umiat Meridian ("UM") in 1996. The discovery was confirmed by the Nanuk No.2 exploration well that was drilled during 2000. This well flowed oil from the Nanuq reservoir. ConocoPhillips subsequently drilled three additional exploration wells to delineate the accumulation: Nanuq No.3, Nanuq No.5 and CRU CDI-229. Three-dimensional seismic and well data have been used to determine the geologic structure and reservoir distribution. Production tests, conventional cores, sidewall cores, well log data, Repeat Formation Tester ("RFT"), and Modular Formation Dynamics Tester ("MDT") data have been used to establish reservoir properties. 5. Pool Identification: The proposed Nanuq Oil Pool is the accumulation of hydrocarbons common to, and correlating with, the interval between the measured depths of 7,043 feet and 7,223 feet in the Nanuk No.2 exploration well. 6. Stratigraphy/Reservoir Properties: The Nanuq reservoir is Cretaceous-aged, and it was deposited in a basin floor submarine fan system dominated by lobe-sheet deposits that extend across the development area. The reservoir consists of sandstone with interbedded shale layers of varying thickness. Reservoir porosity averages approximately 17 percent, permeability averages about 2.5 millidarcies, and net pay averages 35 feet. An oil-water contact lies at about 6,207 feet true vertical depth subsea ("TVDss"). The highest known oil in the CD4 area lies at 6,104 feet TVDss, and a gas-oil contact is thought to lie at about 6,100 feet TVDss. Original reservoir pressure is 2,740 psia. Crude oil samples obtained during production tests of the reservoir range from 39 to 42 degrees API gravity. Oil viscosity is about 0.5 centipoise, and the solution GOR is approximately 990 standard cubic feet per stock tank barrel ("SCF /STB"). The N anuq reservoir is overlain by interbedded mudstone and siltstone assigned to the Torok Formation, and underlain by mudstone, siltstone and sandstone within the basal Torok, HRZ, Kalubik Shale and the Kuparuk D interval, in descending order. 7. Structure: The Nanuq structure is northwest-trending closure, approximately 2 miles long and 1-1/4 miles wide. No major faults cut this reservoir within the development area. 8. Trap Configuration: Well log and seismic information indicates that the oil in the pool is stratigraphically trapped. Conservation Order 562 December 6, 2005 . . Page 3 9. In-Place and Recoverable Hydrocarbon Volumes: Oil in place, MMSTB Recoverable Oil, MMSTB Gas in place, BSCF 84 - 169 22 - 69 40 The peak production rate is expected to exceed 3,000 barrels per day. 10. Reservoir Development Drilling Plan: Sixteen long-reach, horizontal wells are plarmed from CD4 to develop the Nanuq Oil Pool. Within the reservoir, wellbores will be oriented parallel to each other and spaced approximately 1,500 feet apart. Two or more development and service wells may be arranged end-to- end with "heel-to-toe" distances of less than 500 feet to increase sweep and recovery efficiency. 11. Reservoir Management: ConocoPhillips proposes developing this oil pool as a miscible water-alternating-gas ("MW AG") enhanced oil recovery project. This involves cyclic injection of water and enriched, miscible hydrocarbon gas into the pool. ConocoPhillips plans 16 horizontal wells to develop this oil pool: nine producers and seven injectors. This process will maximize resource recovery by: a. Waterflood which displaces oil and maintains reservoir pressure by injecting water into the reservoir to replace voidage; and b. Water Alternating Gas Injection ("WAG"), which entails injecting enriched gas to mix with and mobilize residual oil followed by slugs of water to sweep the oil and control conformance. To ensure optimal resource recovery, ConocoPhillips proposes to maintain average reservoir pressure above the laboratory-measured, minimum miscibility pressure of 2,400 psia. 12. Reservoir surveillance plans: ConocoPhillips proposes that bottomhole pressure survey requirements be met by conducting stabilized, bottomhole static pressure measurements, pressure fall-off, pressure build-up, multi-rate tests, drill stem tests, or formation tests. ConocoPhillips also proposes to acquire an initial pressure survey in each injection well prior to beginning regular injection operations. The annual bottom hole pressure measurement requirement for this oil pool will be satisfied by conducting at least two bottomhole pressure surveys per year. Pressures will be referenced to 6,150 feet TVDss. ConocoPhillips proposes to report data and results from pressure surveys annually. Further, all data necessary for analysis of each pressure survey will not be submitted, but will be made available to the Commission upon request. 13. Wellbore Construction: ConocoPhillips proposes that wells drilled in the Nanuq Oil Pool have surface casing set at approximately 2,500 feet true vertical depth Conservation Order 562 December 6, 2005 . . Page 4 and cemented to surface. Leak-off tests are planned after drilling no more than 50 feet beyond the surface casing and intermediate casing shoes. Significant hydrocarbon zones encountered in the boreholes outside of the reservoir intervals will be covered with cement. The Nanuq Oil pool will be developed using undulating horizontal wells of lengths of up to 7,000 feet completed with a combination of 4-1/2 inch slotted liner and blank liner tied back to surface with 3-1/2 inch or 4-1/2 inch tubing. ConocoPhillips proposes that all production wells within the Nanuq Oil Pool be equipped with a fail-safe automatic surface safety valve ("SSV") and a surface- controlled sub-surface safety valve ("SSSV"). ConocoPhillips proposes all injection wells be equipped with either a double check valve arrangement or a single check valve combined with an SSV, and that a subsurface-controlled injection valve will satisfy the requirement of a single check valve. SSSV scan only be removed after demonstrating to the Commission that the well is not capable of unassisted flow of hydrocarbons. ConocoPhillips also proposes to conduct pressure testing of the safety valve systems every six months. 14. Waivers: ConocoPhillips requests the Commission grant waivers for: a. Proposed directional wellbore plans: CP AI will provide a plan view well plat, vertical section diagram, close approach data and description of the proposed directional program as required in 20 AAC 25.050(b)(I); and requested waiver of the requirements of 25.050 (b)(2)(A) and (B), which require listing names of operators and providing named operators a copy of the application by certified mail when CP AI is the only operator on the unitized acreage. b. Petrophysical logging programs: allowing a complete petrophysical log suite from below conductor to total depth for one well in lieu of the requirements of 20 AAC 25.071(a). Four exploration wells have been drilled in the vicinity of the CD4 development area, and each of these wells has a complete petrophysical and mud log suite through this pool. c. Well spacing: allowing no restrictions on wellbore spacing to accommodate very small "heel-to-toe" distances between horizontal, line- drive wells that will be arranged end-to-end. 15. Sustained Casing Pressure Rules: The Commission has adopted a series of orders addressing sustained casing pressures for all active wells in Alaska. The wells in the proposed pool will be operated under similar conditions and similar rules are appropriate for this development. 16. Consistency of Operating Rules: To ease administrative burdens and to prevent confusion, the Commission seeks to establish, when appropriate, consistent operating rules for similar reservoirs within the same field. The reservoir characteristics, fluid properties, and development plans for the Nanuq Oil Pool are sufficiently similar to those of the nearby Alpine Oil Pool to warrant Conservation Order 562 December 6, 2005 . . Page 5 consistent operating rules for both pools. CONCLUSIONS: 1. Pool Rules for the development of the Nanuq Oil Pool within the Colville River Field in the Colville River Unit are appropriate at this time. 2. Monitoring of reservoir performance on a regular basis will ensure proper management of the pool. Annual reports and technical review meetings will keep the Commission apprised of reservoir performance and will ensure that future development plans promote greater ultimate recovery. 3. Eliminating the requirements of25.050 (b)(2)(A) and (B) will conform to drilling and completion practices approved for the nearby Alpine Oil Pool and reduce administrative burden. Eliminating these requirements will not affect recovery from the reservoir, promote waste, jeopardize correlative rights, or result in an increased risk of fluid movement into freshwater. 4. Waiver of the requirements of 20 AAC 25.071(a) will conform to drilling and completion practices approved for the nearby Alpine Oil Pool and reduce administrative burden. Well and mud log data acquired in four nearby exploration wells satisfy the intent of this regulation. 5. Eliminating spacing restrictions on wellbores interior to the affected area will allow the operator greater flexibility for placement of wells as the pool is developed, and it will not affect recovery from the reservoir, promote waste, jeopardize correlative rights, or result in an increased risk of fluid movement into freshwater. Correlative rights will be protected if a 500-foot set back is required from external property lines where ownership or landownership changes. NOW, THEREFORE, IT IS ORDERED: The following rules, in addition to statewide requirements under 20 AAC 25 (to the extent not superseded by these rules), apply to the Nanuq Oil Pool within the following affected area: Umiat Meridian Township / Range TI0N, R4E TI0N, R5E TIIN, R4E Sections TIIN, R5E 1,2 3,4,5,6 1, 2, 3, 4, 9, 10, 11, 12, 13, 14, 15, 16, 21, 22, 23, 24, 25, 26,27,28,33,34,35,36 3,4,5,6, 7, 8, 9, 10, 15, 16, 17, 18, 19,20,21,22,27,28, 29,30,31,32,33,34 Conservation Order 562 December 6, 2005 Rule 1 Field and Pool Name . . Page 6 The field is the Colville River Field. Hydrocarbons underlying the affected area and within the herein defined intervals of the Torok Formation constitute the oil reservoir named the Nanuq Oil Pool. Rule 2 Pool Definition The Nanuq Oil Pool is the accumulation of hydrocarbons common to, and correlating with, the interval between the measured depths of 7,043 feet and 7,223 feet in the Nanuk No.2 exploration well. Rule 3 Well Spacine: There shall be no restrictions as to well spacing except that no pay shall be opened in a well closer than 500 feet to an external property line where ownership or landownership changes. Rule 4 Casine: and Cementine: Practices a. After drilling no more than 50 feet below a casing shoe set in the Nanuq Oil Pool, a formation integrity test must be conducted. The test pressure need not exceed a predetermined pressure. b. Casing and completion designs may be approved by the Commission upon application and presentation of data that demonstrate the designs are appropriate and based upon sound engineering principles. c. Production casing cement volumes will be sufficient to place cement a minimum of 500 feet measured depth above the Nanuq interval in all wellbores. d. Permit(s) to drill deviated wells within the Nanuq Oil Pool shall include a plat with a plan view, vertical section, close approach data and a directional program description in lieu ofthe requirements of20 AAC 25.050(b). e. A complete petrophysical log suite acceptable to the Commission is required from below the conductor to TD for at least one well on each drilling pad in lieu of the requirements of 20 AAC 25.071(a). The Commission may, in its discretion, require additional wells on a pad to be logged using a complete petrophysical log suite. Rule 5 Injection Well Completion a. To facilitate wireline access, packers in injection wells may be located more than 200 feet measured depth above the top of the injection zone; however, packers must not be located above the confining zone. In cases where the distance is more than 200 feet, the production casing cement volume should be sufficient to place cement a minimum of 300 feet measured depth above the planned packer depth. b. An approved injection order is required prior to commencement of injection in this pool. Conservation Order 562 December 6, 2005 . . Page 7 Rule 6 Automatic Shut-in Equipment a. All production wells will be equipped with a fail-safe automatic surface safety valve ("SSV") and a surface-controlled subsurface safety valve ("SSSV"). b. Injection wells, including WAG, gas injection and water injection service wells per Form 10-407 wells completion report, must be equipped with either a double check valve arrangement or a single check valve and SSV. A subsurface-controlled injection valve or SSSV satisfies the requirement of a single check valve. c. Safety valve systems must be maintained in good working order at all times and must be tested at six-month intervals or on a schedule prescribed by the Commission. Rule 7 Common Production Facilities and Surface Commin2lin2 a. Production from the Nanuq Oil Pool may be commingled with production from other pools in surface facilities prior to custody transfer. b. The allocation factor for the produced fluids will be based on well tests, daily well allocation and total production as measured in the Colville River Unit Production facilities. c. Each producing well must be tested a minimum of twice per month. d. The Commission may require more frequent or longer tests if the allocation quality deteri orates. e. The operator shall submit a monthly report and electronic file(s) containing daily allocation data and daily test data for agency surveillance and evaluation. f. The operator shall provide the Commission with a well test and allocation review report in conjunction with an annual reservoir surveillance report. Rule 8 Reservoir Pressure Monitorin2: a. A bottom-hole pressure survey shall be taken on each well prior to initial sustained production or injection. b. The Operator shall obtain pressure surveys as needed to effectively manage hydrocarbon recovery processes subject to an annual plan outlined in paragraph (e) of this rule. c. The reservoir pressure datum will be 6,150 feet TVDss for the Nanuq Oil Pool. d. Pressure surveys may consist of stabilized static pressure measurements at bottomhole, pressure fall-off, pressure buildup, multi-rate tests, drill stem tests, and open-hole formation tests or other appropriate technical pressure transient or static tests. e. Data from the surveys required in this rule shall be filed with the Commission by Conservation Order 562 December 6, 2005 . . Page 8 April 1 of the subsequent year to the year in which the surveys are conducted. Along with the survey submittal, the operator will provide a proposed survey plan for the upcoming year. The proposed plan shall be deemed accepted if the operator has not received written correspondence from the Commission within 45 days. f. Reservoir Pressure Report, Form 10-412, shall be utilized for all surveys with attachments for complete additional data. Data submitted shall include, but are not limited to, rate, pressure, depth, fluid gradient, temperature, and other well conditions necessary for complete analysis of each survey being conducted. g. Results and data from special reservoir pressure monitoring tests or surveys shall also be submitted in accordance with paragraph (e) of this rule. Rule 9 Gas-Oil Ratio Exemption Wells producing from the Nanuq Oil Pool are exempt from the gas-oil-ratio limits of 20 AAC 25.240(b) so long as the provisions of20 AAC 25.240(c) apply. Rule 10 Annual Reservoir Review An annual report must be filed on or before April 1 of each year. The report shall include an overview of reservoir performance, future development and reservoir depletion plans, and surveillance information for the prior calendar year, including: a. Reservoir pressure maps at datum; b. Summary and analysis of reservoir pressure surveys; c. Estimates of reservoir pressure; d. Results and, where appropriate, analysis of production, temperature, tracer surveys, observation well surveys, and any other special monitoring surveys; e. Estimates of yearly production and the reservoir voidage balance of injection and withdrawals at standard and reservoir conditions; f. Progress of plans and tests to expand the productive limits of the pool; and g. Results of surface safety valve testing. Rule 11. Well Mechanical Inte2ritv and Annulus Pressures a. The operator shall conduct and document a pressure test of tubulars and completion equipment in each development well at the time of installation or replacement that is sufficient to demonstrate that planned well operations will not result in failure of well integrity, uncontrolled release of fluid or pressure, or threat to human safety. b. The operator shall monitor each development well daily to check for sustained pressure, unless prevented from doing so by extreme weather conditions, emergency situations, or similar unavoidable circumstances. Monitoring results shall be made available for AOGCC inspection. c. The operator shall notify the AOGCC within three working days after the operator identifies a well as having (i) sustained inner annulus pressure that exceeds 2000 psig Conservation Order 562 December 6, 2005 . . Page 9 or (ii) sustained outer annulus pressure that exceeds 1000 psig. d. The Commission may require the operator to submit in an Application for Sundry Approvals (Form 10-403), a proposal for corrective action or increased surveillance for any development well having sustained pressure that exceeds a limit set out in paragraph "c" of this rule. The Commission may approve the operator's proposal or may require other corrective action or surveillance. The Commission may require that corrective action be verified by mechanical integrity testing or other Commission approved diagnostic tests. The operator shall give the Commission sufficient notice of the testing schedule to allow the Commission to witness the tests. e. If the operator identifies sustained pressure in the inner annulus of a development well that exceeds 45% of the burst pressure rating of the well's production casing for inner annulus pressure, or sustained pressure in the outer annulus that exceeds 45% of the burst pressure rating of the well's surface casing for outer annulus pressure, the operator shall immediately notify the Commission and take corrective action. Unless well conditions require the operator to take emergency corrective action before Commission approval can be obtained, the operator shall submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action. The Commission may approve the operator's proposal or may require other corrective action. The Commission may also require that corrective action be verified by mechanical integrity testing or other Commission approved diagnostic tests. The operator shall give the Commission sufficient notice of the testing schedule to allow the Commission to witness the tests. f. Except as otherwise approved by the AOGCC under paragraph "d" or "e" of this rule, before a shut-in well is placed in service, any annulus pressure must be relieved to a sufficient degree that (i) the inner annulus pressure at operating temperature will be below 2000 psig, and (ii) the outer annulus pressure at operating temperature will be below 1000 psig. However, a well that is subject to paragraph "c", but not paragraph "e", of this rule may reach an annulus pressure at operating temperature that is described in the operator's notification to the AOGCC under paragraph "c", unless the AOGCC prescribes a different limit. Rule 12 Administrative Action Unless notice and public hearing are otherwise required, the Commission may administratively waive the requirements of any rule stated above or administratively amend any rule as long as the change does not promote waste or jeopardize correlative rights, is based upon sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater. Conservation Order 562 December 6, 2005 . . Page 10 DONE at Anchorage, Alaska and dated December 6, 2005 ~ Daniel T. Seamount, Jr., Commissioner Alaska Oil and Gas Conservation Commission fl~ Cathy P. oerster, Commissioner il and Gas Conservation Commission AS 31.05.080 provides that within 20 days after receipt of written notice of the entry of an order, a person affected by it may file with the Commission an application for rehearing. A request for rehearing must be received by 4:30 PM on the 23'd day following the date of the order, or next working day if a holiday or weekend, to be timely filed. The Commission shall grant or refuse the application in whole or in part within 10 days. The Commission can refuse an application by not acting on it within the 10-day period. An affected person has 30 days from the date the Commission refuses the application or mails (or otherwise distributes) an order upon rehearing, both being the final order of the Commission, to appeal the decision to Superior Court. Where a request for rehearing is denied by nonaction òfthe Commission, the 23day period for appeal to Superior Court runs ftom the date on which the request is deemed denied (i.e., lOth day after the application for rehearing was filed). Citgo Petroleum Corporation PO Box 3758 Tulsa, OK 74136 -. Mary Jones XTO Energy, Inc. Cartography 810 Houston Street, Ste 2000 Ft. Worth, TX 76102-6298 . David McCaleb IHS Energy Group GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 Mona Dickens Tesoro Refining and Marketing Co. Supply & Distribution 300 Concord Plaza Drive San Antonio, TX 78216 Robert Gravely 7681 South Kit Carson Drive Littleton, CO 80122 George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 Richard Neahring NRG Associates President PO Box 1655 Colorado Springs, CO 80901 John Levorsen 200 North 3rd Street, #1202 Boise, ID 83702 Kay Munger Munger Oil Information Service, Inc PO Box 45738 Los Angeles, CA 90045-0738 Samuel Van Vactor Economic Insight Inc. 3004 SW First Ave. Portland, OR 97201 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle, WA 98119-3960 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Schlumberger Drilling and Measurements 2525 Gambell Street #400 Anchorage, AK 99503 Baker Oil Tools 4730 Business Park Blvd., #44 Anchorage, AK 99503 Ciri Land Department PO Box 93330 Anchorage, AK 99503 Ivan Gillian 9649 Musket Bell Cr.#5 Anchorage, AK 99507 Jill Schneider US Geological Survey 4200 University Dr. Anchorage, AK 99508 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 Jack Hakkila PO Box 190083 Anchorage, AK 99519 Darwin Waldsmith PO Box 39309 Ninilchick, AK 99639 James Gibbs PO Box 1597 SOldotna, AK 99669 Kenai National Wildlife Refuge Refuge Manager PO Box 2139 Soldotna, AK 99669-2139 Penny Vadla 399 West Riverview Avenue Soldotna, AK 99669-7714 Richard Wagner PO Box 60868 Fairbanks, AK 99706 Cliff Burglin PO Box 70131 Fairbanks, AK 99707 Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 North Slope Borough PO Box 69 Barrow, AK 99723 CO 562 CRF Nanuq Oil Pool, CO 563 CRF Nanuq-Kuparuk Oil Pool... . . Iefs she d@aoga.org>, nocophlllips.com> , atty AIf: Kratz@che n.com>, Gary lof2 12/8/2005 II: 14 AM CO 562 CRF Nanuq Oil Pool, CO 563 CRF Nanuq-Kuparuk Oil Pool... . . dnr.state.ak.us>, Ken oe Nicks s@radiokenaLcom>, <paulto@acsalasa.net>, Cynthia B Rogers <ken@s J erry McCutch~on <s Mciver <bren mciver nt-Type: applicationJpdf C0562.pdf: Content-E ing: base64 12/8/2005 11:14 AM 20[2 • • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: AN ORDER rescinding those rules within ) Docket Number: CO -10 -21 existing Conservation Orders relating to ) Other Order No. 66 well safety valve systems. ) ) Statewide, Alaska January 11, 2011 IT APPEARING THAT: 1. On October 13, 2010 the Alaska Oil and Gas Conservation Commission ( AOGCC or Commission) formally adopted new regulations relating to well safety valve systems, at 20 AAC 25.265. 2. The newly adopted well safety valve system regulations underwent final review by the Regulations Section of the Alaska Attorney General's Office and were forwarded to the Alaska Lieutenant Governor's Office on October 28, 2010. 3. The new regulations were signed by the Lieutenant Governor and took legal effect on December 3, 2010. 4. To ensure consistency with the new regulations, the AOGCC, on its own motion, proposed to rescind part or all of the outdated rules within existing Commission Orders relating to well safety valve systems. 5. On November 4, 2010, pursuant to 20 AAC 25.540, the Commission published in the Alaska Daily News notice of opportunity for public hearing on December 6, 2010. 6. The Commission received written comments in response to its public notice, and held a public hearing on December 7, 2010. 7. Oral testimony and written comments were provided at the December 7, 2010 hearing. FINDINGS: 1. Well safety valve systems are regulated under newly- adopted 20 AAC 25.265, which consolidates the requirements previously established in legacy documents, policies, and statewide guidelines relating to safety valve systems. 2. Thirty -four existing Commission Orders contain rules governing well safety valve systems. Twenty of those Orders contain broad regulatory requirements for safety valve systems that are now covered by the newly- adopted regulations. The remaining fourteen Orders include field- or pool - specific safety valve system requirements. . Other Order 66 • • Page 2 Statewide, AK January 11, 2011 3. Within existing Commission Orders are rules unrelated to well safety valve systems; these rules will continue in effect, unmodified. 4. Existing Commission Orders containing individual rules relating to well safety valve systems are enumerated in the attached Table. CONCLUSIONS: 1. Eliminating redundant requirements and standardizing wording for those field - and pool - specific safety valve system requirements deemed appropriate to retain will improve regulatory clarity. 2. Twenty existing Commission Orders that include rules relating to well safety valve systems are rendered unnecessary, and can be replaced by newly- adopted 20 AAC 25.265. As more fully set forth in the attached Table, those Orders are Conservation Orders 98A, 207A, 300, 311B, 317B, 329A, 341E, 345, 402B, 432D, 452, 457B, 471, 477, 484A, 505B, 553, 559, 570, and a Commission unnumbered Order signed March 30, 1994 (policy dictating SVS performance testing requirements). 3. Fourteen existing Commission Orders include field- or pool- specific safety valve system requirements that the Commission considers appropriate for retention. Wording for the same safety valve system requirements existing in different Commission Orders has been standardized. As more fully set forth in the attached Table, those Orders are Conservation Orders 406B, 423, 430A, 435A, 443B, 449, 456A, 458A, 562, 563, 569, 596, 597, and 605. NOW, THEREFORE, IT IS ORDERED THAT individual rules in thirty-four existing Commission Orders that relate to well safety valve systems are hereby rescinded or revised as enumerated in the Table. Remaining rules unrelated to safety valve systems within affected Commission Orders remain in effect, unmodified. DONE at Anchorage, Alaska, and dated aii ..- ary 11, 2011 j iii ..- Daniel T. Se. r ou , r., Commissioner, Chair • • • it . 4 :. s Conservation Commission k • ,.� r m a n, Co der rA 7 a Oi , % a Conserva ion Commission $ ti .v ► . . I 9 � /Miff ' 4 A Cat y P.:oerst-r, Commissioner "` '' ,1 ' Alaska 0 il and Gas Conservation Commission Other Order 66 • • Page 3 Statewide, AK January 11, 2011 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 Commission grants for good cause shown, a person affected by it may file with the Commission 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 Commission 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 Commission 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 Commission mails, OR 30 days if the Commission 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 Commission 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 Commission, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited to the questions presented to the Commission by the application for 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. • • Fisher, Samantha J (DOA) From: Fisher, Samantha J (DOA) Sent: Tuesday, January 11, 2011 4:08 PM To: Ballantine, Tab A (LAW); '(foms2 @mtaonline. net)'; '( michael .j.nelson @conocophillips.com)'; '(Von.L .Hutchins @conocophillips.com)'; 'AKDCWellIntegrityCoordinator; 'Alan Dennis'; 'alaska @petrocalc.com'; 'Anna Raff; 'Barbara F Fullmer; 'bbritch'; 'Becky Bohrer'; 'Bill Penrose'; 'Bill Walker; 'Bowen Roberts'; 'Brad McKim'; 'Brady, Jerry L'; 'Brandon Gagnon'; 'Brandow, Cande (ASRC Energy Services)'; 'Brian Havelock'; 'Bruce Webb'; 'carol smyth'; 'caunderwood'; 'Chris Gay; 'Cliff Posey'; 'Crandall, Krissell'; 'D Lawrence'; 'dapa'; 'Daryl J. Kleppin'; 'Dave Matthews'; 'David Boelens'; 'David House'; 'David Steingreaber; 'ddonkel @cfl.rr.com'; 'Deborah J. Jones'; Delbridge, Rena E (LAA); 'Dennis Steffy'; 'Elowe, Kristin'; 'Erika Denman'; 'eyancy'; 'Francis S. Sommer'; 'Fred Steece'; 'Gary Laughlin'; 'Gary Rogers'; 'Gary Schultz'; 'ghammons'; 'Gordon Pospisil'; 'Gorney, David L.'; 'Greg Duggin'; 'Gregg Nady'; 'gspfoff; 'Harry Engel'; 'Jdarlington (jarlington @gmail.com)'; 'Jeanne McPherren'; 'Jeff Jones'; 'Jerry McCutcheon'; 'Jill Womack'; 'Jim White'; 'Jim Winegarner'; 'Joe Nicks'; 'John Garing'; 'John Katz'; 'John S. Haworth'; 'John Spain'; 'John Tower; 'Jon Goltz'; 'Judy Stanek'; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; 'Kelly Sperback'; 'Kim Cunningham'; 'Larry Ostrovsky'; 'Laura Silliphant; 'Marilyn Crockett; 'Mark Dalton'; 'Mark Hanley (mark.hanley @anadarko.com)'; 'Mark Kovac'; 'Mark P. Worcester; 'Marguerite kremer; 'Michael Dammeyer; 'Michael Jacobs'; 'Mike Bill'; 'Mike Mason'; 'Mikel Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'nelson'; 'Nick W. Glover; 'NSK Problem Well Supv'; 'Patty Alfaro'; 'Paul Decker (paul.decker @alaska.gov)'; 'Paul Figel'; 'PORHOLA, STAN T'; 'Randall Kanady'; 'Randy L. Skillern'; ' rob.g.dragnich @exxonmobil.com'; 'Robert Brelsford'; 'Robert Campbell'; 'Ryan Tunseth'; 'Scott Cranswick'; 'Scott Griffith'; Scott, David (LAA); 'Shannon Donnelly'; 'Sharmaine Copeland'; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); 'Sondra Stewman'; 'Steve Lambert'; 'Steve Moothart'; 'Steven R. Rossberg'; 'Suzanne Gibson'; 'tablerk'; 'Tamera Sheffield'; Taylor, Cammy 0 (DNR); 'Temple Davidson'; 'Teresa Imm'; 'Terrie Hubble'; 'Thor Cutler'; 'Tina Grovier'; 'Todd Durkee'; 'Tony Hopfinger'; 'trmjrl'; 'Valenzuela, Mariam '; 'Vicki Irwin'; 'Walter Featherly'; 'Will Chinn'; Williamson, Mary J (DNR); 'Yereth Rosen'; 'Aaron Gluzman'; Bettis, Patricia K (DNR); caunderwood @marathonoil.com; 'Dale Hoffman'; 'David Lenig'; 'Gary Orr; 'Jason Bergerson'; 'Joe Longo'; 'Lara Coates'; 'Marc Kuck'; 'Mary Aschoff; 'Matt Gill'; 'Maurizio Grandi'; Ostrovsky, Larry Z (DNR); 'Richard Garrard'; 'Sandra Lemke'; 'Talib Syed'; 'Tiffany Stebbins'; 'Wayne Wooster; 'William Van Dyke'; Woolf, Wendy C (DNR); Aubert, Winton G (DOA) (winton.aubert@alaska.gov); Brooks, Phoebe L (DOA) (phoebe.brooks @alaska.gov); Colombie, Jody J (DOA) (jody.colombie @alaska.gov); Crisp, John H (DOA) (john.crisp @alaska.gov); Davies, Stephen F (DOA) (steve.davies @alaska.gov); Foerster, Catherine P (DOA) (cathy.foerster @alaska.gov); Grimaldi, Louis R (DOA) (lou.grimaldi @alaska.gov); Johnson, Elaine M (DOA) (elaine.johnson @ alaska.gov); Jones, Jeffery B (DOA) (jeff.jones @alaska.gov); Laasch, Linda K (DOA) (linda.laasch @alaska.gov); Maunder, Thomas E (DOA) (tom.maunder @alaska.gov); McIver, Bren (DOA) (bren.mciver @alaska.gov); McMains, Stephen E (DOA) (steve.mcmains @alaska.gov); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA) (bob.noble @alaska.gov); Norman, John K (DOA) (john.norman @alaska.gov); Okland, Howard D (DOA) (howard.okland @alaska.gov); Paladijczuk, Tracie L (DOA) (tracie.paladijczuk @alaska.gov); Pasqual, Maria (DOA) (maria.pasqual @alaska.gov); Regg, James B (DOA) (jim.regg @alaska.gov); Roby, David S (DOA) (dave.roby @alaska.gov); Saltmarsh, Arthur C (DOA) (art.saltmarsh @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); Shartzer, Christine R (DOA) Subject: Other 66 Safety Valve Systems Attachments: other66.pdf Ala4- ka.oi) cuncii gm( Cam-ex Catn4114:4-si-• o- v (907)793 -1223 (907)276 -7542 (fww) 1 1 Mary Jones David McCaleb XTO Energy, Inc. IHS Energy Group George Vaught, Jr. Cartography GEPS P.O. Box 13557 810 Houston Street, Ste 200 5333 Westheimer, Suite 100 Denver, CO 80201 -3557 Ft. Worth, TX 76102 -6298 Houston, TX 77056 Jerry Hodgden Richard Neahring Mark Wedman Hodgden Oil Company NRG Associates Halliburton 408 18 Street President 6900 Arctic Blvd. Golden, CO 80401 -2433 P.O. Box 1655 Anchorage, AK 99502 Colorado Springs, CO 80901 Bernie Karl CIRI K &K Recycling Inc. Land Department Baker Oil Tools P.O. Box 58055 P.O. Box 93330 795 E. 94 Ct. Anchorage, AK 99515 -4295 Fairbanks, AK 99711 Anchorage, AK 99503 North Slope Borough Jill Schneider Gordon Severson P.O. Box 69 US Geological Survey 3201 Westmar Circle Barrow, AK 99723 4200 University Drive Anchorage, AK 99508 -4336 Anchorage, AK 99508 Jack Hakkila Darwin Waldsmith James Gibbs P.O. Box 190083 P.O. Box 39309 P.O. Box 1597 Anchorage, AK 99519 Ninilchick, AK 99639 Soldotna, AK 99669 Kenai National Wildlife Refuge Penny Vadla Cliff Burglin Refuge Manager 399 West Riverview Avenue 319 Charles Street P.O. Box 2139 Soldotna, AK 99669 -7714 Fairbanks, AK 99701 Soldotna, AK 99669 -2139 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 Q` \` Orders Establishing Requirements for Well Safety Valve Systems 1/7/2011 Conservation New Regulation Provisions Revised Rule - "Well safety valves stems" (2) Comment Unit/Field Pool Order (1) Rule Rescind Rule? Existing Order Requirement Addressing Regts from Order y systems" ) fail -safe auto SSV and SCSSV; injection wells (except disposal) require "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered b Colville River Unit Qannik 605 5 no (i) double check valve, or (ii) single check valve and SSV; injection 25.265(a); 25.265(b); 25.265(d)(2)(H); arrangement or (ii) a single check valve and a SSV. A subsurface controlled injection valve or q / y 25.265(h)(5) SCSSV satisfies the re uirements o a sin le check valve." readopted regulation valve satisfies single check valve requirement; test every 6 months requirements single auto SSV and SCSSV; injection wells (except disposal) require "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve re uiremeMS for in ectors are not covered by 25.2659(b); 25.265(d)(1); arrangement (ii) single check valve and a SSV. A subsurface - controlled injection ement or ii a sin ection valve or q / y Oooguruk Oooguruk - Nuiqsut 597 6 no (i) double check valve, or (ii) single check valve and SSV; injection 25.265(h)(5) th readopted regulation valve satisfies single check valve requirement; test every 6 months SCSSV satisfies the requirements of a single check valve." fail -safe auto SSV and SCSSV; injection wells (except disposal) require we ll s (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered b 25.265(a); 25.265( 25 q i by Oooguruk Oooguruk - Kuparuk 596 6 no 0) double check valve, or (ii) single check valve and SSV; injection 25.265(h)(5) arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or readopted regulation valve satisfies single check valve requirement; test every 6 months SCSSV satisfies the requirements of a single check valve." fail -safe auto SSV and SCSSV; maintain list of wells wl removed or 25.265(a); 25.265(b); 25.265(d)(2)(F); Requirement to maintain a wellhead sign and list of wells with N/A deactivated SVS was replaced with requirement to maintain a Prudhoe Bay Unit Raven 570 5 yes deactivated SVS; sign on wellhead 25.265(m) tag on well when not manned fail -safe auto SSV and SCSSV; (except osa excep ection wells t disposal) require 25.26a r "I wells (excludin dis injectors) must be equipped with(i) a double check valve q 25.265(a); 25.265(b); 25.265(d Check valve requirements for injectors are not covered by Colville River Unit Fiord 569 5 no (i) double check valve, or (ii) single check valve and SSV; injection . arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or 25.265(h)(5) readopted regulation valve satisfies single check valve requirement; test every 6 months ( )( 5 ) SCSSV satisfies the requirements of a single check valve." fail -safe auto SSV and SCSSV; injection wells (except disposal) require "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors by 25265 h 25.265(a); 25.265(b); 25.265(d)(2)(H); eq jectors are not covered b Colville River Unit Nanuq - Kuparuk 563 6 no (i) double check valve, or (ii) single check valve and SSV; injection 25.265(h)(5) arrangement or (ii) a single check valve and a SSV. Asubsurface- controlled injection valve or readopted regulation valve satisfies single check valve requirement; test every 6 months ( )( 5 ) SCSSV satisfies the requirements of a single check valve." fail -safe auto SSV and SCSSV; injection wells (except disposal) require 25.265(a); 25.265(b); 25.265(d)(2)(H); "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered by Colville River Unit Nanuq 562 6 no (i) double check valve, or (ii) single check valve and SSV; injection arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or readopted regulation uirements of a sinle check valve valve satisfies single check valve requirement; test every 6 months 25.26 SCSSV satisfies the reqg." fail -safe auto SSV; SSSV landing nipple below permafrost; test as 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; Prudhoe Bay Unit Put River 559 3 yes prescribed by Commission 25.265(h)(5) replaces SSSV nipple requirement for all wells Deep Creek Unit Happy Valley 553 3 yes SSV or SSSV 25.265(a) N/A fail -safe auto SSV; SSSV landing nipple below permafrost; test as 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; Prudhoe Bay Unit Orion 505B 3 yes prescribed by Commission 25.265(h)(5) replaces SSSV nipple requirement for all wells fail -safe auto SSV; SSSV landing nipple below permafrost; test as 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; Prudhoe Bay Unit Polaris 484A 3 yes prescribed by Commission 25.265(h)(5) replaces SSSV nipple requirement for all wells fail -safe auto SSV; SSSV landing nipple below permafrost; gas /MI Milne Point 25.265(a); 25.265(b); 25.265(d); N/A ( Milne Point Unit 477 5 yes injection we require SSSV or injection valve below permafrost; test Readopted 25.265 d ) dictates which wells require SSSV; Schrader Bluff every 6 months 25.265(h)(5) replaces SSSV nipple requirement for all wells fail -safe auto SSV; SSSV landing nipple below permafrost; gas /MI 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; Prudhoe Bay Unit Borealis 471 3 yes injection well require SSSV below permafrost; test every 6 months 25. replaces SSSV nipple requirement for all wells fail -safe auto SSV and SCSSV; test as prescribed by Commission; 500- Existing pool rule established a minimum setting depth for the Northstar Northstar 458A 4 no 25.265(a); 25.265(b); 25.265(d)(1) The minimum setting depth for a tubing conveyed subsurface safety valve is 500 feet." SSSV ft minimum setting depth for SSSV fail -safe auto SSV; SSSV landing nipple below permafrost; test every 6 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; Prudhoe Bay Unit Aurora 457B 3 yes months 25.265(h)(5) replaces SSSV nipple requirement for all wells fail -safe auto SSV; gas /MI injectors require SSV and single check "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered by 25.265(x); 25.265(b); 25.265(d); arrangement or (ii) readopted regulation; ulation; d readopted 25.265 Kuparuk River Unit Meltwater 456A 5 no valve and SSSV landing nipple; water injection wells require (1) double 25.265(h)(5) arran 9 () a single check valve and a SSV. A subsurface - controlled injection valve or reado / p p 25.265(d)(5) ) does not include check valve, or (ii) single check valve and SSV; test every 6 months SCSSV satisfies the requirements of a single check valve." SSSV requirement for MI injectors fail -safe auto SSV (all injectors and producers capable of unassisted 25.265(a); 25.265(b); 25.265(d); NIA Readopted 25.265(d) dictates which wells require SSSV; Prudhoe Bay Unit Midnight Sun 452 6 yes flow to surface); test every 6 months 25.265(h)(5) replaces SSSV nipple requirement for all wells fail -safe auto SSV and SCSSV; SSSV may be installed above or below "The setting depth of a required subsurface safety valve must be located in the tubing either Existing pool rule established alternate SSSV setting depth; 25.265(a); 25.265(b); 25.265(d)(1); Duck Island Unit Eider 449 7 no permafrost; injection wells require double check valve; LPS trip above or below permafrost. Injection wells must be equipped with a double check valve check valve requirements for injectors are not covered by 25.265(h)(5) pressure; test every 6 months arrangement." readopted regulation fail -safe auto SSV and SCSSV (producers and gas injectors); water "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered by Colville River Unit Alpine 443B 5 no injection wells require (i) double check valve, or (ii) single check valve 25.265(a); 25.265(b); 25.265(d)(2)(H) arrangement or (ii) a single check valve and a SSV. A subsurface- controlled injection valve or and SSV SCSSV satisfies the requirements of a single check valve." readopted regulation fail -safe auto SSV; gas /MI injectors require SSV and single check 25.265(x); 25.265(b); 25.265(d); "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered by Kuparuk River Unit Tabasco 435A 6 no valve and SSSV landing nipple; water injection wells require (i) double arrangement or (ii) a single check valve and a SSV. A subsurface-controlled injection valve or readopted regulation; readopted 25.265(d)(5) does not include check valve, or (ii) single check valve and SSV; test every 6 months 25 SCSSV satisfies the requirements of a single check valve." SSSV requirement for MI injectors fail -safe auto SSV (S /D well and artificial lift); sign on well if SVS Requirement to maintain a wellhead sign and list of wells with deactivated; maintain list of wells w /deactivated SVS; test as 25.265(x); 25.265(b); 25.265(h)(5); deactivated SVS was replaced with requirement to maintain a Kuparuk River Unit; r () _ N/A tag on well when not manned; administrative approval CO Kuparuk 432D 5 yes prescribed escribed by Commission; CO 432D.009 modifies Rule 5 b LPP P Milne Point Unit may be defeated on W. Sak injectors w/surface pressure <500psi w/ 25.265(m) 432D.009 remains effective [re:defeating the LPS when surface notice when defeated and placed back in service injection pressure for West Sak water injector is <500psi] Page 1 of 2 Orders Establishing Requirements for Well Safety Valve Systems 1/7/2011 Unit/Field Pool Conservation Rule Rescind Rule? Existing Order Requirement New Regulation Provisions Order (1) g q Addressing Reqts from Order Revised Rule - "Well safety valve systems" (2) Comment fail -safe auto SSV; gas /MI injectors require SSV and single check "I wells (e xcluding disposal injectors) must be equipped with (i) a 25.265(a); 25.265(b); 25.265(d); () double check valve Check valve requirements for injectors are not covered by Kuparuk River Unit Tarn 430A 6 no valve and SSSV landing nipple; water injection wells require (i) double arrangement or (ii) a single check valve and a SSV. A subsurface- controlled injection valve or readopted regulation; readopted 25.265(d)(5) does not include check valve, or (ii) single check valve and SSV; test every 6 mo nths 25 Y SCSSV satisfies the requirements of a single check valve." SSSV requirement for MI injectors Milne Point - Sag fail -safe auto SSV; injection wells require double check valve; test k Chec valve requirements for injectors are not covered b Milne Point Unit 423 7 no 25.265(a); 25.265(b); 25.265(h)(5) "Injection wells must be equipped with a double check valve arrangement." by River every 6 months readopted regulation fail-safe auto SSV; gas /Mt injectors require SSV and single check valve and SSSV landing nipple; water ni le; injection re (i ) double "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Check readop valve ted re requirements ultionad for injectors are not covered by injection wells require i Kuparuk River Unit Kuparuk - West Sak 406B 6 no check valve, or (ii) single check valve and SSV; test every 6 months; 25.265(a); 25.265(b); 25.265(d); arrangement or (ii) a single check valve and a SSV. A subsurface- controlled injection valve or g a ; re opted 25.265(d)(5) does not nclude CO 4068.001 modifies Rule 6(e) - LPP may be defeated on W. Sak 25.265(h)(5) SCSSV satisfies the requirements of a single check valve. The Low Pressure Pilot may be SSSV requirement for MI injectors; administrative approval CO injectors w /surface pressure <500psi wl notice when defeated and defeated on West Sak water injectors with surface injection pressure less than 500psi " 4066.001 remains effective [re:defeating the LPS when surface placed back in service injection pressure for West Sak water injector is <500psij fail -safe auto SSV and SCSSV; LPS trip pressure; readily accessible Badami Badami 402B 6 yes control unit SSSV belo permafrost; NTE 210days between tests; 25.265(a); 25.265(b); 25.265(h); N/A submit test results electronically within 14days; SVS defeated /removed 25.265(m) only if well SI or pad continuously manned fail -safe auto SSV (S /D well and artificial lift); sign on well if SVS 25.265(a); 25.265(b); 25.265(h)(5); Requirement to maintain a wellhead sign and list of wells with Prudhoe Bay Unit North Prudhoe 345 4 yes deactivated; maintain list of wells w/deactivated SVS; test as N/A 25.265 m deactivated SVS was replaced with requirement to maintain a prescribed by Commission ( ) tag on well when not manned fail -safe auto SSV (SID well and artificial lift); if SSSV installed it must Prudhoe Bay Unit Prudhoe 341E 5 yes be maintained and tested as part of SVS; sign on well if SV 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; deactivated; maintain list of wells w /deactivated SVS; test as 25.265(h)(5) replaces SSSV nipple requirement for all wells prescribed by Commission Prudhoe Bay Unit Niakuk 329A 5 yes fail -safe auto SSV and SCSSV; maintain list of wells w/ removed o 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; deactivated SVS; sign on wellhead 25.265(h)(5); 25.265(m) replaces SSSV nipple requirement for all wells Prudhoe Bay Unit Pt. McIntyre 317B 8 yes fail -safe auto SSV and SCSSV; SSSV may be rermoved as part of 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; routine well ops w/o notice 25.265(j); 25.265(m) replaces SSSV nipple requirement for all wells Prudhoe Bay Unit West Beach 311 B 6 yes fail -safe auto SSV; sign on well if SVS deactivated; maintain list of wells 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; w/deactivated SVS; test as prescribed by Commission 25.265(h)(5); 25.265(m) replaces SSSV nipple requirement for all wells West Fork West ) B) Fork (Sterling 300 5 yes fail -safe auto SVS on each production tubing 25.265(a); 25.265(b) N/A Prudhoe Bay Unit Lisburne 207A 7 yes fail -safe auto SSV; sign on well if SVS deactivated; maintain list of wells 25.265(a); 25.265(b); 25.265(h)(5); Requirement to maintain a wellhead sign and list of wells with w /deactivated SVS; test as prescribed by Commission 25.265(m) NIA deactivated SVS was replaced with requirement to maintain a tag on well when not manned Prudhoe Bay Unit Prudhoe - Kuparuk 98A 5 es suitable automatic safety valve installed below base of permafrost t Readopted 25.265(d) require prevent uncontrolled flow 25.265(d) N/A pted 25.265 d dictates which wells re uire SSSV; replaces SSSV nipple requirement for all wells Statewide N/A N/A N/A yes Commission policy dictating SVS performance testing AOGCC Policy - SVS Failures; issued by order of the y requirements 25.265(h); 25.265(n); 25.265(0) N/A Commission 3/30/1994 (signed by Commission Chairman Dave Johnson) Footnotes (1) No SVS rules found in Injection Orders (2) New title for Revised Rule; "N /A" means entire pool rule to be rescinded Page 2 of 2 • • Public Hearing Record And Backup Information available in Other 66 . . SARAH PALIN, GOVERNOR AI~SIiA. OIL A1Q) GAS CONSERVATION COMMISSION 333 W. 7th AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRA TIVE APPROVAL NO. CO 443A.003 ADMINISTRATIVE APPROVAL NO. CO 562.001 ADMINISTRATIVE APPROVAL NO. CO 563.001 ADMINISTRATIVE APPROVAL NO. CO 569.001 Ms. Maria Kemner Alpine Production Engineer ConocoPhillips Alaska, Inc. PO Box 100360 Anchorage, AK 99510-0360 Re: Allowable Gas OffTake Rate for the Colville River Unit Dear Ms. Kemner: On February 8, 2007, ConocoPhillips Alaska, Inc. ("ConocoPhillips") applied to the Alaska Oil and Gas Conservation Commission ("Commission") to establish an allowable gas off take rate to permit shipping gas from the Colville River Field ("CRF") to the Village of Nuiqsut. The maximum allowable gas off take requested for the CRU is 1 million standard cubic feet per day ("MMCFPD"). This allowable gas offtake rate would apply to !ill currently defined pools within the CRF and any future pools within the CRF that commingle production at the Alpine Central Facility ("ACF"). In the application and during a Commission Public Hearing on November 28, 2006, ConocoPhillips demonstrated an obligation to provide up to 1 MMCFPD for the Village of Nuiqsut under the terms of a contract between ConocoPhillips predecessor Arco Alaska, Inc. and Kuukpik Corporation. The North Slope Borough, acting on behalf of the Village of Nuiqsut and Kuukpik Corporation, is currently in the process of commissioning a gas transmission line from the ACF to the village. Under the authority of Alaska Statute 31.05 .030( e)(1 )(F) the Commission has determined that establishing an allowable gas offtake rate for the CRF is necessary to ensure conservation of resources. There are currently four defined oil pools within the Colville River Unit. These are: 1. Alpine Oil Pool, established by Conservation Order ("CO") 443 on March 15, 1999, and later expanded by CO 443A on October 7, 2004; 2. Nanuq Oil Pool, established by CO 562 on December 6, 2005; 3. Nanuq-Kuparuk Oil Pool, established by CO 563 on December 5, 2005; and 4. Fiord Oil Pool, established by CO 569 on July 21,2006. Production from these pools is being commingled and processed at the ACF. All produced gas is either being consumed within the CRF for operational purposes or re-injected to enhance oil recovery from the pools within the CRF. . . Ms. Maria Kemner February 13, 2007 Page 2 of2 Rule 11 of CO 443A states: "upon proper application or its own motion, the Commission may administratively waive the requirements of any rule stated above or administratively amend this order as long as the change does not promote waste, jeopardize correlative rights, or compromise ultimate recovery and is based on sound engineering principles." Rule 12 of CO 562, CO 563, and CO 569 states: "unless notice and public hearing are otherwise required, the Commission may administratively waive the requirements of any rule stated above or administratively amend any rule as long as the change does not promote waste or jeopardize correlative rights, is based upon sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into 1Ì'esh water." The Commission has determined that a 1 MMCFPD allowable gas off take rate for the CRF will not promote waste, jeopardize correlative rights, or compromise ultimate recovery and that notice and public hearing are not required to establish an allowable gas off take rate. This proposal is based upon sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into 1Ì'esh water. Therefore, the Commission hereby approves ConocoPhillips requested gas offtake rate with the following conditions: 1. The cumulative gas offtake rate from the CRF must not exceed I MMCFPD. 2. Natural gas may not be severed from the CRF for any other purpose than to meet ConocoPhillips' contractual obligations of providing the Village of Nuiqsut with natural gas. 3. Any new pools that process production at the ACF will be subject to the terms of this administrative approval. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. orage, Alaska and dated February 13,2007. ~ J Chairman Daniel T. Seamount, Jr. Commissioner ~/~ Cathy . Foerster Commissioner " '\, 'I. \ \ ~ p i .~:~ I ..F.-__:";! .. /1..) '.I ~~~;Yn' '/ aio18b-003 CRU CD2-48 . . Subject: aio 18b-003 CRU CD2-48 From: Jody Colombie <jody_colombie@admin.state.akus> Date: Tue, 13 Feb 2007 13:48:36 -0900 To: undisclosed-recipients:; BCC: Cynthia B Mciver <bren_mciver@admin.state.ak.us>, Christine Hansen <c.hansen@iogcc.state.okus>, Terrie Hubble <hubblet1@bp.com>, Sondra Stewman <StewmaSD@BP.com>, stanekj <stanekj@unocal.com>, ecolaw <ecolaw@trustees.org>, trmjrl <trmjr 1 @ao1.com>, jdarlington <jdarlington@forestoi1.com>, nelson <knelson@petroleumnews.com>, cboddy <cboddy@usibelli.com>, Mark Dalton <mark.dalton@hdrinc.com>, Shannon Donnelly <shannon.donnelly@conocophillips.com>, "Mark P. Worcester" <markp.worcester@conocophillips.com>, Bob <bob@inletkeeper.org>, wdv <wdv@dnr.state.ak.us>, tjr <tjr@dnr.state.ak.us>, bbritch <bbritch@alaska.net>, mjnelson <mjnelson@purvingertz.com>, Charles O'Donnell <charles.o'donnell@veco.com>, "Randy L. Skillern" <SkilleRL@BP.com>, "Deborah J. Jones" <JonesD6@BP.com>, "Steven R. Rossberg" <RossbeRS@BP.com>, Lois <lois@inletkeeper.org>, Dan Bross <kuacnews@kuac.org>, Gordon Pospisil <PospisG@BP.com>, "Francis S. Sommer" <SommerFS@BP.com>, Mikel Schultz <Mike1.Schultz@BP.com>, "Nick W. Glover" <GloverNW@BP.com>, "Daryl J. Kleppin" <KleppiDE@BP.com>, "Janet D. Platt" <PlattJD@BP.com>, "Rosanne M. Jacobsen" <JacobsRM@BP.com>, ddonkel <ddonkel@cfl.rr.com>, mckay <mckay@gcLnet>, Barbara F Fullmer <barbara.f.fullmer@conocophillips.com>, Charles Barker <barker@usgs.gov>, doug_schultze <doug_schultze@xtoenergy.com>, Hank Alford <hank.alford@exxonmobi1.com>, Mark Kovac <yesno l@gci.net>, gspfoff <gspfoff@aurorapower.com>, Gregg Nady <gregg.nady@shell.com>, Fred Steece <fred.steece@state.sd.us>, rcrotty <rcrotty@ch2m.com>,jejones <jejones@aurorapower.com>, dapa <dapa@alaska.net>,jroderick <jroderick@gci.net>, eyancy <eyancy@seal-tite.net>, "James M. Ruud" <james.m.ruud@conocophillips.com>, Brit Lively <mapalaska@ak.net>, jah <jah@dnr.state.ak.us>, buonoje <buonoje@bp.com>, Mark Hanley <mark_hanley@anadarko.com>, Julie Houle <julie _ houle@dnr.state.ak.us>, John W Katz <jwkatz@alaskadc.org>, tablerk <tablerk@unocal.com>, Brady <brady@aoga.org>, Brian Havelock <beh@dnr.state.ak.us>, bpopp <bpopp@borough.kenai.ak.us>, Jim White <jimwhite@satx.rr.com>, "John S. Haworth" <john.s.haworth@exxonmobi1.com>, marty <marty@rkindustrial.com>, ghammons <ghammons@ao1.com>, rmclean <rmc1ean@pobox.alaska.net>, mkm7200 <mkm7200@aol.com>, Brian Gillespie <ifbmg@uaa.alaska.edu>, David L Boelens <dboelens@aurorapower.com>, Todd Durkee <TDURKEE@KMG.com>, Gary Schultz <gary _schultz@dnr.state.ak.us>, Wayne Rancier <RANCIER@petro-canada.ca>, Brandon Gagnon <bgagnon@brenalaw.com>, Paul Winslow <pmwinslow@forestoi1.com>, Sharmaine Copeland <copelasv@bp.com>, Kristin Dirks <krlstin_dirks@dnr.state.ak.us>, Kaynell Zeman <kjzeman@marathonoi1.com>, John Tower <John.Tower@eia.doe.gov>, Bill Fowler <Bill_Fowler@anadarko.COM>, Scott Cranswick <scott.cranswick@mms.gov>, Brad McKim <mckimbs@BP.com>,jack newell <jacknewell@acsalaska.net>, James Scherr <james.scherr@mms.gov>, nI617@conocophillips.com, Tim Lawlor <Tim_Lawlor@ak.blm.gov>, Lynnda Kahn <Lynnda_Kahn@fws.gov>, Jerry Dethlefs <Jerry. C.Dethlefs@conocophillips.com>, crockett@aoga.org, Tamera Sheffield <sheffield@aoga.org>, Jon Goltz <Jon.Goltz@conocophillips.com>, Roger Belman <roger.belman@conocophillips.com>, Mindy Lewis <m1ewis@brenalaw.com>, Karl Moriarty <moriarty@aoga.org>, Patty Alfaro <palfaro@yahoo.com>, Jeff <smetankaj@unoca1.com>, Gary Rogers <gary Jogers@revenue.state.ak.us>, Arthur Copoulos <Arthur _ Copoulos@dnr.state.ak.us>, Ken <klyons@otsintl.com>, Steve Lambert <salambert@unocal.com>, Joe Nicks <news@radiokenai.com>, Jerry McCutcheon <susitnahydronow@yahoo.com>, Bill Walker <bill-wwa@ak.net>, Iris Matthews <Iris_Matthews@legis.state.ak.us>, Paul Decker <paul_decker@dnr.state.ak.us>, Aleutians East Borough lof2 2/15/20077:26 PM aio18b-003 CRU CD2-48 . . <admin@aleutianseast.org>, Marquerite kremer <marguerite _ kremer@dnr.state.ak.us>, Mike Mason <mike@kbbi.org>, Garland Robinson <gbrobinson@marathonoil.com>, Cammy Taylor <Camille_Taylor@law.state.ak.us>, Thomas E Maunder <tom_maunder@admin.state.ak.us>, Stephen F Davies <steve _ davies@admin.state.ak.us>, Keith Wiles <kwiles@marathonoil.com>, Deanna Gamble <dgamble@kakivikcom>, James B Regg <jimJegg@admin.state.ak.us>, Catherine P Foerster <cathy _foerster@admin.state.ak.us>, Bob <Bob@fairweather.com>, gregory micallef <micallef@clearwire.net>, Laura Silliphant <laura_silliphant@dnr.state.ak.us>, David Steingreaber <david.e.steingreaber@exxonmobil.com>, akpratts@acsalaska.net, Robert Campbell <Robert.Campbell@reuters.com>, Steve Moothart <steve_moothart@dnr.state.ak.us>, Anna Raff <anna.raff@dowjones.com>, Cliff Posey <cliff@posey.org>, Paul Bloom <paul_ bloom@ml.com>, Meghan Powell <Meghan.Powell@asrcenergy.com>, Temple Davidson <temple _ davidson@dnr.state.ak.us>, Walter Featherly <WFeatherly@PattonBoggs.com>, Tricia Waggoner <twaggoner@nrginc.com>, Mike Stockinger <Mike.Stockinger@anadarko.com>, John Spain <jps@stateside.com>, Cody Rice <Cody_Rice@legis.state.ak.us>, John Garing <garingJD@bp.com>, Harry Engel <engelhr@bp.com>, Jim Winegarner <jimwinegarner@brooksrangepetro.com>, Matt Rader <mattJader@dnr.state.ak.us>, carol smyth <carol.smyth@shell.com>, Arthur C Saltmarsh <art_saltmarsh@admin.state.ak.us>, Chris Gay <cdgay@marathonoil.com>, foms@mtaonline.net, Rudy Brueggeman <rudy.brueggemann@intemational.gc.ca> J ody Colombie <l Od1~...s:~\2l~Hn ºi~(â~<..!.ç!!!!Ü!:..st'!!~:ªtl¡~> Special Staff Assistant Alaska Oil and Gas Conservation Commission Department of Administration Content-Type: applicationlpdf aio18b-003.pdf Content-Encoding: base64 2of2 2/15/20077:26 PM Mary Jones XTO Energy, Inc. Cartography 810 Houston Street, Ste 2000 Ft. Worth, TX 76102-6298 George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 John Levorsen 200 North 3rd Street, #1202 Boise,lD 83702 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Ciri Land Department PO Box 93330 Anchorage, AK 99503 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 James Gibbs PO Box 1597 Soldotna, AK 99669 Richard Wagner PO Box 60868 Fairbanks, AK 99706 North Slope Borough PO Box 69 Barrow, AK 99723 . David McCaleb IHS Energy Group GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 Kay Munger Munger Oil Information Service, Jnc PO Box 45738 Los Angeles, CA 90045-0738 Schlumberger Drilling and Measurements 2525 Gambell Street #400 Anchorage, AK 99503 Ivan Gillian 9649 Musket Bell Cr.#5 Anchorage, AK 99507 Jack Hakkila PO Box 190083 Anchorage, AK 99519 Kenai National Wildlife Refuge Refuge Manager PO Box 2139 Soldotna, AK 99669-2139 Cliff Burglin PO Box 70131 Fairbanks, AK 99707 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 . Mona Dickens Tesoro Refining and Marketing Co. Supply & Distribution 300 Concord Plaza Drive San Antonio, TX 78216 Richard Neahring NRG Associates President PO Box 1655 Colorado Springs, CO 80901 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle, WA 98119-3960 Baker Oil Tools 4730 Business Park Blvd., #44 Anchorage, AK 99503 Jill Schneider US Geological Survey 4200 University Dr. Anchorage, AK 99508 Darwin Waldsmith PO Box 39309 Ninilchick, AK 99639 Penny Vadla 399 West Riverview Avenue Soldotna, AK 99669-7714 Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 ðl . ~rrr~~Œ (ID~ ~~~~[{~ . AI~ASIiA OIL A1Q) GAS CONSERVATION COMMISSION SARAH PALIN, GOVERNOR 333 W. 7th AVENUE, SUITE 100 ANCHORAGE. ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL CO 562.002 Mr. Jack Walker ConocoPhillips Alaska, Inc. 700 G Street Anchorage, AK 99501 RE: CRU CD4-214 Request for Administrative Approval Dear Mr. Walker: In accordance with Rule 12 of Conservation Order ("CO") 562.000, the Alaska Oil and Gas Conservation Commission ("AOGCC" or "Commission") hereby grants ConocoPhillips Alaska Inc. ("CPAI")'s request for administrative approval to produce the subject well up to 60 days without a subsurface safety valve ("SSSV"). Your request for administrative approval is approved. CRU CD4-214 was permitted and completed as a water-alternating-gas ("WAG") injector in the Nanuq Oil Pool. The gas oil ratio ("GOR") encountered in the Nanuq Oil Pool by this well was significantly higher than expected. Rationale for temporarily producing the well prior to injection is to gain an improved understanding other GOR performance, which will assist CP AI in developing an improved reservoir description and the placement of future development wells in the Nanuq Oil Pool. CP AI states that the well is equipped with the required safety valve system, including a wireline-retrievable injection valve down hole. The injection valve will not allow production. Installation of a surface-controlled SSSV suitable for production service is deemed impractical for this test, requiring a rig workover to replace the well's tubing and install control lines for the SSSV. Installation of a subsurtàce controlled SSSV, while possible, is complicated by the lack of well performance data required to properly size the subsurface-controlled valve. AOGCC's administrative approval to temporarily produce CRU CD4-214 without a SSSV will not promote waste or jeopardize correlative rights, and is based on sound engineering and geoscience principles. There is no risk of movement of fluids into freshwater. This approval is conditioned upon the following: 1. CPAI shall not produce CRU CD4-214 more than 60 days; . . CO 562.002 March 13,2007 Page 2 of2 2. CP AI shall maintain automatic remote and local surface shut in capabilities of the well; 3. CRU CD4-214 must be checked each work shift to ensure the SSV and low pressure pilot or low pressure transmitter are operational; 4. CP AI shall test the surface safety valve system within 3 days of commencing production, to be witnessed by the Commission. CP AI must give the Commission 48 hours notice of the safety valve system test. Subsequent testing of the surface safety valve system is required 90 days from commencement of production should the 60 days of authorized production occur over more than a 3 month timeframe. 5. CP AI shall tag the production tree with a sign indicating the SSSV is out of the well. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. DONE at Anchorage, Alaska and dated March 13,2007. Iv-- Cathy . Foerster Commissioner Mary Jones XTO Energy, Inc. Cartography 810 Houston Street, Ste 2000 Ft. Worth, TX 76102-6298 George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 John Levorsen 200 North 3rd Street, #1202 Boise, ID 83702 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Ciri Land Department PO Box 93330 Anchorage, AK 99503 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 James Gibbs PO Box 1597 Soldotna, AK 99669 Richard Wagner PO Box 60868 Fairbanks, AK 99706 North Slope Borough PO Box 69 Barrow, AK 99723 . David McCaleb IHS Energy Group GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 Kay Munger Munger Oil Information Service, Inc PO Box 45738 Los Angeles, CA 90045-0738 Schlumberger Drilling and Measurements 2525 Gambell Street #400 Anchorage, AK 99503 Ivan Gillian 9649 Musket Bell Cr.#5 Anchorage, AK 99507 Jack Hakkila PO Box 190083 Anchorage, AK 99519 Kenai National Wildlife Refuge Refuge Manager PO Box 2139 Soldotna, AK 99669-2139 Cliff Burglin PO Box 70131 Fairbanks, AK 99707 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 . Mona Dickens Tesoro Refining and Marketing Co. Supply & Distribution 300 Concord Plaza Drive San Antonio, TX 78216 Richard Neahring NRG Associates President PO Box 1655 Colorado Springs, CO 80901 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle, WA 98119-3960 Baker Oil Tools 4730 Business Park Blvd., #44 Anchorage, AK 99503 Jill Schneider US Geological Survey 4200 University Dr. Anchorage, AK 99508 Darwin Waldsmith PO Box 39309 Ninilchick, AK 99639 Penny Vadla 399 West Riverview Avenue SOldotna, AK 99669-7714 Bemie Karl K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 ¡ ,(tYt '- I' AI úV' I vi I u ¡ç r 31 . .............. '.L..J '-"'" -', .. ... '-"..... '-' L -', .. .........., L .VVJ ___.1..""........"".....'-'.1.., .............., J....,....VV..., 1 ).~'-'-r.L....t-V t u . . Subject: AI04E-019, AI03-015, AI01.005 Cancellation, CO 562.002, AI04E-018 From: Jody Colombie <jody_colombie@admin.state.ak.us> Date: Tue, 13 Mar 2007 14:54:02 -0800 To: undisclosed-recipients:; BCC: Cynthia B Mciver <bren_mciver@admin.state.ak.us> Jody Colombie <jody colombie(a?admin.state.ak.us> Special Staff Assistant Alaska Oil and Gas Conservation Commission Department of Administration Content-Type: application/pdf aio4e-19.pdf . Content-Encodmg: base64 Content-Type: application/pdf aiol-5 cancelled.pdf Content-Encoding: base64 Content-Type: application/pdf aio3.15.pdf Content-Encoding: base64 Content-Type: application/pdf aio4e.18.pdf Content-Encoding: base64 Content-Type: application/pdf co562-002.pdf Content-Encoding: base64 of 1 3/13/2007 2:57 PM ~lVI-J \.Alll\;Clldl1UII, ~lVJ-UIJ, ~lV 'fe-IO, .e-I":1 dllU\..cVJO¿-UV¿ . Subject: AIOl-5 Cancellation, AI03-015, AIO 4E-18, AIO 4E-19 and C0562-002 From: Jody Colombie <jody_colombie@admin.state.ak.us> Date: Tue, 13 Mar 2007 14:57: 11 -0800 To: undisclosed-recipients:; BCC: Christine Hansen <c.hansen@iogcc.state.ok.us>, Terrie Hubble <hubbletl@bp.com>, Sondra Stewman <StewmaSD@BP.com>, stanekj <stanekj@unocal.com>, ecolaw <ecolaw@trustees.org>, trmjrl <trmjrl@aol.com>, jdarlington <jdarlington@forestoil.com>, nelson <knelson@petroleumnews.com>, cboddy <cboddy@usibelli.com>, Mark Dalton <mark.dalton@hdrinc.com>, Shannon Donnelly <shannon.donnelly@conocophillips.com>, "Mark P. Worcester" <mark.p.worcester@conocophillips.com>, Bob <bob@inletkeeper.org>, wdv <wdv@dnr.state.ak.us>, tjr <tjr@dnr.state.ak.us>, bbritch <bbritch@alaska.net>, mjnelson <mjnelson@purvingertz.com>, Charles O'Donnell <charles.o'donnell@veco.com>, "Randy L. Skillern" <SkilleRL@BP.com>, "Deborah J. Jones" <JonesD6@BP.com>, "Steven R. Rossberg" <RossbeRS@BP.com>, Lois <lois@inletkeeper.org>, Dan Bross <kuacnews@kuac.org>, Gordon Pospisil <PospisG@BP.com>, "Francis S. Sommer" <SommerFS@BP.com>, Mikel Schultz <Mikel.SchuItz@BP.com>, "Nick W. Glover" <GloverNW@BP.com>, "Daryl J. Kleppin" <KleppiDE@BP.com>, "Janet D. Platt" <PlattJD@BP.com>, "Rosanne M. Jacobsen" <JacobsRM@BP.com>, ddonkel <ddonkel@cfl.rr.com>, mckay <mckay@gci.net>, Barbara F Fullmer <barbara.f.fullmer@conocophillips.com>, Charles Barker <barker@usgs.gov>, doug_schultze <doug_schultze@xtoenergy.com>, Hank Alford <hank.alford@exxonmobil.com>, Mark Kovac <yesnol@gci.net>, gspfoff <gspfoff@aurorapower.com>, Gregg Nady <gregg.nady@shell.com>, Fred Steece <fred.steece@state.sd. us>, rcrotty <rcrotty@ch2m.com>, jejones <jejones@aurorapower.com>, dapa <dapa@alaska.net>,jroderick <jroderick@gci.net>, eyancy <eyancy@seal-tite.net>, "James M. Ruud" <james.m.ruud@conocophillips.com>, Brit Lively <mapalaska@ak.net>, jah <jah@dnr.state.ak.us>, buonoje <buonoje@bp.com>, Mark Hanley <mark_hanley@anadarko.com>, Julie Houle <julie_houle@dnr.state.ak.us>, John W Katz <jwkatz@alaskadc.org>, tablerk <tablerk@unocal.com>, Brady <brady@aoga.org>, Brian Havelock <beh@dnr.state.ak.us>, bpopp <bpopp@borough.kenai.ak.us>, Jim White <jimwhite@satx.rr.com>, "John S. Haworth" <john.s.haworth@exxonmobil.com>, marty <marty@rkindustrial.com>, gharnmons <gharnmons@aoLcom>, rmclean <rmclean@pobox.alaska.net>, mkm7200 <mkm7200@aol.com>, Brian Gillespie <ifbmg@uaa.alaska.edu>, David L Boelens <dboelens@aurorapower.com>, Todd Durkee <TDURKEE@KMG.com>, Gary Schultz <gary_schultz@dnr.state.ak.us>, Wayne Rancier <RANCIER@petro-canada.ca>, Brandon Gagnon <bgagnon@brenalaw.com>, Paul Winslow <pmwinslow@forestoil.com>, Sharrnaine Copeland <copelasv@bp.com>, Kristin Dirks <kristin_dirks@dnr.state.ak.us>, Kaynell Zeman <kjzeman@marathonoil.com>, John Tower <John.Tower@eia.doe.gov>, Bill Fowler <Bill_Fowler@anadarko.COM>, Scott Cranswick <scott.cranswick@mms.gov>, Brad McKim <mckimbs@BP.com>, jack newell <jack.newell@acsalaska.net>, James Scherr <james.scherr@mms.gov>, nI617@conocophillips.com, Tim Lawlor <Tim_Lawlor@ak.blm.gov>, Lynnda Kahn <Lynnda_Kahn@fws.gov>, Jerry Dethlefs <Jerry.C.Dethlefs@conocophillips.com>, crockett@aoga.org, Tamera Sheffield <sheffield@aoga.org>, Jon Goltz <Jon.Goltz@conocophillips.com>, Roger Belman <roger.belman@conocophillips.com>, Mindy Lewis <mlewis@brenalaw.com>, Kari Moriarty <moriarty@aoga.org>, Patty Alfaro <palfaro@yahoo.com>, Jeff <smetankaj@unocaLcom>, Gary Rogers <g~"'T rng..rst/J\r.."..nn.. "t",t.. ",Jr ""~ A ...t"n~ r~~~nl~n < A ....1...._ rv~iìv~·u·11v-,,(ij)W.- W..:I-ll- "tat", ~L- n<:.> y £'>1--1 tAd.J_£.'V _.a. ~.L"''',"",.I...U''''''''.I':'''u....,",.u.J.'\...u..;)-, ..L1.J.I..1.J.U.l ,"-,VPVULV.:) ruU.1UJ._,"", r v"-:7 .....t.a.._.u.1'tr...~, .L:"-_ <klyons@otsintLcom>, Steve Lambert <salambert@unocal.com>, Joe Nicks <news@radiokenai.com>, Jerry McCutcheon <susitnahydronow@yahoo.com>, Bill Walker <bill-wwa@ak.net>, Iris Matthews <Iris_Matthews@legis.state.ak.us>, Paul Decker <paul_decker@dnr.state.ak.us>, Aleutians East Borough <admin@aleutianseast.org>, Marquerite kremer <marguerite_kremer@dnr.state.ak.us>, Mike Mason lof2 3/13/20072:57 PM __.___ _ ___.___~___..~_...__,_~_ __~,__,.-..- ._ ........'L............. ......., ,,___ _.~,,_ "-''-J-'V_ vv¿.." . . <mike@kbbi.org>, Garland Robinson <gbrobinson@marathonoil.com> ~arnmy Taylor <Camille_Taylor@law.state.ak.us>, Thomas E Maunder <tom_maunder@admin.state.ak.us>, Stephen F Davies <steve _ davies@admin.state.ak.us>, Keith Wiles <kwiles@marathonoil.com>, Deanna Gamble <dgamble@kakivik.com>, James B Regg <jimJegg@admin.state.ak.us>, Catherine P Foerster <cathy_foerster@admin.state.ak.us>, Bob <Bob@fairweather.com>, gregory micallef <micallef@clearwire.net>, Laura Silliphant <laura_silliphant@dnr.state.ak.us>, David Steingreaber <david.e.steingreaber@exxonmobil.com>, akpratts@acsalaska.net, Robert Campbell <Robert.Campbell@reuters.com>, Steve Moothart <steve_moothart@dnr.state.ak.us>, Anna Raff <anna.raff@dowjones.com>, Cliff Posey <cliff@posey.org>, Paul Bloom <pauCbloom@ml.com>, Meghan Powell <Meghan.Powell@asrcenergy.com>, Temple Davidson <temple _ davidson@dnr.state.ak. uS>, Walter Featherly <WF eatherIy@PattonBoggs.com>, Tricia Waggoner <twaggoner@nrginc.com>, Mike Stockinger <Mike.Stockinger@anadarko.com>, John Spain <jps@stateside.com>, Cody Rice <Cody_Rice@legis.state.ak.us>, John Garing <garingJD@bp.com>, Harry Engel <engelhr@bp.com>, Jim Winegamer <jimwinegamer@brooksrangepetro.com>, Matt Rader <mattJader@dnr.state.ak.us>, carol smyth <carol.smyth@shell.com>, Arthur C Saltmarsh <art_saltmarsh@admin.state.ak.us>, Chris Gay <cdgay@marathonoil.com>, foms@mtaonline.net, Rudy Brueggeman <rudy.brueggemann@international.gc.ca>, Cary Carrigan <cary@kfqd.com>, Sonja F rankllin <sfi'anklin6@bloomberg.net> Jody Colombie <iody colombie(Zijadmin.state.ak.us> Special Staff Assistant Alaska Oil and Gas Conservation Commission Department of Administration Content-Type: application/pdf aiol-5 cancelled.pdf . Content-Encodmg: base64 Content-Type: application/pdf aio3.15.pdf Content-Encoding: base64 Content-Type: application/pdf aio4e.18.pdf Content-Encoding: base64 Content-Type: application/pdf aio4e-19.pdf Content-Encoding: base64 Content-Type: application/pdf co562-002.pdf Content-Encoding: base64 ~ of2 3/13/20072:57 PM • AlAs[KKA • slfATT[E ® SEAN PARNELL, GOVERNOR ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 C OATS ERQATIO C ISSIOls ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 ADMINISTRATIVE APPROVALS CONSERVATION ORDER 432D.010 — KUPARUK RIVER UNIT: KUPARUK RIVER OIL POOL CONSERVATION ORDER 406B.010 — KUPARUK RIVER UNIT: WEST SAK OIL POOL CONSERVATION ORDER 430A.009 — KUPARUK RIVER UNIT: TARN OIL POOL CONSERVATION ORDER 435A.008 — KUPARUK RIVER UNIT: TABASCO OIL POOL CONSERVATION ORDER 456A.008 — KUPARUK RIVER UNIT: MELTWATER OIL POOL CONSERVATION ORDER 443B.001 — COLVILLE RIVER UNIT: ALPINE OIL POOL CONSERVATION ORDER 562.003 — COLVILLE RIVER UNIT: NANUQ OIL POOL CONSERVATION ORDER 569.002 — COLVILLE RIVER UNIT: FIORD OIL POOL CONSERVATION ORDER 605.001— COLVILLE RIVER UNIT: QANNIK OIL POOL Mr. James Rodgers GKA Development Manager ConocoPhillips Alaska, Inc. 700 G Street Anchorage, AK 99501 Re: Request for Authorization to use MPM Multiphase Metering Systems for Well Testing and Production Allocation at ConocoPhillips Alaska, Inc. Operated Pools Mr. Rodgers: By letter dated December 14, 2010, ConocoPhillips Alaska, Inc. (CPAI), as the operator of the Kuparuk River Unit (KRU) and Colville River Unit (CRU), submitted an application report for the MPM Multiphase Metering System (MPM) and requested the Alaska Oil and Gas Conservation Commission (Commission) authorize use of the MPM for well testing and production allocation within the KRU and CRU. CPAI's request is GRANTED with the conditions below. The MPM, developed by Multi Phase Meters AS via a multi -year joint industry project involving ConocoPhillips and other major oil and gas companies, has undergone extensive laboratory and field testing. A key component of the MPM is the 3DBroadBand section, which uses a radio frequency (RF) based technique to take measurements of the flow through the sensor on many different planes. The RF readings, combined with readings from a salinity probe and gamma ray absorption measurements, create a three dimensional picture of the flow through the meter and the composition of the flow stream. This information is combined with a mass flow rate obtained from a venturi meter to give accurate flow rates for oil, gas, and water. A key feature of the MPM system is the ability to switch from a multiphase meter to a wet gas meter automatically and very rapidly. This feature is particularly beneficial when measuring production streams experiencing slugging flow. Tests show that the MPM provides acceptable accuracy under these conditions without the need for a slug catcher or partial separation. The MPM has been subjected to extensive product development, laboratory testing, and several field trials, including one conducted at CD -1 in the CRU in March and April 2010. For this test a 3" MPM was installed upstream of the two phase test separator normally used for well testing and allocation. The results between the two systems were compared. The test was a blind test in which those monitoring and operating the MPM were not shown the results coming from the conventional test separator, which provided "out of the box" results for the meter. A total of 80 well tests were conducted on 16 different production wells during the field trial. The range C0432D -010, C0406B -010 • • C0430A -009, C0435A -008 C0456A -008, C0443B -001 CO562 -003, CO569 -002, C0605 -001 June 20, 2011 Page 2of3 of flow characteristics for these wells were fluid flow rates from 300 BPD to 5,200 BPD, gas flow rates from 4 MMSCFPD to 8 MMSCFPD, water cut from 19% to 95 %, and GVF from 88 -90 %. The raw data collected from the field trials indicated that, as compared to the two phase test separator, the MPM under -read total liquid by 4.7 %, oil by 3.7 %, water by 5.4 %, and water cut by 0.4% while over reading gas by 7.3 %. However, Multi Phase Meters AS reviewed the raw data and determined that due to the size of meter selected that two wells slugged sufficiently to over -range the differential pressure cell. Multi Phase Meters AS also found the gas density provided for the calculation of gas flow rate was significantly different from what the meter's densitometer was reading. When the over - ranged test results were removed and the gas density used to calculate gas flow rate was corrected, the measured difference of the MPM was significantly reduced as compared to the two phase test separator. After the MPM data was reprocessed, the MPM meter under -read total liquids by 2.6 %, oil by 2.1 %, water by 3 %, water cut by 0.2% and gas by 0.4 %. Although the reprocessed results show all components were under -read, the individual test data indicate no definitive bias towards under- or over - reporting. The appearance of under - reporting in this instance could be a function of the duration of the field trial and the wells that were tested. Since the MPM will be used for well testing and allocation purposes a slight bias in one direction or the other would not be significant due to application of an allocation factor to adjust the test results to match the results obtained from the custody transfer meter. The results obtained during the CRU field trials are comparable to results obtained during other laboratory / field trials of the MPM, demonstrating the MPM's reliability and accuracy over a wide range of flow conditions and fluid properties. Tests have covered everything from heavy oil (163 cP at 20° C) to light condensate (120° API gravity) with water cuts and GVFs from 0% to 100 %, pressures from 75 to 3,000 psi, temperatures from 60° F to 130° F, and liquid and gas rates up to 30 MPBD and 230 MMCFPD, respectively. The publically released test data indicate the liquid and gas rates are typically within +/- 3% and +/- 2 %, respectively, of the reference test separator. The fluid and flow properties for the KRU and CRU pools fall well within this performance envelope establishing that an appropriately sized MPM can be utilized for well testing and production allocation purposes at any of these pools. The Commission finds that CPAI's request is based on sound engineering principles and will not promote waste or jeopardize correlative rights. Therefore, the Commission approves CPAI's request for authorization to use the MPM Multiphase Metering System for well testing and production allocation in the above - referenced oil pools subject to the following conditions: 1) This approval is for well testing and production allocation purposes only. The MPM is NOT approved for custody transfer or fiscal allocation purposes. 2) Before a new MPM can be put into service for well testing and production allocation purposes CPAI must provide notification to the Commission of the location of the new system (i.e. at which facility and /or drill site) and the pool(s) for which it will be used. 3) The MPM must be installed, operated, maintained, and calibrated in accordance with the manufacturer's requirements. 4) In addition to the above referenced pools, the MPM is approved for well testing and production allocation from as yet undefined pools that CPAI may operate, provided that: C0432D -010, C0406B -010 • • C0430A -009, C0435A -008 C0456A -008, C0443B -001 CO562 -003, CO569 -002, C0605 -001 June 20, 2011 Page 3 of 3 a. CPAI obtains all approvals necessary from any other agency that may have statutory or regulatory jurisdiction over well testing and production allocation for the as yet undefined pool; b. CPAI demonstrates that the expected fluid characteristics and flow properties of the as yet undefined pool are within the performance envelope that has been established for the MPM Multiphase Metering System; and c. CPAI references this administrative approval in its application for pool rules for the as yet undefined pool. t►v,p■SKA 04 DONE at Anchorage, Alaska and dated June 21 1 .. ' Ar: ik ` 1 ✓.:,,a c++ Daniel T. Seamount, Jr. Wit frrm.� Cathy P. Foers er Chair, Commissioner Issio Comm ssioner 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 Commission grants for good cause shown, a person affected by it may file with the Commission 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 Commission 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 Commission 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 Commission mails, OR 30 days if the Commission 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 Commission 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 Commission, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited to the questions presented to the Commission by the application for 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. • • Fisher, Samantha J (DOA) From: Fisher, Samantha J (DOA) Sent: Monday, June 20, 2011 4:55 PM To: '( michael .j.nelson @conocophillips.com)'; '(Von.L .Hutchins @conocophillips.com)'; 'AKDCWelllntegrityCoordinator; 'Alan Dennis'; 'alaska @petrocalc.com'; 'Anna Raff; 'Barbara F Fullmer'; 'bbritch'; 'Becky Bohrer; 'Bill Penrose; 'Bill Walker; 'Bowen Roberts'; 'Brady, Jerry L'; 'Brandon Gagnon'; 'Brandow, Cande (ASRC Energy Services)'; 'Brian Havelock'; 'Bruce Webb'; 'caunderwood'; 'Chris Gay'; Cliff Posey'; 'Crandall, Krissell'; 'D Lawrence'; 'dapa'; 'Daryl J. Kleppin'; 'Dave Matthews'; 'David Boelens'; 'David House'; 'David Scott'; 'David Steingreaber'; 'ddonkel @cfl.rr.com'; 'Dennis Steffy'; 'Elizabeth Bluemink'; 'Elowe, Kristin'; 'Erika Denman'; 'eyancy'; 'Francis S. Sommer; 'Fred Steece'; 'Garland Robinson'; 'Gary Laughlin'; 'Gary Schultz (gary.schultz @alaska.gov)'; 'ghammons'; 'Gordon Pospisil'; 'Gorney, David L.'; 'Greg Duggin'; 'Gregg Nady'; 'gspfoff; 'Harry Engel'; 'Jdarlington (jarlington @gmail.com)'; 'Jeanne McPherren'; 'Jeff Jones'; 'Jeffery B. Jones (jeff.jones @alaska.gov)'; 'Jerry McCutcheon'; 'Jill Womack'; 'Jim White'; 'Jim Winegarner'; 'Joe Nicks'; 'John Garing'; 'John Katz (john.katz @alaska.gov)'; 'John S. Haworth'; 'John Spain'; 'John Tower'; 'Jon Goltz'; 'Judy Stanek'; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; 'Kelly Sperback'; 'Kim Cunningham'; 'Larry Ostrovsky'; 'Laura Silliphant (laura.gregersen @alaska.gov)'; 'Marilyn Crockett'; 'Mark Dalton'; 'Mark Hanley (mark.hanley @anadarko.com)'; 'Mark Kovac'; 'Mark P. Worcester'; 'Marguerite kremer (meg.kremer @alaska.gov)'; 'Michael Dammeyer'; 'Michael Jacobs'; 'Mike Bill'; 'Mike Mason'; 'Mikel Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'nelson'; 'Nick W. Glover'; 'NSK Problem Well Supv'; 'Patty Alfaro'; 'Paul Decker (paul.decker @alaska.gov)'; 'Paul Figel'; 'PORHOLA, STAN T'; 'Randall Kanady'; 'Randy L. Skillern'; 'Rena Delbridge'; 'Renan Yanish'; ' rob.g.dragnich @exxonmobil.com'; 'Robert Brelsford'; 'Robert Campbell'; 'Rudy Brueggeman'; 'Ryan Tunseth'; 'Scott Cranswick'; 'Scott Griffith'; 'Shannon Donnelly'; 'Sharmaine Copeland'; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); 'Sondra Stewman'; 'Steve Lambert'; 'Steve Moothart (steve.moothart @alaska.gov)'; 'Steven R. Rossberg'; 'Suzanne Gibson'; 'tablerk'; 'Tamera Sheffield'; Taylor, Cammy 0 (DNR); 'Temple Davidson'; 'Teresa Imm'; 'Terrie Hubble'; 'Thor Cutler'; 'Tina Grovier'; 'Todd Durkee'; 'Tony Hopfinger'; 'trmjrl'; 'Vicki Irwin'; 'Walter Featherly'; 'Will Chinn'; Williamson, Mary J (DNR); 'Yereth Rosen'; 'Aaron Gluzman'; 'Ben Greene'; Bruno, Jeff J (PCO); 'Dale Hoffman'; 'David Lenig'; 'Donna Vukich'; 'Eric Lidji'; 'Gary Orr'; Heusser, Heather A (DNR); 'Jason Bergerson'; 'Joe Longo'; King, Kathleen J (DNR); 'Lara Coates'; 'Lois Epstein'; 'Marc Kuck'; 'Marie Steele'; 'Mary Aschoff; 'Matt Gill'; 'Maurizio Grandi'; Ostrovsky, Larry Z (DNR); 'Patricia Bettis'; 'Richard Garrard'; 'Ryan Daniel'; 'Sandra Lemke'; 'Talib Syed'; 'Wayne Wooster'; 'Wendy Wollf; 'William Van Dyke'; Aubert, Winton G (DOA) (winton.aubert@alaska.gov); Ballantine, Tab A (LAW); Brooks, Phoebe L (DOA) (phoebe.brooks @alaska.gov); Colombie, Jody J (DOA) (jody.colombie @alaska.gov); Crisp, John H (DOA) (john.crisp @alaska.gov); Davies, Stephen F (DOA) (steve.davies @alaska.gov); Foerster, Catherine P (DOA) (cathy.foerster @alaska.gov); Grimaldi, Louis R (DOA) (lou.grimaldi @alaska.gov); Herrera, Matt F (DOA); Johnson, Elaine M (DOA) (elaine.johnson @alaska.gov); Jones, Jeffery B (DOA) (jeff.jones @alaska.gov); Laasch, Linda K (DOA) (linda.laasch @alaska.gov); Maunder, Thomas E (DOA) (tom.maunder @alaska.gov); McIver, Bren (DOA) (bren.mciver @alaska.gov); McMains, Stephen E (DOA) (steve.mcmains @alaska.gov); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA) (bob.noble @alaska.gov); Norman, John K (DOA) (john.norman @alaska.gov); Okland, Howard D (DOA) (howard.okland @alaska.gov); Paladijczuk, Tracie L (DOA) ( tracie.paladijczuk @alaska.gov); Pasqual, Maria (DOA) (maria.pasqual @alaska.gov); Regg, James B (DOA) (jim.regg @alaska.gov); Roby, David S (DOA) (dave.roby @alaska.gov); Saltmarsh, Arthur C (DOA) (art.saltmarsh @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) Subject: co432d -010, co406b -010, co430a -009, co435a -008, co456a -008, co443b -001, co562 -003, co569 -002, co605 -001 (Kuparuk and Colville) Attachments: co605- 001.pdf 1 0 • Mary Jones David McCaleb XTO Energy, Inc. IHS Energy Group George Vaught, Jr. Cartography GEPS P.O. Box 13557 810 Houston Street, Ste 200 5333 Westheimer, Suite 100 Denver, CO 80201 -3557 Ft. Worth, TX 76102 -6298 Houston, TX 77056 Jerry Hodgden Richard Neahring Mark Wedman Hodgden Oil Company NRG Associates Halliburton 408 18 Street President 6900 Arctic Blvd. Golden, CO 80401 -2433 P.O. Box 1655 Anchorage, AK 99502 Colorado Springs, CO 80901 Bernie Karl CIRI Baker Oil Tools K &K Recycling Inc. Land Department 795 E. 94 Ct. P.O. Box 58055 P.O. Box 93330 Anchorage, AK 99515 -4295 Fairbanks, AK 99711 Anchorage, AK 99503 North Slope Borough Richard Wagner Gordon Severson Planning Department P.O. Box 60868 3201 Westmar Circle P.O. Box 69 Fairbanks, AK 99706 Anchorage, AK 99508 -4336 Barrow, AK 99723 Jack Hakkila Darwin Waldsmith James Gibbs P.O. Box 190083 P.O. Box 39309 P.O. Box 1597 Anchorage, AK 99519 Ninilchick, AK 99639 Soldotna, AK 99669 Kenai National Wildlife Refuge Penny Vadla Cliff Burglin Refuge Manager 399 West Riverview Avenue 319 Charles Street P.O. Box 2139 Soldotna, AK 99669 -7714 Fairbanks, AK 99701 Soldotna, AK 99669 -2139 4a `> i , . 1 , THE STATE 01ALAJl\!'1 GOVERNOR BILL WALKER Ms. Misty Alexa Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL CONSERVATION ORDER NO.562.004 CONSERVATION ORDER NO.569.003 CONSERVATION ORDER NO.605.002 Manager, WNS Development ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: CO-15-007 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Request for administrative approval to waive the monthly production allocation reporting requirement for the Nanuq Oil Pool, Fiord Oil Pool, and Qannik Oil Pool in the Colville River Field. Dear Ms. Alexa: By letter dated June 16, 2015, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to waive the requirement for monthly reporting of daily allocation and test data contained in Rule 7(e) of Conservation Order No. (CO) 562 and Rule 6(e) of CO's 569 and 605. In accordance with Rule 12 of the orders, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request for administrative approval to waive the requirement to submit monthly reports of daily allocation and test data. Rule 7 of CO 562 and rule 6 of COs 569 and 602 states: (e) The operator shall submit a monthly report and electronic file(s) containing daily allocation data and daily test data for agency surveillance and evaluation. Part (f) of these rules require an annual allocation review report accompany the annual reservoir surveillance report. Receiving an annual report on the production allocation and well test data 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. Now therefore it is ordered that part (e) of rule 7 of CO 562 and Rule 6 of COs 569 and 602 are revised as follows: CO 562.004, CO 569.003, & CO 605.002 August 6, 2015 Page 2 of 2 (e) the operator shall retain electronic file(s) containing daily allocation data and daily test data for a minimum of five years. DONE at Anchorage, Alaska and dated August 6, 2015. Cathy, . Foerster Daniel T. Seardount, Jr. Chair, Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Singh, Angela K (DOA) From: Carlisle, Samantha J (DOA) Sent: Friday, August 07, 2015 12:36 PM To: AKDCWellIntegrityCoordinator, Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew VanderJack; Anna Raff; Barbara F Fullmer, bbritch; Becca Hume; 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; 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; Tony Hopfinger; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Walter Featherly; 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; 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; 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 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: Angela K (DOA); Wallace, Chris D (DOA) Subject: CO 569.003, CO 605.002, CO 562.004 (Colville River Field) Attachments: co569-003.pdf, co605-002.pdf, co562-004.pdf Please see attached. Samantha Carlisle Executive Secretary II Alaska Oil and Gas Conservation Commission 333 West 7tt, Avenue Anchorage, AK 99501 (907) 793-1223 (phone) (907) 276-7542 (fax) 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.Carlisle@alaska.gov. 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 Ms. Misty Alexa Richard Wagner Darwin Waldsmith Manager, WNS Development P.O. Box 60868 P.O. Box 39309 ConocoPhillips Alaska, Inc. Fairbanks, AK 99706 Ninilchik, AK 99639 P.O. Box 100360 Anchorage, AK 99510-0360 -7t 201z�z, Angela K. Singh ..�..._-,.-.. hi :—tA Lei� T H1-. S AIE ALASKA GOVERNOR BILL WALKER Ms. Misty Alexa Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL CONSERVATION ORDER NO.562.004 CONSERVATION ORDER NO. 569.003 CONSERVATION ORDER NO. 605.002 (Corrected) Manager,'WNS Development ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: CO-15-007 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.alaska.gov Request for administrative approval to waive the monthly production allocation reporting requirement for the Nanuq Oil Pool, Fiord Oil Pool, and Qannik Oil Pool in the Colville River Field. Dear Ms. Alexa: It has come to the attention of the AOGCC that the Conservation Order number that was used through this order was incorrect, it has now been corrected. By letter dated June 16, 2015, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to waive the requirement for monthly reporting of daily allocation and test data contained in Rule 7(e) of Conservation Order No. (CO) 562 and Rule 6(e) of CO's 569 and 605. In accordance with Rule 12 of the orders, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request for administrative approval to waive the requirement to submit monthly reports of daily allocation and test data. Rule 7 of CO 562 and rule 6 of COs 569 and 605 states: (e) The operator shall submit a monthly report and electronic file(s) containing daily allocation data and daily test data for agency surveillance and evaluation. Part (f) of these rules require an annual allocation review report accompany the annual reservoir surveillance report. Receiving an annual report on the production allocation and well test data 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. CO 562.004, CO 569.003, & CO 605.002 (Cotrected) August 19, 2015 Page 2 of 2 Now therefore it is ordered that part (e) of rule 7 of CO 562 and Rule 6 of COS 569 and 605 are revised as follows: (e) the operator shall retain electronic file(s) containing daily allocation data and daily test data for a minimum of five years. DONE at Anchorage, Alaska and dated August 19, 2015. Nunc pro tune August Cath P. Foerster Daniel T. Sear6ount, Jr. r Chair, Commissioner Commissioner :. RECONSIDERATION AND APPEAL NOTICE "I--!_f " rti 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: Colombie, Jody J (DOA) Sent: Wednesday, August 19, 2015 1:52 PM To: Ballantine, Tab A (LAW); Bender, Makana K (DOA); Bettis, Patricia 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, Micha) (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, Angela K (DOA); Wallace, Chris D (DOA); AKDCWellIntegrityCoordinator, Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew Vandedack; Anna Raff; Barbara F Fullmer, bbritch; Becca Hume; 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 Qarlington@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; 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: Corrected CO 605-002 Attachments: co605-002 corrected.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 Ms. Misty Alexa Richard Wagner Darwin Waldsmith Manager, WNS Development P.O. Box 60868 P.O. Box 39309 ConocoPhillips Alaska, Inc. Fairbanks, AK 99706 Ninilchik, AK 99639 P.O. Box 100360 Anchorage, AK 99510-0360 V-0c.�ue�-' All 2o1S Angela K. Singh THE STATE °fALASKA GOVERNOR BILL WALKER Mr. Stephen Thatcher Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVALS CONSERVATION ORDER NO. 443C.001 CONSERVATION ORDER NO. 562.005 CONSERVATION ORDER NO. 569.004 CONSERVATION ORDER NO. 605.003 Manager, WMS Development North Slope Operations and Development ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510 Re: Docket Number: CO -18-002 and AIO-18-014 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Request for administrative approval to amend allowable gas offtake for the Colville River Field and authorize surface commingling of production from the Lookout Oil Pool with production from the Fiord and Qannik Oil Pools. Colville River Field Colville River Unit Alpine Oil Pool Nanuq Oil Pool Fiord Oil Pool Qannik Oil Pool Dear Mr. Thatcher: By letter dated February 28, 2018, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to amend the allowable gas offtake rate established for the Colville River Field (CRF) to increase the allowable rate from 1 MMSCFPD to 7 MMSCFPD to allow for development of the Lookout Oil Pool (LOP) in the Greater Moose's Tooth Unit (GMTU). By a different letter also dated February 28, 2018, CPAI requested administrative approval to amend the Common Production Facilities and Surface Commingling rules for the Fiord and Qannik Oil Pools to allow commingling production on the surface with production from the LOP.' ' The Alpine and Nanuq Oil Pools pool rules do not contain a rule that would preclude commingling those pools with the LOP. CO 443C.001, CO 562.005, CO 569.004, and CO 650.003 August 13, 2018 Page 2 of 4 In accordance with Rule 11 of Conservation Order No. (CO) 443C and Rule 12 of COs 562, 569, and 605, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request to increase the allowable gas offtake rate from the CRF. On February 13, 2007, the Alaska Oil and Gas Conservation Commission (AOGCC) authorized a I MMSCFPD gas offtake from the CRF for the sole purpose of meeting contractual obligations to ship gas from the CRF to the village ofNuigsut. CPAI plans to begin production from the LOP in GMTU in late 2018 and has requested authority to ship gas from the CRF to the GMTU to support LOP development. The LOP is expected to routinely produce significant excess gas that will be shipped, along with the produced oil and water, to the Alpine Central Facility (ACF) where the gas will be returned to the LOP, used for lease operations within the CRF, or injected into the pools in the CRF for EOR purposes. However, prior to initial production the GMTU facilities may take gas from the CRF to pack production lines and/or heat facilities. Additionally, after production commences there may be periods when LOP development switches from water to gas injection when the gas needs of the LOP enhanced oil recovery project exceeds the volume of gas being produced from the LOP resulting in the LOP needing to purchase extra gas from the CRF. Over its life the LOP is expected to produce nearly 40 BCF more gas than it 'Ail] need for lease usage and EOR injection. This excess gas will be used in the CRF for EOR injection projects in the CRF's oil pools. Because this excess gas from the LOP will be used for EOR purposes in the CRF, the net benefit in oil production from the CRF will far outweigh the temporary delay in recovery that would be associated with shipping gas from the CRF to the GMTU. The Fiord and Qannik Oil Pools are currently authorized to commingle production on the surface with production from other CRF oil pools. These rules need to be amended to allow the LOP production to be commingled as well. The LOP is an Alpine formation reservoir. As such, production from the LOP should be compatible with the CRF oil pools. The administrative action rules for the affected orders allow the AOGCC to amend an order administratively if the proposed action will not result in waste, will not jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in increased risk of fluid movement into freshwater. Waste is prevented because the long-term benefits of using the gas from the LOP for EOR purposes in the CRF far outweigh the short-term and largely negligible impacts of periodically shipping small volumes of gas from the CRF to the GMTU to support LOP development. Correlative rights are protected because all of the affected pools are within the Colville River Unit. Selling small volumes of gas from the CRF to the GMTU is based on sound engineering and geoscience practices because the sharing of production facilities and infrastructure will lessen environmental impacts and increase ultimate recovery through the sharing of expenses. Selling gas from one unit to another has no impacts on the risk of fluids moving into freshwater. CO 443C.001, CO 562.005, CO 569.004, and CO 650.003 August 13, 2018 Page 3 of 4 Now therefore it is ordered that Rule 12 of CO 443C and Rule 11 of CO 605 are amended to read as follows: Allowable Gas Offfake 1. The cumulative gas offtake rate from the CRF must not exceed 7 MMCFPD. 2. Natural gas may not be severed from the CRF for any other purpose than to meet ConocoPhillips' contractual obligations of providing the Village of Nuiqsut with natural gas and to support development of the Lookout Oil Pool in the Greater Moose's Tooth Unit. 3. Any new pools that process production at the ACF will be subject to the terms of this administrative approval. The conditions of approval in CO 562.001 and 569.001 are amended to read as follows: 1. The cumulative gas off take rate from the CRF must not exceed 7 MMCFPD. 2. Natural gas may not be severed from the CRF for any other purpose than to meet ConocoPhillips' contractual obligations of providing the Village of Nuiqsut with natural gas and to support development of the Lookout Oil Pool in the Greater Moose's Tooth Unit. 3. Any new pools that process production at the ACF will be subject to the terms of this administrative approval. Rule 6 of CO 569 is amended to read as follows: Rule 6 Common Production Facilities and Surface Commin¢line a. Production from the Fiord Oil Pool may be commingled with production from other CRU pools and the Lookout Oil Pool in surface facilities prior to custody transfer. b. Production shall be allocated to wells within the Fiord Oil Pool in accordance with the procedures described in Section 5.0 of ConocoPhillips' application dated November 22, 2005. c. Each producing well must be tested a minimum of twice per month. d. The Commission may require more frequent or longer tests if the allocation quality deteriorates. e. The operator shall retain electronic file(s) containing daily allocation data and daily test data for a minimum of five years. f The operator shall provide the Commission with a well test and allocation review report in conjunction with an annual reservoir surveillance report. CO 443C.001, CO 562.005, CO 569.004, and CO 650.003 August 13, 2018 Page 4 of 4 And Rule 6 of CO 605 is amended to read as follows: Rule 6 Common Production Facilities and Surface Commingling a. Production from the Qannik Oil Pool and other CRU pools and the Lookout Oil Pool may be commingled in surface facilities prior to custody transfer. b. Production shall be allocated to wells within the Qannik Oil Pool in accordance with the procedures described in Section 6.0 of CPAI's application, dated April 3, 2008. c. Each producing well must be tested a minimum of twice per month. d. The Commission may require more frequent or longer testing if the allocation quality deteriorates. e. The operator shall retain electronic file(s) containing daily allocation data and daily test data for a minimum of five years. f. The operator shall provide the Commission an annual well test and allocation review report in conjunction with the annual reservoir surveillance report required under Rule 9 (below). DONE at Anchorage, Alaska and dated August 13, 2018. Hollis S. French Cath P. oerster Daniel T. Seamount, Jr. Chair, Commissioner Commissioner Commissioner NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. if the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default afterwhich the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. 1'l 11: S l .,v11{ ( ALASKA (Ii)NIION( I. 1l111 �"AIGIP Mr. Stephen Thatcher Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVALS CONSERVATION ORDER NO. 443C.001 CONSERVATION ORDER NO. 562.005 CONSERVATION ORDER NO. 569.004 CONSERVATION ORDER NO. 605.003 Manager, WMS Development North Slope Operations and Development ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510 Re: Docket Number: CO -18-002 and AIO-18-014 333 west Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 aogcc.oloska.gov Request for administrative, approval to amend allowable gas offtake for the Colville River Field and authorize surface commingling of production from the Lookout Oil Pool with production from the Fiord and Qannik Oil Pools. Colville River Field Colville River Unit Alpine Oil Pool Nanuq Oil Pool Fiord Oil Pool Qannik Oil Pool Dear Mr. Thatcher: By letter dated February 28, 2018, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to amend the allowable gas offtake rate established for the Colville River Field (CRF) to increase the allowable rate from 1 MMSCFPD to 7 MMSCFPD to allow for development of the Lookout Oil Pool (LOP) in the Greater Moose's Tooth Unit (GMTU). By a different letter also dated February 28, 2018, CPAI requested administrative approval to amend the Common Production Facilities and Surface Commingling rules for the Fiord and Qannik Oil Pools to allow commingling production on the surface with production from the LOP.' 1 The Alpine and Nanuq Oil Pools pool rules do not contain a rule that would preclude commingling those pools with the LOP. CO 443C.001, CO 562.005, CO 569.004, and CO 650.003 August 13, 2018 Page 2 of 4 In accordance with Rule 11 of Conservation Order No. (CO) 443C and Rule 12 of COs 562, 569, and 605, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request to increase the allowable gas offtake rate from the CRF. On February 13, 2007, the Alaska Oil and Gas Conservation Commission (AOGCC) authorized a 1 MMSCFPD gas offtake from the CRF for the sole purpose of meeting contractual obligations to ship gas from the CRF to the village of Nuiqsut. CPAI plans to begin production from the LOP in GMTU in late 2018 and has requested authority to ship gas from the CRF to the GMTU to support LOP development. The LOP is expected to routinely produce significant excess gas that will be shipped, along with the produced oil and water, to the Alpine Central Facility (ACF) where the gas will be returned to the LOP, used for lease operations within the CRF, or injected into the pools in the CRF for EOR purposes. However, prior to initial production the GMTU facilities may take gas from the CRF to pack production lines and/or heat facilities. Additionally, after production commences there may be periods when LOP development switches from water to gas injection when the gas needs of the LOP enhanced oil recovery project exceeds the volume of gas being produced from the LOP resulting in the LOP needing to purchase extra gas from the CRF. Over its life the LOP is expected to produce nearly 40 BCF more gas than it will need for lease usage and EOR injection. This excess gas will be used in the CRF for EOR injection projects in the CRF's oil pools. Because this excess gas from the LOP will be used for EOR purposes in the CRF, the net benefit in oil production from the CRF will far outweigh the temporary delay in recovery that would be associated with shipping gas from the CRF to the GMTU. The Fiord and Qannik Oil Pools are currently authorized to commingle production on the surface with production from other CRF oil pools. These rules need to be amended to allow the LOP production to be commingled as well. The LOP is an Alpine formation reservoir. As such, production from the LOP should be compatible with the CRF oil pools. The administrative action rules for the affected orders allow the AOGCC to amend an order administratively if the proposed action will not result in waste, will not jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in increased risk of fluid movement into freshwater. Waste is prevented because the long-term benefits of using the gas from the LOP for EOR purposes in the CRF far outweigh the short-term and largely negligible impacts of periodically shipping small volumes of gas from the CRF to the GMTU to support LOP development. Correlative rights are protected because all of the affected pools are within the Colville River Unit. Selling small volumes of gas from the CRF to the GMTU is based on sound engineering and geoscience practices because the sharing of production facilities and infrastructure will lessen environmental impacts and increase ultimate recovery through the sharing of expenses. Selling gas from one unit to another has no impacts on the risk of fluids moving into freshwater. CO 443C.001, CO 562.005, CO 569.004, and CO 650.003 August 13, 2018 Page 3 of 4 Now therefore it is ordered that Rule 12 of CO 443C and Rule 11 of CO 605 are amended to read as follows: Allowable Gas Offrake 1. The cumulative gas offtake rate from the CRF must not exceed 7 MMCFPD. 2. Natural gas may not be severed from the CRF for any other purpose than to meet ConocoPhillips' contractual obligations of providing the Village of Nuiqsut with natural gas and to support development of the Lookout Oil Pool in the Greater Moose's Tooth Unit. 3. Any new pools that process production at the ACF will be subject to the terms of this administrative approval. The conditions of approval in CO 562.001 and 569.001 are amended to read as follows: 1. The cumulative gas off take rate from the CRF must not exceed 7 MMCFPD. 2. Natural gas may not be severed from the CRF for any other purpose than to meet ConocoPhillips' contractual obligations of providing the Village of Nuiqsut with natural gas and to support development of the Lookout Oil Pool in the Greater Moose's Tooth Unit. 3. Any new pools that process production at the ACF will be subject to the terms of this administrative approval. Rule 6 of CO 569 is amended to read as follows: Rule 6 Common Production Facilities and Surface Commin¢lina a. Production from the Fiord Oil Pool may be commingled with production from other CRU pools and the Lookout Oil Pool in surface facilities prior to custody transfer. b. Production shall be allocated to wells within the Fiord Oil Pool in accordance with the procedures described in Section 5.0 of ConocoPhillips' application dated November 22, 2005. c. Each producing well must be tested a minimum of twice per month. d. The Commission may require more frequent or longer tests if the allocation quality deteriorates. e. The operator shall retain electronic file(s) containing daily allocation data and daily test data for a minimum of five years. f. The operator shall provide the Commission with a well test and allocation review report in conjunction with an annual reservoir surveillance report. CO 443C.001, CO 562.005, CO 569.004, and CO 650.003 August 13, 2018 Page 4 of 4 And Rule 6 of CO 605 is amended to read as follows: Rule 6 Common Production Facilities and Surface Commin¢line a. Production from the Qannik Oil Pool and other CRU pools and the Lookout Oil Pool may be commingled in surface facilities prior to custody transfer. b. Production shall be allocated to wells within the Qannik Oil Pool in accordance with the procedures described in Section 6.0 of CPAI's application, dated April 3, 2008. c. Each producing well must be tested a minimum of twice per month. d. The Commission may require more frequent or longer testing if the allocation quality deteriorates. e. The operator shall retain electronic file(s) containing daily allocation data and daily test data for a minimum of five years. f. The operator shall provide the Commission an annual well test and allocation review report in conjunction with the annual reservoir surveillance report required under Rule 9 (below). DONE at Anchorage, Alaska and dated August 13, 2018. //signature on file// //signature on file// //signature on file// Hollis S. French Cathy P. Foerster Daniel T. Seamount, Jr. Chair, Commissioner Commissioner Commissioner As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration most set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. if the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which can the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Penny Vadla 399 W. Riverview Ave. Soldotna, AK 99669-7714 George Vaught, Jr. Darwin Waldsmith Richard Wagner P.O. Box 13557 P.O. Box 39309 P.O. Box 60868 Denver, CO 80201-3557 Ninilchik, AK 99639 Fairbanks, AK 99706 ConocoPhillips February 28, 2018 Stephen Thatcher Manager, WNS Development North Slope Operations and Development ConocoPhillips Alaska, Inc. ATO -1770 700 G Street Anchorage, AK 99501 phone 907.263.4464 C`vU Hollis French, Chair MARL 0 1 2018 Alaska Oil and Gas Conservation Commissionat 333 W. 7th Ave #100 � _50C Anchorage, Alaska, 99501-3539 RE: Application to Amend Allowable Gas Offtake Rate, Colville River Unit, North Slope, AK Dear Commissioner French, ConocoPhillips Alaska, Inc. ("CPA[") as operator of the Colville River Unit ("CRU") and Greater Mooses Tooth Unit ("GMTU"), requests that the Alaska Oil and Gas Conservation Commission ("Commission") approve CPAI's application to amend the Allowable Gas Off Take Rate from the CRU to allow CRU gas to be transferred to the Greater Mooses Tooth Unit (GMTU). This application is being made concurrently with applications for GMTU Lookout Oil Pool applications for Conservation Orders and Area Injection Orders. Enclosed are two printed originals of this application for expanded gas offtake and a disc containing an electronic version of the application. Please contact John Cookson (265-6547) if you have questions or require additional information. Regards, Stephen Thatcher Manager, WNS Development North Slope Operations and Development Cc: Land Manager - Alaska, Anadarko E&P Onshore LLC Bruce W. Hunt, Petro -Hunt LLC Enclosures (3) Application to Amend CRU AGOTR February 28, 2018 Page 2 of 5 APPLICATION TO AMEND THE ALLOWABLE GAS OFF TAKE RATE COLVILLE RIVER UNIT Request for Expanded Offtake This application is submitted for approval by the Alaska Oil and Gas Conservation Commission ("Commission") to amend the Allowable Gas Off Take Rate ("AGOTR") for the Colville River Unit ("CRU") to provide gas to the Greater Mooses Tooth Unit Lookout Oil Pool ("GMTU"). The current AGOTR for all CRU participating areas is 1 MMCFPD, as set forth in Administrative Approval Nos.443A.003, 562.001, 563.001, 569.001, and CO 605. ConocoPhillips Alaska, Inc. ("CPAI") as operator of the CRU and GMTU, requests that the Commission amend the AGOTR from the CRU to a maximum of a monthly cumulative volume of 7 million standard cubic feet per day ("MMCFPD") to provide 1 MMCFPD to the Village of Nuiqsut and on an as needed basis up to 6 MMCFPD to the GMTU for intermittent operational needs. It is also requested that this AGOTR apply to all currently defined pools within the CRU and any future pools that commingle production at the Alpine Central Facility ("ACF"). Background The Commission has approved an AGOTR not to exceed 1 MMCFPD from the "Colville River Field" for the purposes of providing the Village of Nuiqsut with natural gas. See, e.g., Administrative Approval No. 443A.003. In addition, the AGOTR applies to any new pools that process production at the ACF. Id. The current pools processing production from the ACF are the Alpine Oil Pool (which includes the Kuparuk oil pool), Fiord Oil Pool, Nanuq Oil Pool and Qannik Oil Pool. As a frame of reference, CRU provided 0.4 MMCFPD to the Village of Nuiqsut during November 2017. Production from the CRU pools is commingled and processed at the ACF. All of the commingled gas is either consumed within the CRU for operational purposes, re -injected to enhance oil recovery from the CRU, or provided to the Village of Nuiqsut. Gas production from all CRU oil pools was 67.3 MMCFD during the month of November 2017. The GMTU will begin production into the ACF in late 2018 as described in the Lookout Oil Pool Conservation and Area Injection Order applications that are submitted concurrently with this application. GMTU gas production will be sent to ACF for processing. Gas needed for GMTU operations will be returned to GMTU, any excess GMTU gas after accounting for GMTU's share of fuel and flare will be injected into CRU participating areas. GMTU Requirement for Gas from the CRU Production from the GMTU is expected to generate significant excess gas. In most instances, the amount of GMTU Return Gas will be more than enough to provide for the gas requirements of the GMTU. CPAI estimates that approximately 38 BCF of gas beyond the gas needs of the GMTU will be produced and injected into CRU PAs as Outside Substance Gas. There will be months, however, when the GMTU will need gas beyond what it produces for its operations. Prior to GMTU production startup, GMTU may require CRU native gas to pack production lines and heat facilities. This initial start-up gas will be purchased from the Colville River Unit, and will not exceed the offtake limit being requested in this application. Once operations begin, GMTU will typically provide more gas to CRU than it needs in return, and there will be no need for CRU gas at GMTU. However, during cycles when GMTU injection wells are converted from water injection to enriched gas injection, it is expected that GMTU gas requirements may periodically be greater than the available GMTU gas production. Consequently, CRU gas will be Application to Amend CRU AGOTR February 28, 2018 Page 3 of 5 necessary on these occasions for GMTU operations. Figure 1 shows a forecast of periods after start-up when CRU gas may be needed for operations at GMTU. This forecast indicates a peak requirement of approximately 6 MMCFD of CRU gas. Other than at startup, GMTU will likely not require significant amounts of gas from CRU until 2021. The forecasted cumulative CRU gas needed for GMTU operations is 11,000 MMCF. Figure 2 shows the net cumulative excess GMTU gas injected into CRU. Overall, it is forecasted that GMTU will inject a net 38,000 MMCF of gas into the CRU as Outside Substances Gas. Once GMTU production begins, there is never a negative net cumulative balance of GMTU gas that is injected into the CRU. Figure 3 shows the results of a simulation of the benefit of gas injection on oil recovery and is further described in the Lookout oil pool Area Injection Order application. In general, the oil benefit of gas injection is greatest for reservoirs that have received less gas injection and there is a continued but lesser oil benefit out to very high volumes of gas injection. This oil benefit of gas injection will apply to both GMTU and CRU oil pools. Justification for Expanded Offtake The justification for increasing the AGOTR to a monthly cumulative volume of 7 MMCFD is as follows: 1) The increased offtake will provide for a monthly cumulative volume of 1 MMCFD in sales to the Village of Nuiqsut and a monthly cumulative volume of 6 MMCFD on an as needed basis to the GMTU. 2) CRU gas will be needed by the GMTU intermittently for operational purposes to maximize efficient oil recovery from the GMTU. 3) CRU oil recovery will benefit from the net increased gas injection that GMTU production provides. Application to Amend CRU AGOTR February 28, 2018 Page 4 of 5 6 5 4 O U 3 2 1 0 Jan -18 Jan -23 Jan -28 Jan -33 Jan -38 Jan -43 Figure 1. Forecasted Gas Sales from CRU to GMTU 45,000 40,000 35,000 30,000 U 25,000 20,000 15,000 10,000 5,000 Jan -18 Jan -23 Jan -28 1ao-33 Jan -38 Figure 2. Cumulative Net GMTU Gas Injection into CRU Jan -43 Application to Amend CRU AGOTR February 28, 2018 Page 5 of 5 too 90 8o 70 e 20 Assumed Con&lxms Fresswt = 3750 P! Temperature = 3$'. Current lnjectantIN 0 20 t•0 E0 a:l I"v2 120 IAO Pore Volumes of Gas Injected, % PV tectent is — Lean Gas — Current Carnposrlional Blend -•— IOiu Enriching FW id 15'=! Enriching Fluid — 27.4 Enrithing Flwd Figure 3. Simulated Oil Benefit of Gas Injection I6'7 17 ConocoPhillips February 28, 2018 Hollis French, Chair Alaska Oil and Gas Conservation Commission 333 W. 7th Ave #100 Anchorage, Alaska, 99501-3539 Stephen Thatcher Manager, WNS Development North Slope Operations and Development ConocoPhillips Alaska, Inc. ATO -1770 700 G Street Anchorage, AK 99501 phone 907.263.4464 MAR 31 2313 t0GC RE: Application to Amend Allowable Gas Offtake Rate, Colville River Unit, North Slope, AK Dear Commissioner French, ConocoPhillips Alaska, Inc. ("CPA[") as operator of the Colville River Unit ("CRU") and Greater Mooses Tooth Unit ("GMTU"), requests that the Alaska Oil and Gas Conservation Commission ("Commission") approve CPAI's application to amend the Allowable Gas Off Take Rate from the CRU to allow CRU gas to be transferred to the Greater Mooses Tooth Unit (GMTU). This application is being made concurrently with applications for GMTU Lookout Oil Pool applications for Conservation Orders and Area Injection Orders. Enclosed are two printed originals of this application for expanded gas offtake and a disc containing an electronic version of the application. Please contact John Cookson (265-6547) if you have questions or require additional information. Regards, Stephen Thatcher Manager, WNS Development North Slope Operations and Development Cc: Land Manager - Alaska, Anadarko E&P Onshore LLC Bruce W. Hunt, Petro -Hunt LLC Enclosures (3) Application to Amend CRU AGOTR February 28, 2018 Page 2 of 5 APPLICATION TO AMEND THE ALLOWABLE GAS OFF TAKE RATE COLVILLE RIVER UNIT Request for Expanded Offtake This application is submitted for approval by the Alaska Oil and Gas Conservation Commission ("Commission") to amend the Allowable Gas Off Take Rate ("AGOTR") for the Colville River Unit ("CRU") to provide gas to the Greater Mooses Tooth Unit Lookout Oil Pool ("GMTU"). The current AGOTR for all CRU participating areas is 1 MMCFPD, as set forth in Administrative Approval Nos.443A.003, 562.001, 563.001, 569.001, and CO 605. ConocoPhillips Alaska, Inc. ("CPAI") as operator of the CRU and GMTU, requests that the Commission amend the AGOTR from the CRU to a maximum of a monthly cumulative volume of 7 million standard cubic feet per day ("MMCFPD") to provide 1 MMCFPD to the Village of Nuiqsut and on an as needed basis up to 6 MMCFPD to the GMTU for intermittent operational needs. It is also requested that this AGOTR apply to all currently defined pools within the CRU and any future pools that commingle production at the Alpine Central Facility ("ACF'): Background The Commission has approved an AGOTR not to exceed 1 MMCFPD from the "Colville River Field" for the purposes of providing the Village of Nuiqsut with natural gas. See, e.g., Administrative Approval No. 443A.003. In addition, the AGOTR applies to any new pools that process production at the ACF. Id. The current pools processing production from the ACF are the Alpine Oil Pool (which includes the Kuparuk oil pool), Fiord Oil Pool, Nanuq Oil Pool and Qannik Oil Pool. As a frame of reference, CRU provided 0.4 MMCFPD to the Village of Nuiqsut during November 2017. Production from the CRU pools is commingled and processed at the ACF. All of the commingled gas is either consumed within the CRU for operational purposes, re -injected to enhance oil recovery from the CRU, or provided to the Village of Nuiqsut. Gas production from all CRU oil pools was 67.3 MMCFD during the month of November 2017. The GMTU will begin production into the ACF in late 2018 as described in the Lookout Oil Pool Conservation and Area Injection Order applications that are submitted concurrently with this application GMTU gas production will be sent to ACF for processing. Gas needed for GMTU operations will be returned to GMTU, any excess GMTU gas after accounting for GMTU's share of fuel and flare will be injected into CRU participating areas. GMTU Requirement for Gas from the CRU Production from the GMTU is expected to generate significant excess gas. In most instances, the amount of GMTU Return Gas will be more than enough to provide for the gas requirements of the GMTU. CPAI estimates that approximately 38 BCF of gas beyond the gas needs of the GMTU will be produced and injected into CRU PAs as Outside Substance Gas. There will be months, however, when the GMTU will need gas beyond what it produces for its operations. Prior to GMTU production startup, GMTU may require CRU native gas to pack production lines and heat facilities. This initial start-up gas will be purchased from the Colville River Unit, and will not exceed the offtake limit being requested in this application. Once operations begin, GMTU will typically provide more gas to CRU than it needs in return, and there will be no need for CRU gas at GMTU. However, during cycles when GMTU injection wells are converted from water injection to enriched gas injection, it is expected that GMTU gas requirements may periodically be greater than the available GMTU gas production. Consequently, CRU gas will be Application to Amend CRU AGOTR February 28, 2018 Page 3 of 5 necessary on these occasions for GMTU operations. Figure 1 shows a forecast of periods after start-up when CRU gas may be needed for operations at GMTU. This forecast indicates a peak requirement of approximately 6 MMCFD of CRU gas. Other than at startup, GMTU will likely not require significant amounts of gas from CRU until 2021. The forecasted cumulative CRU gas needed for GMTU operations is 11,000 MMCF. Figure 2 shows the net cumulative excess GMTU gas injected into CRU. Overall, it is forecasted that GMTU will inject a net 38,000 MMCF of gas into the CRU as Outside Substances Gas. Once GMTU production begins, there is never a negative net cumulative balance of GMTU gas that is injected into the CRU. Figure 3 shows the results of a simulation of the benefit of gas injection on oil recovery and is further described in the Lookout oil pool Area Injection Order application. In general, the oil benefit of gas injection is greatest for reservoirs that have received less gas injection and there is a continued but lesser oil benefit out to very high volumes of gas injection. This oil benefit of gas injection will apply to both GMTU and CRU oil pools. Justification for Expanded Offtake The justification for increasing the AGOTR to a monthly cumulative volume of 7 MMCFD is as follows: 1) The increased offtake will provide for a monthly cumulative volume of 1 MMCFD in sales to the Village of Nuiqsut and a monthly cumulative volume of 6 MMCFD on an as needed basis to the GMTU. 2) CRU gas will be needed by the GMTU intermittently for operational purposes to maximize efficient oil recovery from the GMTU. 3) CRU oil recovery will benefit from the net increased gas injection that GMTU production provides. Application to Amend CRU AGOTR February 28, 2018 Page 4 of 5 )an -23 Jan -28 Jan -33 lan-38 Figure 1. Forecasted Gas Sales from CRU to GMTU 45,000 40,000 35,000 30,000 V 25,000 S` 20,000 15,000 10,000 5,000 Jan -18 Jan -23 Jan -28 Jan -33 Jan -38 Figure 2. Cumulative Net GMTU Gas Injection into CRU JanA3 )am -43 Application to Amend CRU AGOTR February 28, 2018 Page 5 of 5 100 so 68 70 0 20 --- -,. ✓ numed Cmd•Itl m 71 Preuurc=3750ps A0 9 Temperature a W 0 L Current tn*tint N 0 20 40 60 8o 189 1210 140 Pore Volumes of Gas Injected, % PV IKtent ks - lean Gas— Current Compositional Bland -a 18:a Enriching Fluid - 151'. Errichmg Fluid-- 20'm Enriching Fljw Figure 3. Simulated Oil Benefit of Gas Injection 0M 16 ConocoPhi I I ip s June 16, 2015 RECEIVEDMisty Alexa y ►7 J U N 2015 Manager, WNS Development Operations & Development 1 t North Slope ConocoPhillips Alaska, Inc. /"►VG (./ PO Box 100360 Anchorage, Alaska 99510-0360 Phone: (907) 265-6822 Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Attention: Commissioner Cathy Foerster Dear Commissioner Foerster, Pursuant to Rule 12 of Conservation Order (CO) 562, CO 569, and CO 605, ConocoPhillips Alaska, Inc. (COPA), as Operator of the Colville River Unit, respectfully requests an administrative action by the Commission to waive the requirement for monthly submittals under the following Rules: 1. Rule 7(e) of CO 562 (Nanuq Oil Pool) 2. Rule 6(e) of CO 569 (Fiord Oil Pool) 3. Rule 6(e) of CO 605 (Qannik Oil Pool) The rule is stated the same in each CO and reads: "The operator shall submit a monthly report and electronic file(s) containing daily allocation data and daily test data for agency surveillance and evaluation." COPA stopped sending monthly these reports to the Commission in September 2013. Regrettably, our plan to request an administrative action in support of that change was never executed. The data has been collected and retained, however, and provided in summary form to the Commission in the Annual Surveillance Reports for the Colville River Unit. We could send the daily data to the Commissioner at any time, if asked to do so. This request for a waiver is limited to the requirement for monthly submittals. COPA intends to continue to collect the daily data required by the rule, to submit summaries annually in the surveillance report, and to submit the daily data to the Commission on request. We simply seek relief from the cost and burden of preparing the reports on a monthly basis. Please feel free to contact Jack Walker at 265-6268 regarding this request. Sincerely, Misty Alexa Manag r, Western North Slope Development Cc: Mike Nixson, Anadarko Bobby Donahue, Petro -Hunt Teresa Imm, ASRC Corri Feige, AK DNR Division of Oil & Gas ..► Ul • • Roby, David S (DOA) From: Soria, Dora I [ Dora .I.Soria ©conocophillips.com] Sent: Wednesday, December 15, 2010 11:28 AM To: Roby, David S (DOA); Cellos, Harry S; Cologgi, John R; Parviz Mehdizadeh; Davidson, Temple (DNR); Dykstra, Jeffrey R (DNR); Konsor, Alicia G (DNR); Heumann, Michael P (DNR) Cc: Fullmer, Barbara F (LDZX) Subject: RE: Attendance sheet Importance: High All, This is a reminder that certain portions of the report CPAI presented yesterday are confidential as follows: The information in Appendices 3 and 4 of the AOGCC `Application Report" for the MPM Multiphase Metering System provided by ConocoPhillips Alaska, Inc., as Operator ( "ConocoPhillips "), is confidential and proprietary to ConocoPhillips and is not subject to disclosure because it contains information or data that is (1). trade secret information as defined in AS 45.50.940(3) and State v. Arctic Slope Regional Corp., 834 P.2d 134 (Alaska 1991); (2).required to be held confidential under AS 38.05.035(a)(8); (3). exempted from disclosure under 5 U.S.C. 552(b)(4) or (b) (9); and /or (4). required to be held confidential under AS 31.05.035(d). Best regards and Happy Holidays! -dora Dora I. Soria Staff Landman ConocoPhillips Alaska, Inc. Exploration and Land P.O. Box 100360, Anchorage, AK 99510 email - dora. i.soriaaconocophillips.com (907) 265 -6297 (telephone), (907) 263 -4966 (fax) From: Roby, David S (DOA) [mailto:dave.roby @alaska.gov] Sent: Tuesday, December 14, 2010 12:01 PM To: Cellos, Harry S; Soria, Dora I; Cologgi, John R; Parviz Mehdizadeh; Davidson, Temple (DNR); Dykstra, Jeffrey R (DNR); Konsor, Alicia G (DNR); Heumann, Michael P (DNR) Subject: Attendance sheet All, Attached is a copy of the sign in sheet from the meeting this morning. I once again want to apologize for being so late. Harry, I do not have Gordon's email, could you please forward this to him? 1 • • • Thanks, Dave Roby (907)793 -1232 From: Davidson, Temple (DNR) Sent: Tuesday, December 14, 2010 11:51 AM To: Roby, David S (DOA) Subject: CPAI MPM App Hi Dave, Thought you'd like to have this — sorry I forgot to give it to you. Did you want to distribute or do you want me to? Thanks, Temple 2 • Jc2Qn"� 9n 60 1 `, Cit es 14, r� ^L C,`�' � 7 ` ;11 _i)N 2 1)Ce Cc 13 : z--4-5- 7Q ii TG P.' bu f 5 i-C4 3 75 d z 3 3 1bi Rf D 0 Er Co Augotreold .4s 4r ?;cP SC 's /1,7 c 2 6 3 - , 7(7 pfvE Roar 79 /2 7; - /906 CC- �� v ti J tv)e.Cld r Z G 35502 • • • • • • • ConocoPhiflips . • • • • CPAI • • AOGCC "Application Report" for • the MPM Multiphase Metering g • • System • • • • • • • • • • • MultiPhaseMeters '• • • • • • • • • • • • • • • Prepared Parviz Mehdizadeh and Gordon Stobie • 12/14/2010 • • Cover Letter • Anchorage, G Street Anchoragge, , AK 99501 C onocoPhullips Phone: 907 - 263 -3701 December 14, 2010 RECFIVED Daniel T Seamount Jr., Commissioner DEC 2 1 MO Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 lasl�a C:�ia$ L, i�0lMS:tl0t8 Anchorage, AK 99501 An horne Re: Application Report for MPM Multiphase Metering System and Request for Approval of Amendments to Conservation Orders Dear Commissioner Seamount: ConocoPhillips Alaska, Inc.( "CPAI ") as Operator on behalf of the working interest owners of the Kuparuk River Unit ( "KRU ") and Colville River Unit ( "CRU ") (listed in Appendix 1 of the Application Report attached as Attachment 1) hereby requests authorization to use a multi -phase measurement device, as described in the Application Report, for the purpose of well testing and production allocation within the KRU and CRU operations conducted pursuant to 20 AAC 25.228, 20 AAC 25.230, and Alaska Statute Sec 31.05.030(d)(6). The Application Report describes the design, the expected performance and the anticipated applications of the specific multiphase flow meter and compiles the data and literature that were used to qualify the design and establish performance levels for MPM Multi -phase Flow Meter as a self contained unit. This document was prepared following the "Guidelines for Qualification of Multiphase Metering Systems for Well Testing" issued November 30, 2004 by the AOGCC. Upon approval from AOGCC, CPAI would request an amendment to each of the AOGCC Conservation Orders (CO) governing each pool listed in Appendix 1 in order to allow for the use of multi -phase meter technology as described in the Application Report. At this time, there are no specific sites planned for deployment of this technology but having the approval to include such technology will allow it to be included in conceptual planning for project development. The MPM multiphase metering system has been developed by Multi Phase Meters AS ( "MPM ") in Norway under a Joint Industry Project supported and directed by ConocoPhillips Company, ENI, Hydro, Shell, Statoil and Total. A comprehensive test and qualification program was established by the participating members to be able to qualify the MPM Meter for use in field applications. These qualification programs are described in the Application Report. At this time, it is our understanding that 83 MPM meters have been sold for various applications worldwide - of these, 31 units have been commissioned, and the first commenced operating in October 2007 as shown in Table 1 in the Application Report. The main physical components of the MPM Meter are shown in Figure 1 of the Application Report. The special features of MPM are, however, software based. The MPM Meter uses several sensors for different measurements. The data from these sensors are combined in a multi -modal "tomographic" measurement system as described in Section 4 of the Application Report. After a comprehensive review of the performance records of MPM meter from flow loops and field trials, CPAI selected the MPM multiphase metering system for field tests at CRU. The results from these field tests are reported in Section 5 of the Application Report. The CRU tests have demonstrated that the MPM meter has suitable measurement capabilities for well testing. The MPM meter has also been tested in a number of field locations and flow loops. These field tests have been conducted under the MPM Joint Industry Project. Table 8 of the Application Report summarizes the performance uncertainty for flow rates and compositions obtained in the above mentioned tests. Taking into account the uncertainty in the reference devices and data used in the field tests, the MPM has been able to measure the oil /condensate rates with an uncertainty of ± 1 -7 % and gas rates to an uncertainty level of ± 1 -10 %. This is a good record for the overall uncertainty in the many fluids under flow conditions that cover a wide range of fluid properties, water cuts and gas volume fractions. Appendix 1 to the Application Report shows the wells and production horizons for which CPAI is the Operator that may use the proposed multiphase metering unit. This Appendix also shows the working interest owners for those wells and horizons. All parties with working interest, and royalty ownership, as well as the Alaska Department of Revenue will be notified about the use of the MPM meters when the meters are implemented and the application of the metering system affects such interests. The allocation methodology currently practiced at the KRU and CRU will continue and would not be affected by the multiphase metering system. Approval of this request will advance the use of multi -phase technology for North Slope production measurements by allowing CPAI to gain operational experience with the MPM meter and demonstrate that this technology can provide allocation well tests comparable to a conventional separator. Should you have any questions regarding this request, please don't hesitate to contact me at 263 -3701. We would be pleased to provide additional information on this subject at your convenience. erely, es Rodgers GKA Development Manager cc: cover letter only: Kevin Brown, BP Exploration (Alaska) Inc. Glenn Fredrick, Chevron U.S.A. Inc. & Union Oil Company of California Mark Agnew, ExxonMobil Alaska Production Inc. Steve Dodds, Anadarko Petroleum Corporation Bobby Donahue, Petro -Hunt, L.L.C. podeki • • • • • • • • • • • • • CPAI • • • AOGCC "Application Report" for • the MPM Multiphase Metering • • System • • • • • • • • • • • • • • • • • • • • • • • • Prepared Parviz Mehdizadeh and Gordon Stobie • 11/11/2010 • • • • • 12- 02- 2010.AOGCC R1PM for Approval.doc • • Table of Contents • 1. Introduction 2 • 2- MPM Meter Development History 2 • 3. Proposed Applications 2 Table 1 - Current MPM Installations 3 • Table 2- Range of Well Head Conditions and Fluid Properties at the CPAI Proposed Sites • for MPM Installations 4 • 4. System Components and Measurement Strategy for MPM 4 Figure 1- The main components of the MPM meter 5 • Figure 2 -The MPM Meter performs RF measurements in many different planes. 6 • Figure 3 - Schematic of the MPM Well Head configuration 6 • Table 3 — Summary of MPM Accuracy (Uncertainty) Specifications at 95% confidence level • 7 5. Performance of MPM at Alpine 7 • Figure 5 — MPM Meter installed at Alpine 8 • Table 4 - Alpine Wells at CD -1 Tested and Average Test Duration(Hours) 9 • Table 5 - Summary of Alpine Tests 10 Table 6 - Summary of Alpine Test Results - Accumulated Delta Relative to Test Separator • 10 IP Figure 6 — Liquid flow comparison MPM Meter to Test Separator The arrows show 2 tests • where the flow rates were high enough for the size meter used in the Alpine trials to cause • saturation of DP transducer 11 Figure 7 — Water Cut comparison MPM Meter to Test Separator The dotted lines show the • ± 5% variation band 11 • Figure 8 — Oil flow comparison MPM Meter to Test Separator the dotted lines show the • ±10% variation band. 12 Figure 9 — Mass Gas flow comparison MPM Meter to Test Separator. Dotted lines show • the ±10% variation band. 12 • The gas comparison is based on mass flow rates since the Coriolis meter is a good mass • meter and the mass rate comparison eliminates any uncertainty introduced due to PVT • conversion and the additional uncertainties which could be introduced in the gas Coriolis meter converting to volumetric flows. 12 • Table 7- Raw and Post Process MPM Gas Data 13 • 6 — Further Field and Flow Loop Testing 14 • Table 8 - Flow Conditions and Fluid Properties In MPM Tests 15 Table 9- Summary of Field and Flow Loop Test Results 15 • 7. Factory Acceptance Tests (FAT) 16 • 8. Field Maintenance and Periodic Calibration 16 • 9. List of References 16 10. List of Appendices - Supportive Documents 17 • • • • • • • 1 - • • • • • • • • 12- 02- 2010AOCCC MPM for Approval.doc • • • AOGCC "Application Report" for MPM • • Multiphase Measurement System • • 1. Introduction • This document describes the design and performance of the MPM multiphase metering • system — hereafter referred to as MPM - designed for well testing in operating areas shown in • Appendix 1. This report compiles the test data and literature that was used to qualify the • design and establish performance levels for the MPM. This document is to be submitted to Alaska Oil and Gas Conservation Commission (AOGCC) as an "Application Report" to • obtain their approval for using the MPM as an alternative to conventional gravity based test • separators for well testing. The "Guidelines for Qualification of Multiphase Metering Systems • for Well Testing" issued by AOGCC, requires operators to submit an "Application Report" • before new metering systems are used for production well testing and allocations. This CPAI "Application Report" provides the information that is requested in the Section 3 of the • AOGCC document. • • 2- MPM Meter Development History • The MPM multiphase metering system has been developed by Multi Phase Meters AS • (MPM) in Norway under a Joint Industry Project supported and directed by ConocoPhillips, • ENI, Hydro, Shell, Statoil and Total. A comprehensive test and qualification program was • established by the participating members to be able to qualify the MPM Meter for use in field applications. • The first part of this qualification program consisted of testing the meter in the MPM Flow • Laboratory. Following successful completion of the vendor flow loop tests, the MPM meter • was taken to K -Lab in Norway for the first performance tests in October 2006. After successfull flow test at K -Lab the meter was made available commercially. Many of the JIP • Partners bought meters for further field testing. ConocoPhillips purchased an MPM meter and • conducted field performance trials of the meter at their North Sea Ekofisk facility. Other • specific application field trials were also conducted. The results from all the field trials are • discussed in Section 6 of this report. At this time 83 MPM meters have been sold for various applications - of these 31 units have been commissioned, and the first commenced operating • in October 2007 as shown in Table 1. • After a comprehensive review of the performance records of MPM meter from flow loops and • field trials, CPAI selected the MPM multiphase metering system for field tests at Alpine. The • results from these field tests are reported in Section 5 of this application. The Alpine tests • have demonstrated that the MPM meter has suitable measurement capabilities for well testing. • • 3. Proposed Applications • The proposed MPM multiphase metering system is designed to be used either as permanent • wellhead installation or mobile systems deployed in a field. Information and data presented in • 2 -17 • • • • • • 12- 02- 2010A0GCC MPI%1 for Approval.doc • • Sections 5 and 6 of this report indicates that the MPM meter has been able to measure the oil • rates with an uncertainty of ± 1 to ±7 % and gas rates to uncertainty level of ± 1 to ±10 % • when compared to a test separator system. This level of performance has been demonstrated • under flow conditions that cover a wide range of fluid properties, water cuts, and gas void fractions. Appendix 1 shows the wells and production horizons for which CPAI is the • Operator or has working interests in that may use the proposed multiphase metering unit. This • Appendix also shows the working interest owners. All parties with working interest, royalty • ownership, as well as the Alaska Department of Revenue will be notified about the use of the • MPM meters when the application of the metering system affects such interests. The allocation methodology currently practiced at CPAI operating fields will not be affected by • the application of the MPM metering technology. The well head conditions and range of fluid • properties at the CPAI Proposed Sites for MPM Installations are shown in Table 2. • Table 1 - Current MPM Installations • • Project Country Operator Units Size MP WG Installed • Morvin (subsea) Norway Statoil 4 3" v 8/1/2010 • Champion West Brunei BSP 1 3" v 6/2/2010 • Ebla Syria PetroCanada 1 5" v v 5/30/2010 • Baraka Tunisia ENI 1 3" v 5/15/2010 • Welltesting Oman PDO 1 3" v v 11/10/2009 • Oseberg Low Pressure Norway Statoil 4 3" v v 3/1/2010 • Oseberg B46 Norway Statoil 1 5" v 9/15/2009 • Bardolino -Howe UK Shell UK 1 5 v 8/15/2009 Penguin UK Shell U.K. 1 10" v 8/15/2009 • Nini ost Denmark Dong 1 5" v 2/20/2010 • Oseberg B30 Norway StatoilHydro 1 5" v 12/1/2008 • Oman Well Testing Oman MB Petroleum 1 3" v 8/1/2008 • Blacktip Australia ENI 2 5" v 9/15/2009 • Maamoura Tunisia ENI 3 2 " -3" v 12/18/2009 • Separation Module Norway StatoilHydro 1 2" v 10/1/2008 • Compression project Norway StatoilHydro 1 10" v 1/1/2008 • Oseberg B28 Norway StatoilHydro 1 5" v 3/1/2008 • Vega Norway StatoilHydro 1 5" v 10/1/2007 • Ekofisk 2/4 M Norway Conoco Phillips 1 5" v v 10/1/2007 • Separation module Norway StatoilHydro 1 3" v v 10/1/2007 • Separation module Norway StatoilHydro 1 3" v v 10/1/2007 • Gullfaks A Norway StatoilHydro 1 3" v 10/1/2006 • • • • 3 -17 • • • • • • • • 12-02- 2010AOGCC J\1PM for Approval.doc • • • Table 2- Range of Well Head Conditions and Fluid Properties at the CPAI Proposed Sites for • MPM Installations • Well Testing Parameters • ( Average Values) Operating Fields • Well Head Conditions ' Kuparuk West Salt Tarn Alpine GMT1 • Reservoir Gas Rate - mmscfd 0.32 0.06 10.7 1 10.7 Gas Lift - mmscfd 1 1 0 1.8 0 • Oil Rate - BPD 800 300 6000 1500 6000 • Produced Water Rate - BPD 2500 300 5000 2500 5000 • Total Liquid Rate- BPD 3300 600 6000 3000 6000 • Water Cut 76% 50% 83% 83% 83% • Formation GOR - scf /stdBbl 400 207 1800 670 1800 • GVF (estimated at the meter) 0.95 0.97 0.85 0.89 0.85 Meter Pressure (WH Pressure )- psia 135 150 450 250 450 • Meter Temperature (WH Temperature) - F 140 120 100 130 100 • Fluid Properties • Oil Density - lb /ft3 55 57 48 49 48 • Water Density - lb /ft3 61 61 62 62 62 • Gas Density - lb /ft3 0.44 0.42 1.88 0.99 1.88 • Mixture Density - lb /ft3 3.36 1.89 8.88 7.34 8.88 • API Gravity 22 19 38 39 38 • Oil Viscosity - cp 14 26 1.14 0.51 1.14 Water Viscosity - cp 0.46 0.49 0.71 1.56 0.71 • Gas Viscosity - cp 0.012 0.012 0.012 0.012 0.012 ' • Oil /water viscosity 1.05 157 1.16 4.63 1.16 • • 4. System Components and Measurement Strategy for MPM • The main physical components of the MPM Meter are shown in Figure 1. The special features • of MPM are, however, software based. The MPM Meter uses several sensors for different • measurements. The data from these sensors are combined in a multi -modal "tomographic" • measurement system - Reference 1. The major measurement functions in the meter are • performed as follows: • • 3DBroadBand tomography is used to measure dielectric constant in 3D, the • distribution of annular gas concentration, water conductivity, salinity and density. • • The Venturi is used for flow rate measurements (via differential pressure) and flow conditioning. • • Gamma ray absorption is used for gas /liquid composition and bulk density. • • The temperature and pressure devices provide in situ P and T data for PVT • calculations. • • 4 -17 • • • • • • 12- 02- 2010AOGCC MPM for Approval.doc • • The flow first passes through a Venturi, which is used to measure the total mass flow rate. i The special Venturi model used also creates radial symmetrical flow conditions in the 3D BroadbandTM section downstream of the Venturi. The 3D BroadbandTM technology is used to • establish a three dimensional picture of flow and composition inside the pipe as shown in Figure 2. The basis for the technology is often referred to as `process tomography'- which has e many parallels to tomography used in medical applications. The 3D BroadbandTM system is a • high -speed radio frequency(RF) based technique for measuring the water cut, fluid • composition, and the liquid/gas distribution within the pipe cross section. • The MPM Meter performs RF measurements in many different planes as shown in Figure 2 at • high speed. At each plane, measurements are conducted at many frequencies over a broad • frequency range, and combined with gamma ray absorption measurements to establish • accurate determination of the cross sectional composition and distribution of oil, water and gas. By combining this information with the measurements from the densitometer and • Venturi, accurate flow rates of oil, water and gas can be calculated in dual mode - either liquid • dominated (MP mode) or gas dominated (Wet Gas mode) flow regimes. With its dual mode - • liquid or wet gas - functionality and the capability to measure water salinity, the MPM Meter is intended to bridge many of the existing measurement gaps in conventional multiphase and wet gas meters. • • • "" • • Outlet connection — • – Electronics Enclosure • • Gamma Detector — -i, ". '$ • — Single Energy Gamma • • �, Sensor Body r 1 Electronics/ • Transmitters .•. How computer • (P, dP) 1t" ' , 3D Broa ''' • t .- r 1 r section • Salinity Probe 1 1 W i:1 • 411, i. �`_ ! ;i.. Termination Box • Venturi \.. Inlet connection ♦" f r • e Figure 1- The main components of the MPM meter • • 5 -17 • • • • • • • 12- 02- 2010AOGCC MPM for Approval.doc • • • V t1• $ c I i , • • f • • t. • ' • _ • ' /' , ___ • Figure 2 -The MPM Meter performs RF measurements in many different planes. • • A summary of the MPM measurement uncertainty specification is shown in Table 3. The full • uncertainty specification is defined in Reference 2. The measurement specifications include sensitivity which is defined as the smallest change which can be reliably detected and trended. • As noted previously, 31 MPM units have been installed in various fields shown in Table 1 for • well testing and field allocation. Some have been operating since October 2007. The MPM • meter is generally installed downstream of a blind tee in the flow line or as a part of wellhead spool. The proposed well head field configuration is shown schematically in Figure 3. • Installation procedures are described in Ap endix 2. • • • - -' ... , s • • 111= ; . • _ JuL- MI - y am • Mur— 1 =NW, A % . 1 •-* sac�.,�w. u�sr Tr, 1,, • alr. nommacor :e-+Ew.i...„"7. rn 17168-G r - • Figure 3 - Schematic of the MPM Well Head configuration • 6 -17 • • • • • 12- 02- 2010AOGCC MPM for Approval.doc • • Table 3 — Summary of MPM Accuracy (Uncertainty) Specifications at 95% confidence level • Topside & Subsea Meter • Uncertainty (i) Sensitivity • MultiPhase Mode GVF range - % GVF • WLR 0 -80 80 -95 0 - 95% Gas Flow Rate 0 - 100 % 5 % 5 % ± 0,5 % • Liquid Flow Rate 0 - 100% 2.5 % 5 % ± 0,3 % WLR <5% & >85% 1 % 1 °t° ±0,1 % • 5 -85% 2% 2% ±0,2% • WetGas Mode - 3 Phases (2) GVF range - % GVF WLR 90 - 95 95 - 98,5 90 - 98,5% • Gas Flow Rate 0 - 100% 3 % 3 % ± 0,5 % • Liquid Flow Rate 0 - 100% 4 % 10 % ± 0,3 Hydrocarbon mass flow 0 - 100% 3 % 3 °I° ± 0,3 % • Water Fraction (abs) 0 - 100% 0.1 % 0.1 % ± 0,01 % WetGas Mode - 2 Phases (3) GVF range • % GVF • WLR 90 -95 95 -99 99- 100 90 -100% • Gas Flow Rate 0 -100% 3% 3% 3% ±0,3% Liquid Flow Rate 0 - 100% 3 % 5 % 15 % ± 0,3 % • Hydrocarbon mass flow 0 - 100% 2.5 % 2.5 % 2.5 % ± 0,2 % Water Fraction (abs) < 15% 0.04 % 0.04 % 0.02 % ± 0,003 % • > 15% 0.08 % 0.08 % 0.04 % ± 0,005 % • Salinity Measurement Uncertainty • <50 mS /cm > 50 mSlcm • Multi Phase (Salinity Probe) ±2 mS /cm (4) ±4 % rel (4) • Wet Gas (S- curve) ± 50 mS /cm (6) ± 50 mSfcm (6) • • 5. Performance of MPM at Alpine • The testing was performed at Alpine Field. A 3 "NB, Beta 0.55 MPM meter was installed in • series with a compact two phase separator as shown schematically in Figure 4 • • Alaskan Multiphase Meter Test • Test Schematic • • • • Test Separator • Flow from wells 16ft by 5ft Dia I • • • • • MPM • • • • Figure 4- Schematic of MPM Installations at Alpine • 7 -17 • • • • • • • • 12- 02- 2010AOGCC MPM for Approval.doc • • , V , ‘ i '4 .s . 4 \ ,,,,,,-1 b • ,N , N • . . not • io • parato t pv, urd Flow • IF IP To MP11 • • • • Figure 5 — MPM Meter installed at Alpine • Figure 5 shows a photograph of the MPM installed at the well pad. The well pad consisted of • producers and injectors. The injectors were on a miscible water - alternating -gas (MWAG) • cycle. Many wells utilize lift gas (so produced gas composition can vary from well to well). • The Alpine well pad ( CD -1 ) selected for testing consisted of 24 producers. The use of the 3" MPM meter available for the tests restricted some of the larger producers on the well pad • from being tested. As a result only 16 wells were tested. • • The trials were conducted during March -April 2010. The liquid flow rates, gas flow rates, • GVF, and WC were in the following ranges: • • Fluid Flow Rates 300 -5200 BPD • • Gas Flow Rates 4 -8 MMSCFD • • Water Cut Range 19% -95% ( although 99% was observed) • GVF Range 88 -90% (although 100% was observed) • • Flow Line Pressure 145 - 200 psig • • Flow Line Temperature 68 -86 °F • • API Oil Gravity 40 • • Table 4 shows the wells tested, number of tests and average test durations. The test results are • summarized in Table 5. The liquid and oil volumes are reported in BBL, gas volume is • reported in Mscf (although later comparisons are in gas mass flow), deviations are reported in percentage. Well tests varied in duration from 3 to 25 hours — based on operational experience • with the wells. There were some relatively stable, some slugging and some unstable wells. • The total hours of well testing was in excess of 800 hours. The summation of test results • shown in Table 5 illustrates similar performance to currently used well testing methodology. • • 8 -17 • • • • • • 12- 02- 2010AOGCC MPM for Approval.doc • • Table 4 - Alpine Wells at CD -1 Tested and Average Test Duration(Hours) • • Well Number of Test Designation Tests Duration 4 6 9 • 8 5 5 • 12 6 6 • 18 4 7 24 2 6 0 25 5 6 • 27 12 12 28 6 6 • 32 6 7 • 34 4 6 35 5 8 • 38 4 10 • 40 5 8 • 41 5 7 43 5 5 • 44 7 14 • • The 2 -phase gravity test sseparator used for comparison with the MPM meter is a 16ft T -T by • 5ft OD, 42 BBL capacity vessel. Gas was metered by a Micro Motion CMF300 Coriolis meter • - capable of flow up to 9.4MMscfd with a DP <10psi. Vendor accuracy is quoted as ±0.35 %. • Considering the gas leg of the separator may carry some small amount of liquid (less than WG Type 1), the gas measurement is assumed to have an uncertainty of ± 4 %. Liquid was • metered by a Micro Motion CMF200 Coriolis meter. The meter had a 20:1 turndown — with a • range of 660 to 13,200BBL /d with a DP < 0.2 psi. Vendor quoted accuracy for liquid • measurements is ±0.1 % of rate. This accuracy level does not account for any gas carry under during slugging flow. An analysis of the Coriolis meter drive gains indicated that the meter • was working well. Only six short (several minutes) durations when the meter drive gains • peaked above 4V (of 14V) were noted. Based on these observations the uncertainty in liquid • measurement is assumed to be ±2.5 %. Water cut was monitored using a Phase Dynamics • Inc.(PDI) online water cut monitor, backed up by Net oil Computation(NOC) density based calculations. It has been observed that the WC monitor has problems with WC's >75 %, and in • those cases the NOC density calculations have been used. The MPM Meter was installed • downstream of a 3" blind tee in the test separator module. The well fluids moved upward • through the MPM and downward to the Test Separator. • Figures 6 to 9 show graphs of the well test results for liquid rate, water cut, oil rate, and gas • rate. In each graph the data from the MPM is plotted against the data from test separator. • Generally the MPM meter and the test separator tracked each other well. The average of the • differences from all 80 well tests are shown in Table 5. The gas data has a positive bias. MPM were encouraged to review the data with that in mind. MPM did review the data and found • that: • • two wells slugged so badly that the DP cells saturated at 5000mbar (72.5 psi DP) and • these results were eliminated from the data set. • 9 -17 • • • • • • • • 12- 02- 2010A0( ;CC 11P!VI for Approval.doc • • • The PVT gas density calculated based on the composition provided by CPAI and the • in -situ density seen from the gamma densitometer varied by about 0.5Kg/M3 relative • to a base density of about 12Kg /m3. • Using the above corrections, i.e. eliminating the saturated DP cell flow data and reprocessing • the data with in -situ gas density, the differences were reduced as shown in Table 6. • • Table 5 - Summary of Alpine Tests • Alpine Separator MPM Deviations ( %) Well Liq OiI Water Gas WC Liq Oil Water Gas WC Liq OiI Water Gas WC • 4 4784.0 345.4 4438.6 5795.0 92.8 4219.8 340.2 3879.6 6237.9 91.9 -11.8 -1.5 -12.6 7.6 -0.8 • 8 434.9 242.6 192.3 4118.6 44.2 371.6 158.2 213.4 4473.1 57.4 -14.6 -34.8 10.9 8.6 13.2 • 12 1284.8 881.3 403.5 3410.1 31.4 1286.7 921.8 364.9 3856.1 28.4 0.2 4.6 -9.6 13.1 -3.1 • 18 1880.1 803.9 1076.2 4335.3 57.2 1753.4 818.1 935.3 4772.2 53.3 -6.7 1.8 -13.1 10.1 -3.9 24 2184.0 702.1 1482.0 6492.6 67.9 2186.3 620.5 1565.8 6983.7 71.6 0.1 -11.6 5.7 7.6 3.8 • 25 2375.4 1089.8 1285.6 7535.1 54.1 2486.7 1126.7 1359.9 7781.8 54.7 4.7 3.4 5.8 3.3 0.6 • 27 2142.4 661.4 1481.0 7210.3 69.1 2172.7 812.5 1360.2 7546.1 62.6 1.4 22.8 -8.2 4.7 -6.5 • 28 572.2 121.0 451.2 2844.4 78.9 614.9 157.5 457.4 3069.5 74.4 7.5 30.2 1.4 7.9 -4.5 32 2347.5 775.7 1571.8 5662.8 67.0 2277.9 671.7 1606.2 6303.8 70.5 -3.0 -13.4 2.2 11.3 3.6 • 34 343.7 276.8 66.9 2865.6 19.5 257.2 183.5 73.7 3308.7 28.7 -25.1 -33.7 10.2 15.5 9.2 • 35 3486.8 1251.7 2235.2 6773.4 64.1 3223.1 1045.6 2177.4 7423.6 67.6 -7.6 -16.5 -2.6 9.6 3.5 • 38 1655.7 664.9 990.8 5296.7 59.8 1674.4 653.3 1021.2 5534.5 61.0 1.1 -1.7 3.1 4.5 1.1 40 1273.9 792.6 481.2 4679.2 37.8 1209.4 815.8 393.5 4920.0 32.5 -5.1 2.9 -18.2 5.1 -5.2 • 41 1809.9 1252.1 557.8 7756.5 30.8 1657.3 1247.0 410.3 7809.0 24.8 -8.4 -0.4 -26.4 0.7 -6.1 • 43 818.4 432.0 386.3 4060.1 47.2 725.4 343.0 382.4 4435.1 52.7 -11.4 -20.6 -1.0 9.2 5.5 • 44 1675.9 1223.0 452.8 4888.8 27.0 1590.7 1178.6 412.1 5340.3 25.9 -5.1 -3.6 -9.0 9.2 -1.1 • E 29069.0 11516.0 17553.0 83724.0 60.4 27707.0 11094.0 16613.0 89795.0 60.0 -4.7 -3.7 -5.4 7.3 -0.4 • • Table 6 - Summary of Alpine Test Results - Accumulated Delta Relative to Test Separator • • Test Location Liq Oil Water Gas WC • Alpine Raw data -4.7% -3.7% -5.4% 7.3% -0.4 % • Processed data -2.6% -2.1% -3.0% -0.4% -0.2% • • • • • • • • • • 10- 17 • • • • • • 12- 02- 2010AOGCC MPM for ApprovaLdoc • • 8o,o - {-''' • �~ • .►fu • le 6000 +r 5 d s * r • { t f. r i ce0 - r�r ` • , 2 -} -- • a er r w rd ` 3000 - r . • f o 'r. • 2000 - °. DP saturated >5000mbar • �r z 4'44 r.; • x 1001 - * s�` • a.r • 0 1000 2000 3000 4000 6000 6000 Alpine separator liquid Aowrate (stbid) • Figure 6 — Liquid flow comparison MPM Meter to Test Separator The arrows show 2 tests • where the flow rates were high enough for the size meter used in the Alpine trials to cause • saturation of DP transducer. • 100 - „ • .r.ss • ei 80 - s -;.,,,,--e, at d r ' s, • 1 70 - r* f • r r r a 1p . _ 4 ✓ • • 10 - • • 0 10 20 30 40 50 00 70 $0 90 in • Alpine separator wallow out (V • Figure 7 — Water Cut comparison MPM Meter to Test Separator The dotted lines show the ± • 5% variation band • • • 11 - 17 • • • • • • • • 12- 02- 2010AOGCC MPM for Approval.doc • • 2500 . r' • Yi 44 J, r r •i 1MN` 2000 - t • m !_ • . r f- 1500- �. -. L r • di + r • m 1000 - Ri • i • d a • ‘B 50C • • • • 0 - • 0 500 1000 1500 2000 2500 • Alpine separator oil flowrate (stb /d) • Figure 8 — Oil flow comparison MPM Meter to Test Separator the dotted lines show the ±10% • variation band. • WOW �. • - - .. • r r - • r+ t .. In • oa * i SCO3 - 4 * • u 4.:05 • r _ ,r ° _.- • 7 -..- • 1 ko • =t • • 0 1= 2C00 3000 illo� E a50 60X 74QQ P90Q0 1 ) • Alpine separatar gas flowrate ob) • Figure 9 — Mass Gas flow comparison MPM Meter to Test Separator. Dotted lines show the • ±10% variation band. • • The gas comparison is based on mass flow rates since the Coriolis meter is a good mass meter • and the mass rate comparison eliminates any uncertainty introduced due to PVT conversion and the additional uncertainties which could be introduced in the gas Coriolis meter • converting to volumetric flows. • 12- 17 • • • • • • 12- 02- 2010AOGCC MPM for Approval.doc • • As noted previously the gas data in Figure 9 shows a positive bias. The MPM meter used the • i gas composition provided by CPAI with their CALSEP PVTSIM® Equation of State • calculation package to determine the gas density using the flowing pressure and temperatures. The MPM meter is able to provide an in -situ measurement of the gas density under no flow • conditions. The results from the in -situ gas density measurements shown in Figure 10 • indicated a discrepancy between the composition based PVT density and the actual measured • density. Figure 10 shows the in -situ measured density is 4.2% lower, which would result in a • lower measured gas flow rate, reducing the discrepancy between the separator and the MPM • meter as shown in Table 7. • 16 • 14 • • IM 12 • 10 • - --Gas Density PVT 8 [kf;/m • 6 - Measured Gas Density • 4 (k l'm31 • 2 • 0 • .-M t,D .. 'D .-# tp • lD .-+ tD .-4 tD .-1 LD - 0 • - + , - i N N M m V V IJ 4f1 tD %D n • ti N m v to ID n OD c 0 ...4 e' m sr rr .-e rt ... • • Figure 10: Graph showing difference between measure and calculated gas density • Table 7- Raw and Post Process MPM Gas Data • Separaator Raw data Post Process • Well Gas flow Delta Delta Comments • Mscf [ %1 _ [ %] • 4 5795 7 .6 2.3 DP >5000mbar cut off 8 4118.6 8.6 3.2 • 12 3410.1 13.1 7.4 • 18 4335.3 10.1 4.6 • 24 6492.6 7.6 2.2 25 7535.1 3.3 -1.9 • 27 7210.3 4.7 -0.6 • 28 2844.4 7.9 2.5 32 5662.8 11.3 5.8 • 34 2865.6 15.5 9.7 • 35 6773.4 9.6 4.1 DP >5000m bar cut off 38 5296.7 4.5 -0.7 • 40 4679.2 5.1 -0.1 • 41 7756.5 0.7 -4.4 43 4060.1 9.2 3.8 • 44 4888.8 9.2 3.8 • Total 7.3 1.9 All data • • 13 - 17 • • • • • • • • 12- 112- 2010A0( ;CC MPM for Approval.doc • • 6 — Further Field and Flow Loop Testing • The MPM meter has been tested in a number of field locations and flow loops. The tests listed • below have been conducted under the MPM Joint Industry Project as blind tests or in • Operator controlled field tests where MPM have had minimal or no access to the test data. • • • MPM Flow lab tests as part of the MPM JIP, multiphase and wet gas flows with air, water and refined oils at about lOBarG - Reference 1. • • K Lab (1) lab tests were conducted under Statoil sponsorship as part of the MPM JIP • high pressure (60- 100Barg) wet gas using field gas, Decane and process water - • Reference 2. • • K Lab (2) lab tests were also conducted under Statoil sponsorship as a combined Statoil subsea compression test with the data released to the In -Situ JIP. Tests are • planned to run for 24 months (18 months already completed) - Reference 3. • • Gullfaks - under Statoil sponsorship as an early multiphase offshore field test. Trial • has now changed to permanent installation and MPM meter used for production well • testing - Reference 4 • SWRI flow loop tests were conducted by Statoil -Shell to assess the MPM for subsea • application at high pressures for wet gas measurements. Tests were lead by Statoil- • Shell with JIP financial involvement — high pressure (70- 120Barg) wet gas using field • gas, Decane and process water - Reference 5. • • COP Ekofisk - production well tests in a gas lifted field with various produced water origins. GVF 20- 100 %, WC 20 to 95 %. The field test meter has been converted to • permanent production meter and a 2nd MPM meter has been ordered. This meter is • used for well testing. (API 35 oil, water with large salinity variations) - Reference 6. • • K -Lab 2009, blind test by Statoil for a delivery project to Statoil operated field. Data • published in In -Situ Part I Final Report - Reference 7. • Alpine — Field test under CAPI sponsorship as described in section 5 of this report. • The results are published, Reference 8. • • Heavy Oil Project tests at the Petrobras Atalaia Testing Facility for Petrobras and • StatoilHydro - Reference 9 • CEESI — Lab test under BP /COP sponsorship for wet gas flows. Results are not • currently available. • • Table 7 below summarizes the various flow conditions and fluid properties used in the above • flow loop or field tests. The fluid properties and flow conditions proposed in the CPAI applications, see Table 2, are covered by the test conditions in Table 7. • • Table 8 summarizes the performance uncertainty for flow rates and compositions obtained in • the above mentioned tests. Taking into account the uncertainty in the reference devices and data used in the field tests, the MPM has been able to measure the oil /condensate rates with an • uncertainty of ± 1 -7 % and gas rates to an uncertainty level of ± 1 -10 %. • • This is a good record for the overall uncertainty in the money fluids under flow conditions • that cover a wide range of fluid properties, water cuts and gas volume fractions. • 14- 17 • • • • • • 12- 02- 2010AOGCC MPM for Approval.doc • • Table 8 - Flow Conditions and Fluid Properties In MPM Tests • Test Location Liq Range Gas Range *IA Range ° WE Range , Pressure .:.':'Temp -j: Oil Alit Gravity, ' ,; '.Comments • • BPD MMSCFD PSI F (Density- Kg/m3) • MPM Flow Lab 0- 30,200 0- 13.6 0- 100% 0 -100% 75 -150 80 37( 840) Stable and Slugging • flows K -Lab 1 300 - 10,600 338 -150 0-93% 10 -98.5 1800 65 -130 94 -100 Multiphase test • K -Lab 2 30 -1500 20- 230 0-10% 98.5 -100 450 -1800 65 -130 94 -100 Multiphase test • Gullfaks 970 -13840 20- 220 0-95% 0-95 880 6 -130 38-52 3 -Phase TS SWRI 0 -150 8.5- 33.9 0-25% 95 -100 1750 -2940 112 96120 (560 Variable water salinity • 620) Ekofisk 0 -8300 1.7- 13.6 0100 %R *, 0 100 %R *, 88- 300 -350 78 -205 35 Stable and Slugging • 1.5 -48% N 97 %N flow • K -Lab 2008- 24 Month Wet Gas 2010 NA NA 0 -100 94 -100 450 -1800 65 -130 94 -100 Tests • 30 -93 %N, 0- Slugging, Emulsions • Alpine 300 -5000* 2.8 -7.8 100 %R 0- 100 %R* 180 -220 65 -80 40 and variable water salinities • Heavy Oil NA NA 0-90 0-98 105 -180 Oil Viscosity- Rates Unavailable for 163cP at 20C Public • CEESI 0 -410 13 -31 0 -100% 99.5 -100% 1000 60-75 67 Wet Gas • CEESI 0 -2100 13 -31 0-10096 95 -100% 1000 60-75 67 Multiphase • Table 9- Summary of Field and Flow Loop Test Results • • Test Location I Liquid 1 Gas 1 WC 1 Oil 1 Water 1 Refere nce Used • MPM Flow Lab ±1.1% ±1.23% NA 1.2% +0.03% Loop Sep - 2 • K -Lab Blind ±0.1% ±1.4% NA 0.05% 1.2% Loop Sep -1 • Gullfaks Dec 06 ±3.4% ±0.7% NA 1.7% r 0.83% Test Sep - 3 Phase -1 • Gullfaks Jan 07 ±1.4% - 1.4% NA 0.82% 1.36% Test Sep -3 Phase -1 I. SWRI Wet Gas * * ** ±0.7% 1.2 - 1.63% NA r 0.96% -2.6% Loop Sep -2 Phase -2 • SWRI Wet Gas * * ** ±0.7% ±1.2 - 1.35% NA P +5.69% -2% Loop Sep - 3 Phase -1 • Ekofisk * ** ■ +1.2% +19.9 * ** +1.5 %abs +3% -5.8% Test Sep * ** • K -Lab 2008 -2010 ±5 -10% ±5 -10% ±5 -10% ±5 -10% ±5 -10% Data not Released • Alpine* r -4.7% +7.3% 0.42% +3.7% -5.4% Test Sep - 2 Phase -2 I. Alpine -Post Proc ** -2.6% r -0.4% - 0.22% -2.1% -3.0% Test Sep - 2 Phase -1 • Heavy Oil NA NA NA NA NA Test Sep • CEESI - Wet Gas NA NA NA NA NA Loop Sep • • NOTES • 1 = The values are reported on accumulative basis • * Out of the box - no processing accumulated discrepancy MPM meter vs. Test Sep. Alpine data comprises >80 well test and 800 hours of flow • ** Post Processed accumulated discrepancy MPM meter vs. Test Sep * ** Test comprised 76 well tests over 360hours of flow. These tests determined that the new Ekofisk 2/4M • Test Separator Gas meter was in error. It was a multipath USM of a bounce path design and liquids (in the • gas) contaminated the transducer signals. The MPM gas rates were confirmed as being `nearer to the expected figures' by the Reservoir Engineers from prior GOR knowledge (from 30 years prior production • experience of the Ekofisk field). The MPM gas and oil data (converted to GOR) fits the earlier experience. • * * ** 2Phase and 3Phase refers to the MPM Measurement Modes - each has its own advantages. • 15 - 17 • • • • • • •2- 2010AOGCC MPM for Approval.doc • • • 7. Factory Acceptance Tests (FAT) • Factory acceptance tests will be conducted prior to field installation as described in the • Factory Acceptance Test (FAT) MPM Manual shown in Appendix 3. The FAT procedures • include : • • Hydrostatic pressure testing is performed according to the meter's pressure rating. • • Venturi Calibration • • Liquid and gas flow rate tests to check the performance of the skids. The test • conditions will be guided by both the operating constraints of the test meter and of the • flow facility. • • Communication tests. • 8. Field Maintenance and Periodic Calibration • • The maintenance and periodic calibration procedures for MPM are described in the • Maintenance and Calibration Manual shown in Appendix 4. These procedures include but not • limited to the following items : • The PVT tables used for gas and liquid density calculations would be updated periodically • • Periodic in situ calibration of gas density and water salinity if needed • • Correct operation of the primary device - Venturi inspected visually using boroscope on yearly basis - if sand is detected in the well fluids. • • Periodic calibration of DP/P/T transmitter - as needed. • • Densitometer nucleonic source - Leak test - per International/National /State codes by • the RPS, plus Empty Pipe Reference - every 6 months • • 3D Broadband - using in -situ testing via the TCP /IP link to Stavanger and a certified quality index report as needed. • • • 9. List of References • 1. "NSFMW 2007paper - Tomography powered multiphase and wet gas meter providing fiscal • accuracy By Wee, Berentsen, Moestue and Hide" • 2. MPM HighPerformanceMeter- Unparalleled measurement accuracy and sensitivity White • Paper No 1,18 February 2008 . 3. MPM HighPerformanceFlowmetersTM White Paper No 6 1 August 2009,MPM Flow • Laboratory • 4. StatoilHydro- Well Informed 07 • 5. Field Test of MPM Subsea Meter at SwRI with special focus on Wet gas and Salinity Measurements - Preliminary Report Dec 4, 2007. • 6. Successful Implementation and Use of Multiphase Meters, oystein Fossa and, Gordon Stobie • — ConocoPhillips, Arnstein Wee — Multi Phase Meters - NSFMW , October 2009. 7. In situ verification for multiphase and wetgas metering JIP Final Report — Phasel • 8. MPM User Group Forum — Stavanger June 7 -8th 2010, Alaskan Multiphase Meter Test • Gordon Stobie - ConocoPhillips Company • 16- 17 • • • • • 12- 02- 2(110A06CC MPM for Approval, • • 9. MPM METER EXPERIENCE IN HEAVY OIL,Arnstein Wee (MPM), Hans Berentsen (ex • Statoil) and Lars Farestvedt (MPM Inc), InternationalWorkshop on the Challenges in Heavy Oil and Associated Multiphase Flow Measurement,Brazil, 12 -13 November 2009. 10. Erosion in a Venturi Meter with Laminar and Turbulent Flow and • Low Reynolds Number Discharge Coefficient Measurements, G Stobie, COP R Hart and S Svedeman, SWRI, K Zanker, Letton -Hall Group, NSFMW, Oslo, 2007 • • 10. List of Appendices - Supportive Documents • • Appendix 1 — Field, Pool, and Wells for proposed applications, list of ownerships, etc • Appendix 2 - Installation and User Manual - MPM Topside Meter Appendix 3 - Factory Acceptance Test (FAT) MPM Manual Appendix 4 - List of relevant papers and publications • • • • • • • • • • • • • • • • • • • • • • • • • • 17 - 17 • • • Appendix 1 ••••••••••••• •••••••••••••••••••••• Appendix 1 NS Facilities Operated by CPAI Colville River Unit Alaska Property Ownerships Participating AOGCC Pool AOGCC Pool Oil Royalty Gas Royalty Processing Facility Area Code Description Rate Rate ConocoPhillips Anakardo Petro-Hunt Total Colville River Unit Alpine 120100 Alpine 9.8150% 78.00% 22.00% 100.00% Colville River Unit Fiord - Kuparuk 120120 Fiord - Kuparuk 12.5000% 12.5000% 78.00% 22.00% 100.00% Colville River Unit Fiord - Nechelik 120120 Fiord - Nechelik 11.6035% 77.62% 22.00% 0.3800% 100.00% III Colville River Unit Nanuq -Nanuq 120175 Nanuq -Nanuq 9.7726% 9.4685% 78.00% 22.00% 100.00% Colville River Unit Nanuq - Kuparuk 120100 Nanuq - Kuparuk 7.7713% 78.00% 22.00% 100.00% Colville River Unit Qannik 120180 Qannik 8.3285% 3.0808% 78.00% 22.00% 100.00% Kuparuk River Unit Alaska Property Ownerships Participating AOGCC Pool AOGCC Pool Oil Royalty Gas Royalty Processing Facility Area Code Description Rate Rate ConocoPhillips BP Exploration Union ExxonMobil ,Total Kuparuk River Kuparuk River Unit CPF #1 Kuparuk 490100 Unit 11.2513% 12.5010% 55.2753% 39.1920% 4.9506% 0.5821% 100.00% Kuparuk River Unit CPF #1 West Sak 490150 KRU West Sak 12.5000% 52.2247% 37.0247% 4.9506% 5.8000% 100.00% Kuparuk River Kuparuk River Unit CPF #2 Kuparuk 490100 Unit 11.2513% 12.5010% 55.2753% 39.1920% 4.9506% 0.5821% 100.00% Kuparuk River Kuparuk River Unit CPF #2 Meltwater 490140 Unit Meltwater 12.5000% 55.4889% 39.3438% 4.9506% 0.2167% 100.00% Kuparuk River Kuparuk River Unit CPF #2 Tarn 490160 Unit Tarn 12.5000% 55.4023% 39.2823% 4.9506% 0.3648% 100.00% • Kuparuk River Kuparuk River Unit CPF #2 Tabasco 490165 Unit Tobasco 12.5000% 55.4023% 39.2823% 4.9506% 0.3648% 100.00% Kuparuk River Kuparuk River Unit CPF #3 Kuparuk 490100 Unit 11.2513% 12.5010% 55.2753% 39.1920% 4.9506% 0.5821 % 100.00% Kuparuk River Unit CPF #3 NEWS NEWS 12.5000% 55.4024% 39.2822% 4.9506% 0.3648% 100.00% • • • • • • • \--) • i ay R • KDgru River r • • a ' '+ NW MILNE1 S � ■ nR+m loom, o- ��S I ( 1 O DEW U • SITE STA :. jig. \\ —C '9'. MINE SITE E . A 4. • , 3M KRU ') -OB ... PADI J G ..it E SIT VV • 4 v )0 ~ 1111 111111 ili t \ Ity WSAK 16 3 N \ t WSAK 7 W SA 2 H ` I 7 • • "•� ;• • _ ‘ EUGNU. PROD. TEST 4 / " S it Si 41, *'' � t,1G , 1H WSAKN �' ^) 2U — 18 KCS _ • • L .• 1 • 1 12X 1A' j! : c MINE SITEF 1 2V t72 M INE Bear Tooth Unit MP••••-• t 12C 1F CD-4 N UO /\ \ } ..... Is CD-0 Le • OUT rI 1 2F t 1L i1r1 ° • • .. ,tea i 41J • -_---- - Colville~ ; iver Una 4 12G 2E. I 1 • CD -7 - "� I 2 ` Kuparuk River Unit • NUIOSUT j / 36 i 3C F t • i'1 A A WSAK 26618 • / Greater Mooses Tooth Unit • / • I i N W+E • N PR - A 1:340,000 . ) litir A � _ . S 0 1.25 2.5 5 7.5 10 • ! Kuparuk River Unit Miles • . Alaska �- Conoc • c' ) CPAI Operated Facilities • 10100701A00 10 -7 -10 • • • Z xipueddd • • • • • • • mp m • MultiPhaseMeters • Appendix 2 • • MPM High Performance Flowmeters • • Installation and User Manual • • MPM Topside Meter • • • • • �4 • • • ` • • • • Project Name Magnolia, Entrada • Project Number 4054 Customer Name ConocoPhillips, Callon • PO Number 4509571200 • Tag Numbers 20 -ZAU -001, 20 -ZAU -002, 20- ZAU -003A, 20 -ZAU -0038 • Document No /Name TD -010 Installation and User Manual — MPM Topside Meter • (Operating and Maintenance Manual) • Classification PROJECT CONFIDENTIAL • • Rev Date Purpose Written By Accepted By Approved By • 01 14.08.08 Issued for Approval OAI KG AW • • • This document is a successor of the MPM document: QP -010 • • • • • • • mpm • • • TABLE OF CONTENTS • . 1 INTRODUCTION 4 • 1.1 PURPOSE 4 1.2 IMPORTANT NOTICE 4 • 1.3 TRAINING 4 • 1.4 UPDATES AND CONTACT DETAILS 1.5 ABBREVIATIONS 5 • 2 MPM METER DESCRIPTION 5 • 2.1 GENERAL 5 • 2.2 HIGH PRESSURE /HIGH TEMPERATURE DESIGN 7 • 2.3 TOPSIDE Mt i ER COMPONENTS 7 2.4 MECHANICAL PARTS 8 • 2.5 ELECTRONICS SYSTEM 10 2.6 MPM TERMINAL AND COMMUNICATION SYSTEM 11 • 3 INSTALLATION 13 • 3.1 GENERAL 13 • 3.1.1 Check of meter, flanges and covers 13 • 3.1.2 Mechanical installation 13 3.2 SITE INSTALLATION 14 • 3.2.1 MPM Terminal 14 3.2.2 Empty Pipe Verification test 14 • 3.3 ELECTRONIC TEMPERATURE SURVEILLANCE 14 • 3.4 INSTALLATION COMPLETED 14 4 COMMISSIONING 15 • 4.1 METER START UP 15 • 4.2 METER CALIBRATION 15 • 4.3 SITE SYSTEM TEST 15 4.3.1 Transmitters 15 • 4.3.2 External communication ports 16 4.4 METER CONFIGURATION 16 4.4.1 PVT Data 16 • 4.4.2 Conversion to Standard Conditions 18 4.4.3 Two Phase wet gas Mode 19 • 4.4.4 Input of look-up tables 19 • 4.4.5 Continuous input of density values (Live PVT) 20 • 5 OPERATION 21 5.1 STARTING THE MPM USER INTERFACE 21 • 5.1.1 MPM Terminal 21 • 5.2 REMOTE ACCESS 21 5.2.1 Setting up the remote computer 21 • 5.2.2 Main page 22 • 5.2.3 Menu 23 5.2.4 The Information area 24 • 5.2.5 Graphics area 25 • 5.2.6 Status bar 26 5.3 ALARM STATUS 27 • • TD -010 — installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia. Entrada Page 2 of 41 • Project Confidential • • • • . • • • M PM • R °.. 4 , 1 ties, • 5.4 EVENT LOG 28 5.5 TREND /EXPORT DATA 29 • 5.6 METER CONFIGURATION 30 5.6.1 Select active process data set 30 • 5.6.2 Create New Look -Up tables (PVT gas and oil properties) 30 • 5.6.3 Process data configuration 30 5 .7 DIALOG TOOLBAR 35 • 5.8 PVT, OIL AND GAS PROPERTIES DIALOGUE 36 • 6 MAINTENANCE 38 • 6.1 OPERATIONS INTEGRITY SERVICES (OIS AGREEMENT) — LINK TO MPM OPERATIONS CENTRE 38 6.2 VERIFICATION / RECAUBRATION OF VENTURI CD 39 6.3 PVT MAINTENANCE 39 6.4 COMMUNICATION TESTS 39 6.5 MECHANICAL MAINTENANCE 40 • 7 REFERENCE DOCUMENTS 41 • • • • • • • • • • • • • • • • • • • • • • • TD-010 — Installation and User Manual — MPM Topside Meter.Rev01 • Project Name: Magnolia, Entrada Page 3 of 41 Project Confidential • • • • • mPm • tIuni • • • 1 INTRODUCTION • 1.1 Purpose • The purpose of this Installation and User Manual is to provide information and guidance for users of • the MPM Meter, as to how to install, operate and maintain the Meter. • • 1.2 Important notice • The MPM Topside Meter is a field instrument, designed and built for problem -free operation to fulfil • customers' satisfaction. • However, there are some special precautions that must be taken to avoid problems or degradation of • the instruments capabilities, and to avoid unwanted HSE situations. • Please make sure to avoid the following: • - The Meter contains a RADIOACTIVE GAMMA SOURCE. The source is well shielded, and the • radiation to the environment is within specified and acceptable values. The gamma source is • equipped with a shutter mechanism. It is important though, that NO HUMAN LIMB MUST EVER • BE PUT INSIDE THE PIPE. - NO ELECTRICAL WELDING must be performed on the meter body or parts, nor in the adjacent • pipework or structure. • - All TRANSPORTATION AND HANDLING of the meter must be performed as per the • specific Handling of Radioactive Source and Action Plan Procedure. In particular, the • Meter must not be exposed to shocks and vibrations, outside the specified range. . 1.3 Training • • MPM is offering a set of training courses, which are aimed at personnel and operators at different • levels. Training courses can be provided in the MPM Flow Laboratory in Stavanger, and at site. In • Stavanger, operators are provided the opportunity to run the Meter in the MPM Flow laboratory, at a variety of flow conditions and rates, under supervision and guidance. • • 1.4 Updates and Contact details • This manual is made to the best of our knowledge and we hope it will be a useful tool for the • operators. We would certainly like to improve it based on experiences and knowledge gained as we • go along, and we would appreciate feed -back and comments on how we could achieve this. • To do so, or in case that further assistance is required, MPM can be contacted as follows: • e -mail: support(a,mpm- no.com • phone: +47 4000 1150 • TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 • Project Name: Magnolia, Entrada Page 4 of 41 • Project Confidential • • • • • • • • • • MP M • • • 1.5 Abbreviations • MPM - Multi Phase Meters AS • GUI - Graphical User Interface GVF - Gas Volume Fraction (in -situ) • PVT - Pressure Volume Temperature • FOR - Enhanced Oil Recovery dP Differential Pressure • WLR - Water Liquid Ratio • • • 2 MPM METER DESCRIPTION • • 2.1 General • The MPM Meter is intended for production monitoring, well testing and allocation metering purposes, and is tailored for use in WetGas and MultiPhase flow applications. • • • ?<: • is • • • • • • • • • 411 t,.. • • Focus during the development phase was to design a High Performance Meter, characterized by: • • High operational stability • • Unique sensitivity and reproducibility • • Unparalleled accuracy • • TD Installation and User Manual — MPM Topside Meter.Rev01 • Project Name. Magnolia, Entrada Page 5 of 41 Project Confidential • • • • • • mpm • t.4 h.> ^fix x R <ctzr, • The MPM Meter is an in -line and full bore meter, based on conventional multiphase metering • equipment in combination with the patented 3D- BroadBandT'" technology. • The MPM Meter has undergone a very extensive operator - driven qualification program. During the program, the Meter has demonstrated very high performance as to measurement accuracy. The specifications for measurement uncertainty are derived directly from the field testing. More details of the meter accuracy specifications and how these are derived are provided in White Paper No 1 - • Unparalleled measurement accuracy and sensitivity. • The second main part of the qualification program focused on mechanical integrity, and the meters • ability to withstand normal and extreme conditions during its life. More details are provided in the • following section. The MPM Meter can be configured as a wetgas or a multiphase meter (Dual Mode), depending on • the flowing conditions. Mode selection is automatic, or manual. In multiphase mode, the Meter does • extremely fast measurements to capture rapid fluctuations in the flow. In wetgas mode, the Meter • uses its ultra high sensitivity to differentiate tiny fractions of water and liquids from the gas. The Meter has no flow regime dependency - potential measurement errors due to slugging and /or annular gas • concentration are eliminated by the fact that measurements are done extremely fast making • measurements in 3 dimensions inside the pipe. With the dual mode, correct measurement of watercuts across full range of GVF's and water fractions • are obtained, resulting in correctly measured oil flow rates even at high watercuts, and correctly measured formation water flow rates at high GVF. More details of the Dual Mode features are • provided in White Paper No 3 - Dual Mode — Wetgas and Multiphase Meter • The MPM Meter is fully calibrated at the factory, prior to the Factory Acceptance Test (FAT), and has • lean requirements for field configuration. Field configuration consists of entering typical data for the • produced hydrocarbons using the Graphical User Interface. Ali the data related to the gas and oil phase can be calculated using a standard PVT simulator such as Calsep PVTSim based on the • hydrocarbon composition for the well. The Meter also offers a high tolerance to configuration • parameter shifts. While this is valid for most parameters, the conductivity of the produced water is different. At low WLR a potential erroneously specified value for water conductivity has little impact • on measured flow rates. However, once the WLR increases, and the emulsion turns into water - continuous (typically for WLR of 40 -50% and upwards), a potential error in the specified value for • water conductivity can have detrimental effect of the measured flow rates. This effect is more or less • the same for all brands of meters. Except the fact that the MPM Meter can be outfitted with an Auto configuration functionality. With this functionality, the water conductivity is automatically measured • by the Meter, and there would be no more need to provide manual input values (which would also eliminate the need for sampling). • The measured water salinity and water density will be available as output from the Meter, when the • flow is water - continuous. More details of the Salinity Measurement features are provided in White Paper No 2 - Water salinity • measurement & auto configuration • The MPM Meter is outfitted with comprehensive set of In -situ verification and self- diagnostics • functions. The operation and use of these are explained in detail in later sections of this manual. • • • • • TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 • Project Name: Magnolia, Entrada Page 6 of 41 • Project Confidential • • • • • • • • • • • • 2.2 High pressure /High temperature design • A dedicated part of the development program consisted of developing and qualifying a subsea version of the MPM meter. The subsea meter design specifications included high temperature and • high pressure, and a major part of the project consisted of qualifying the resulting design with respect • to mechanical integrity. During this phase of the project, up to nine international Oil Companies • worked in co- operation with MPM. • The resulting HP /HT design is also available for topside meters. it is made to cover the full range of expected requirements for operating pressure and temperature, and to operate without failures during • the full life of the well or field. • The qualification program for the HP /HT deisgn was performed as per • DNV's recommended practice for qualifying new products; the RP A- f 203. At the end of the program, DNV issued a Statement of DET NORSKE VERITAS • Compliance, for design conditions as follows: STATEMENT OF COMPLIANCE I • - P design < 15 kPSI • - T design < 480 °F (250 °C) • - Water Depth < 2700 m • The design and qualification program was further done in accordance to { • • ISO 13628 "'". w' :=. �.�.. • • API 17D/ API 6A. • NACE compliance �. An-4 -:- ' -7 L y i d • • • 2.3 Topside Meter Components • • The Meter is built with all parts in one unit with little need for final assembly on site. The only part which needs to be assembled is the gamma source. • • The MPM Meter does all measurements and calculations locally in the meter electronics, and transmits the measured data to a SCADA (control system) at the host platform, and /or the MPM • terminal (PC). • The main components of the MPM Topside Meter are as follows: • - Mechanical parts, including sensor, antennas and transmitters. • - Electronics system. • MPM Terminal and Communication system. • • • • • • • TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 7 of 41 Project Confidential • • • • • • • • MPM • LftitiPhasetatetErs • • 2.4 Mechanical parts • • • • Outlet connection — • — Electronics Enclosure • Gamma Detector — , ei' 4,,. %w 414 • 1 - 1NT „, , 4 / — Single Energy Gamma TOW • • tliil • Sensor Body Electronics/ Transmitters ,e Flow computer • , • . 3D Broadband 'iv Salinity Probe t ` k section • ,,,, ir ; 1 , . Termination Box • Venturi . • `t ...-741e.- fir` • Inlet connection Vi • • • The MPM Topside Meter and its parts in detail are shown in the figure above. The pressure and • temperature transmitter is optional. The temperature transmitter is recommended mounted in the blind- • T up- stream the meter. To the right on the figure above is the electronic canister containing flow computer and other • electronic, hart modems etc. • The flow first passes through a Venturi, with differential pressure sensors at the inlet and optionally at • the outlet section, which are used to measure the total mass flow rate. The Venturi is also used to • ensure radial symmetrical flow conditions in the 3D BroadbandT section downstream the Venturi, where also the gamma detector system is located. • • • • • • TD -010 - Installation and User Manual - MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 8 of 41 • Project Confidential • • • • • • • • • Mm • M.M.P1 • The functionality of the different measurement elements is briefly explained below: • • Component Function (simplified) • Venturi Constriction which generates a differential pressure between two points for measurements of mass flow rate. It also generates radial • symmetric flow regime for better measurement conditions. • Differential Pressure Used to measure pressure drop over Venturi, and from this deriving • Transmitters mass flow rate measurements. The dP transmitters are connected to • the process via remote seals • 3D- Broadband section Main component of the tomography measurement system, used to make 3 dimensional measurements (pictures) inside the pipe. • Measurements are performed in many planes (up to 27), and at • typical 25 frequencies spread over a large frequency band (MHz to GHz). The measured permittivity is particularly useful for water cut • and salinity (wetgas) calculations. • Salinity probe The salinity probe is mounted in the 3D Broadband area, and is used • for measurements of the water conductivity. From the water • conductivity, the water salinity and water density can be calculated. • Pressure Transmitter Inline Pressure Measurements. The transmitter is connected to the • process via remote seal. • Temperature Transmitter Inline Temperature Measurements. (Recommended mounted in the blind -T up- stream meter) • Gamma Detector Used to obtaining mass absorption measurements in the centre of the • pipe. The mass absorption measurements is used (in combination • with 3D Broadband results) to calculate the effective mixture density in the cross section of the pipe and in situ gas volume fraction • measurements • Electronics Electronics system which performs flow and associated calculations • based on input from all sensors and transmitters. Very high quality • system, with MPM primary uncertainty specifications • Graphical User Interface Web based service, which serves as the interface between the users • and the meter. • All transmitters in the MPM topside meter are high performance versions. They are rated after • application requirement and can be delivered as high pressures and high temperatures versions, • typical 1035 Bars and 250 °C. The transmitters are connected to the flow computer via ModBus protocol. The temperature element is connected with the process via a thermo well. The range of the • pressure transmitter will be application specific. • Further descriptions and details about the MPM Topside meter are found in the Reference • Documentation (See Table of Contents). • • TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 • Project Name: Magnolia, Entrada Page 9 of 41 Project Confidential • • • • • • • • • mpm • • • 2.5 Electronics System • The electronics system used in the MPM Meter has been especially • designed and qualified for problem -free operation in both topside and • subsea applications. It has particularly been designed to survive in severe and violent conditions. • 744 • The field electronics system is located in the meter housing. The software running on the electronics is the "brain" of the meter and does • all data recordings, calculations and transmittal to surface. • All electronics, apart from the gamma densitometer, are rated for the full • • r i temperature range of -40 °C to 85 °C When l th industrial temperature �aiigc of --ry to 85 i�cn selecting the electronics units for the system, special attention was made towards • finding modules with high MTBF figures which had undergone vibration • and shock testing in addition to HALT (Highly Accelerated Life Time Test). • • • • • • • • • • • • • • • • • • • • • • • TD-010— Installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 10 of 41 • Project Confidential • • • • • • • • • mphm • • 2.6 MPM Terminal and Communication system • In addition to the Field electronics, a MPM Terminal is needed for configuration and service of the • MPM Meter. The MPM Meter can also be linked directly (or indirectly) to the Control system (SCADA) • of the host platform. • It is possible to connect to the MPM Terminal from remote locations, such as onshore operations • centres, or from the MPM operations Centre. • The MPM terminal is a tool for logging, calibration and configuration. The physical form of the standard terminal is the 1U form factor, for mounting in a 19" rack. Dimensions for the 1U terminal is; height • 4,3cm, width 43,0cm and depth 67,2cm. Other dimensions may be supplied upon request. • • • • MPM Meter electronics and MPM terminal • • Remote FIELD • P SENSOR AND ELECTRONICS • o_ a • 53 0 Modbus l • mpm ,mss 485 or TCP /IP Flow u I / tom' RF • Termina 1 Compute PC1 DSP N serial Electronics, • i i iii / II 2 j32 211— II • 7 , :i i , • SCADA Transmitte Sensor • . • • The MPM Meter communication protocol is MODBUS v1.la. The protocol may be on RS485 or • TCP /IP. There are two RS -485 serial lines, configurable for data rates between 1200bps and 921.6Kbps. • In addition the log database, located on the terminal, can be accessed through ODBC. • In order to optimize communication with the meter over slow serial connection, parts of the MODBUS • map has been made customizable. That means that there are blocks in the map where variables from • the static map can be stacked in any desired combination. This enables more efficient transfer since the desired variables can be transferred in one MODBUS frame, provided the desired registers • consumes no more than 251 bytes. • • TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 • Project Name: Magnolia, Entrada Page 11 of 41 Project Confidential • • • • • mm • MaaPretasfatetara • The MPM Terminal software consists of several different components; meter communication service, • database, web service and GUI application. Below is an overview of the MPM Terminal components. • • The MPM Meter communication service is • responsible for communication with the MPM r h termjnal (optimnat ) Meter logging m • eter. It is possible to connect multiple meters to 1 and one terminal. Its tasks comprise the following: Communication • • Poll configured measurement variables at configured intervals. • • Log the polled measurement variables. • • Log alarms, events and diagnostic Dot information from the connected meters • • Create and distribute periodic reports for • service persoi ['lei by e-mail, if SMTP LE= server is available ,,� _ • • Run diagnostic functions • • Upload software updates • Upload configuration /calibration data. • • Update average values measurement _ • data in the database. • The database is a repository of information for the • user. In addition to the logged measurement Remote PC • variables from the meters stored here, all configuration updates, software updates and diagnostic data are also stored in this database. • It is easy to create views for report generation, accessible through ODBC. • • The GUI application is the main interface for the MPM meters and is made as a web service. The GUI can either run locally at the MPM Terminal or be accessed on a local machine connected to the • Intranet/Internet. • Access to the GUI application is protected by username and password. In order to change any settings • you need a user with extra privileges. The GUI is described in separate chapters. • • • • • • • • • • • TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 • Project Name: Magnolia, Entrada Page 12 of 41 . Project Confidential • • • • • • • • • MPM • • • 3 INSTALLATION • • 3.1 General • The installation procedures cover all steps from receiving the Meter, until installation is complete and • field commissioning can start. • • 3.1.1 Check of meter, flanges and covers • Before installation starts it's important to • 1. Check that the flange covers are undamaged, and protecting the flanges. • 2. All stud bolts, nuts and seals must be checked for potential damages. If hubs are used • their sealing surfaces and tensioning bolts have to be inspected. • • 3.1.2 Mechanical installation • The Meter shall be mounted with flow direction upwards, if not else specified. • The gamma source has to be mounted to the meter. Make sure the shutter mechanism is shut and • locked while mounting the source. • The vertical alignment should be made to secure a correct vertical position. An angle of plus /minus 2 • degrees off the vertical line can be accepted. If a larger inclination is observed, then MPM shall be • contacted for evaluating the situation and providing advice. • Make sure that it is possible to remove the electronics canister. In case of hardware failure this has to be removed. The free space above the electronic canister has to be the length of the canister lid in • addition to lifting equipment. • Please note that since the MPM Meter contains an electronic measurement system, NO • ELECTRICAL WELDING must be performed on the meter body or parts, nor in the adjacent pipe - work, neither during mechanical installation nor at a later point. This might cause severe damage to • the meter. • • • • • • • • • • TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 • Project Name: Magnolia, Entrada Page 13 of 41 Project Confidential • • • • • • • • mpm • • • • 3.2 Site Installation • • 3.2.1 MPM Terminal • • The MPM Terminal shall be installed in an appropriate location. • The Terminal may communicate with the Meter on or TCP /IP or RS485 . The Topside Meter must be connected accordingly. TCP /IP is recommended since this provides more flexibility and enables • better service and support of the MPM Meter. • Verify that communication with the meter is present by starting the MPM GUI. • • 3.2.2 Empty Pipe Verification test • This section is only applicable if static conditions are feasible. E.g., if the gamma source has been • removed during transportation of the MPM Meter, an empty pipe calibration has to be performed. The • calibration procedure shall only be performed with a warm electronics and warm gamma detector. • Below is a stepwise procedure to verify the empty pipe calibration parameters for the Sensor. • Item Description • 1 Make sure that the sensor is clean inside • Perform a logging in WetGas Mode for 300 seconds (5 minutes). • 2. Store the result to file : Site test — S /Nxxxx — air check WG Mode • Compare the expected vs. measured value for the gamma counts. The expected • 3 value should be within 1 standard deviation from the measured value. Consult MPM if the measurement is outside the acceptance criteria. • • 3.3 Electronic temperature surveillance • • The electronics canister is fitted with cooling ribs on top. To avoid the inside temperature to increase • above specified temperatures, there needs to be free air flow around the electronics canister. • The sun can also contribute to temperature increase inside the canister. If the meter is exposed to severe sunlight over longer periods (like the desert) it needs to be shielded towards direct • sunlight. • 3.4 Installation completed • When the above steps are successfully completed, the installation process is completed. • Next phase will be start up and configuration of the Meter, as detailed in the Commissioning Section. • • • • TD-010 — Installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 14 of 41 • Project Confidential • • • • • • • • • • mpm • • 4 COMMISSIONING • • When the Installation Part is successfully completed, the Commissioning part may start. During • Commissioning, the work should be performed as per the steps and guidance provided below. • • 4.1 Meter Start Up • The MPM Meter starts automatically when it's being powered up, and the context of this first step is to • assure that the Meter indeed has started, and that the communication between the MPM Terminal and the meter is functioning. • To do so, start the GUI, and select the meter you want to check. Make sure that measurement data is • valid and that no alarms are present. • • 4.2 Meter Calibration • The Meter is factory calibrated prior to shipment. There is no need for a calibration at site during • commissioning unless the gamma source have been removed during transportation. If the gamma source is replace with the same used at the factory, a single point empty pipe calibration (air) is required. If the gamma source is replaced with a different unit, a two point calibration in air and fresh • water is required. • • 4.3 Site System Test • • 4.3.1 Transmitters • Reset the transmitter communication counters and log for minimum 1 hour. Record total number of • polls and error messages during the entire period and fill in table below. The error rate is calculated as: • Error Rate = (Number of errors /Number of messages) * 100 • Acceptance Criteria: The test is accepted if the error rate is less than 0.1%. • Transmitter Number of Number of errors Error rate [ %] Conclusion messages • dPinlet 1 • dPinlet 2 dPoutiet 1 • dPoutlet 2 • Temperature 1 Temperature 2 • Pressure 1 • Pressure 2 • Gamma Detector • • • TD -010 — Installat'ion and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 15 of 41 • Project Confidential • • • • • • MPM • ..hgs..°,,cn • 4.3.2 External communication ports • • Before starting error logging on external communication ports, data logging shall be started with a • minimum poll rate of 1 Hz. • 4.3.2.1 External Serial Ports — RS 485 • Connect the MPM Terminal to COM 1, and perform logging of number of messages and errors for • minimum 1 hour and fill in table below. Repeat for any additional COM ports on Meter. • Acceptance Criteria: The test is accepted if the error rate is less than 0.1 %. • Serial Port Number of Number of errors Error rate [ %] Conclusion • messages • COM 1 COM 2 • • The serial ports have been tested with Modbus poll and interface to the control system. No • communication errors have been detected. • 4.3.2.2 • 4.3.2.3 Ethernet (TCP /IP) • Connect the MPM Terminal to communicate with the MPM Meter with Modbus over TCP /IP. Perform • logging of number of messages and errors for minimum 1 hour and fill inn table below. Repeat for any additional Ethernet ports on Meter. • Acceptance Criteria: The test is accepted if the error rate is less than 0.1%. • Communication Number of Number of errors Error rate [ %] Conclusion • Channel messages • Primary Eth1 port • Primary Eth2 port* • Only applicable for electronics with redundant Ethernet car • • 4.4 Meter Configuration • • 4.4.1 PVT Data • To provide measurements in accordance with customer requirements and as per its specifications, the MPM Meter needs a certain amount of information about the different constituents of the multiphase mixture (oil, water and gas). These configuration data is often referred to as PVT data, • and can be provided to the MPM Meter manually, or automatically, depending upon the agreed set- • up. • In general, the MPM Meter offers a high tolerance to shifts in configuration parameter, dependent on • the flow conditions in the meter. This means that for a particular well, data specific values for that well can be used. Or, if the PVT properties for several wells are more or less the same, a common set of • configuration data can in most circumstances be used. An average composition for several wells • TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 • Project Name: Magnolia, Entrada Page 16 of 41 • Project Confidential • • • • • • • • • • mm • Rdatt, scklettr • which originates from the same reservoir may in most cases be sufficient. During the project and commissioning phase, it is recommended to perform an evaluation of the wells that will be used to • evaluate the need for multiple PVT setups. MPM can also during commissioning perform an evaluation of the goodness of the PVT data and provide recommendations whatever the configuration • data is sufficient in order to meet the performance specification for the Meter. • While the above comments are valid for most parameters, the conductivity of the produced water is • different. At low WLR a potential erroneously specified value for water conductivity has little impact • on measured flow rates. However, once the WLR increases, and the emulsion turns into water- continuous (typically for WLR of 40 -50% and upwards), a potential error in the specified value for i• water conductivity can have severe effect of the measured water liquid ratio. This effect is more or • less the same for all brands of meters. Except the fact that the MPM Meter can be outfitted with an option of Auto configuration functionality. With this functionality, the water conductivity is • automatically measured by the Meter, and there would be no more need to provide manual input • values (which would also eliminate the need for sampling). • In the table below are listed the different configuration data. The table below also indicates the • importance of the various configuration data in order to maintain the uncertainty specification for the • meter. If some of these parameters are wrong, the meter will work, but some of the measurements may be outside the specified uncertainty limits. • Key parameter Importance • • • Oil density Important, particularly at low GVF and low WLR • Gas density Important, particularly at high GVF • • Water conductivity (low WLR) Less important • • Water conductivity (high WLR) Very Important' • • Water density Medium' • • Surface tension oil /gas (P > 15 bar) Less important • Surface tension oil /gas (P < 15 bar) Important for wet gas flow conditions • • Viscosity of gas Less important • • Viscosity of oil (< 2 cP) Less important • Viscosity of oil (> 2 cP) Important, particularly for high viscosities • • All the parameters for the oil and gas phase can be calculated based on the total hydrocarbon • composition for the wells, and this is the preferred way of obtaining the parameters for the oil and • gas phase. E.g., temperature and pressure dependent look -up tables for the oil and gas density, viscosity and oil /gas surface tension can be calculated based on the composition. • The tables can be downloaded directly to the Meter using the GUI. A typical hydrocarbon composition • (total) which can be used for this purpose is shown below: • • Componen Density t Mol % Mol wt [kg/m3] • • 1 If the MPM Meter is equipped with the automatic configuration option (salinity measurement), the • importance is low • • TD-010 — Installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 17 of 41 • Project Confidential • • • • • • • mpm • r,t.,t1Pha ∎ • Componen Density • t Mol % Mol wt [kg/m3] • N2 0,354 28,014 • CO2 1,154 44,010 C1 55,767 16,043 • C2 4,658 30,070 • C3 2,774 44,097 1C4 0,583 58,124 • nC4 1,263 58,124 • 105 0,546 72,151 nC5 0,711 72,151 • C6 1,197 85,300 • C7 2,400 90,000 731,7 C8 2,710 103,700 755,8 • C9 1,992 118,800 748,4 • C10+ 23,889 298,700 913,8 • Based on the composition, MPM can calculate all the required data for the oil and gas phase using • Calsep PVTSim (Equation of State). The measurements from the MPM meter can together with • together with Calsep PVTSim and the MPM Meter simulator also be used to verify the well • composition. If the total composition is not known, the total composition may be derived from oil and gas samples • at a known GOR. This may performed during the commissioning phase if pure oil and gas samples • can be obtained under pressure. A total composition for the hydrocarbon phase can be obtained by • analysing the gas and oil composition separately and recombining the composition for the oil and gas phase at the GOR measured by the MPM Meter. Please contact MPM for further details. • Even if salinity measurements are included in the MPM meter, it is recommended to put in density • and conductivity for the water as a fallback option until the meter has made a proper measurement. • In order to calculate the PVT tables MPM need to be supplied with the following data: • • Hydrocarbon composition of the actual well(s) • • Operational range of temperature and pressure • • Density for water at a given temperature (e.g. 15 degree Celsius) • Salinity or conductivity for the water • Please also note that if measurements are done for Hydrocarbon Mass basis, then the oil and gas • densities are of less importance since an overriding of the gas tends to be followed by a similar under • reading of the oil and visa versa. • • 4.4.2 Conversion to Standard Conditions • • The MPM Meter can also provide measurement outputs at standard conditions or any other fixed • temperature and pressure conditions such as test separator conditions. The conversion from actual to standard conditions can be done with or without phase transfer between the oil and gas phase. • • TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 • Project Name: Magnolia, Entrada Page 18 of 41 • Project Confidential • • • • • • • • • • rpm • tA.lii 'i t—,tfetes • The Meter is then configured with the density of oil and gas at standard conditions. These parameters can typical be calculated form the total composition for the well. If the calculation is performed without • any phase transfer, the standard volume rates are calculated by dividing the measured mass flow • rates of oil and gas at actual conditions by the density at standard condition. • A temperature and pressure dependent look -up table for an oil to gas transfer factor is used to calculate net phase transfer from oil to gas (user selectable). The amount (in mass terms) of oil which • is degassing is calculated by multiplying the oil mass rate at actual conditions by the oil to gas mass • transfer factor. The mass which is degassing is added to free gas and divided by the density at standard conditions to obtain the total gas flow rate at standard conditions. The oil mass at standard • conditions is reduced by the amount (in mass terms) which is degassing such that the total • hydrocarbon mass flow rate is unchanged. • The look -up table for the oil to gas transfer factor can be calculated based on the composition of the well using a PVT simulator such as Calsep PVTSim and downloaded to the MPM Meter using the • GUI. • • 4.4.3 Two Phase wet gas Mode • In two phases wet gas mode the MPM Meter requires the GOR as an input parameter. The GOR can • either be downloaded directly to the meter using live PVT as described in section 4.4.5 below or based on a temperature and pressure dependent look -up table. The Zook -up table can be calculated • from the composition for the well. • • 4.4.4 Input of look -up out and g a. densities • tables PVT input ty e o densky t Oil ae tAkshal • In this case, oil and gas Pretsure t • densities are provided at r? 10 15 840 20 850 given pressures and 10 83 G 930 • temperatures in tabular Temperature 830 840' Temperature 20 a 840 850 850 riso 870 sea • form. ldeg q 40 850 Bw a1n 50 879 89¢ soo • To find the correct densities sa: tks+al • for a given temperature and wee pressure, the Meter will do a 10 10 10.02 1003 10.04 • linear interpolation between 10 0 e 6 8 the data points in the table. s 9 e TemPerattse 33 10 10 10 10 10 • In the figure is shown typical Id40 ci 40 11 11 11 11 11 • density table so 12 12 12 12 12 The other PVT data are • keyed in via the GUI/ PMP ( oK !Ham I Terminal. • • • • • • TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 19 of 41 • Project Confidential • • • • • • • mpm • • • 4.4.5 Continuous input of density values (Live PVT) • PVT data can be transferred on a continuous basis from the platform control /SCADA system (live • PVT). The configuration data is written into specified modbus registers in the MPM Meter. • The live PVT can be enabled and disabled from the process data set. The live PVT functions such • that the live PVT data has a higher priority than the data from the look -up tables. E.g., if there is no • data (or NAN is written to the modbus register), the corresponding PVT values in the look -up tables are used. • • Hence, it is possible to use a combination of live PVT and Zook -up table such as : • 1) Viscosity of oil and gas and surface tension calculated based on look -up tables • 2) Gas and oil density downloaded via live PVT 3) GOR (required for two -phase wetgas mode) downloaded via live PVT • • • • • • • • • • • • • • • • • • • • • • • • TD-010 — Installation and User Manual — MPM Topside Meter.Rev01 • Project Name: Magnolia, Entrada Page 20 of 41 • Project Confidential • • • • • • • • • mpm • • 5 OPERATION • • 5.1 Starting the MPM User Interface • 5.1.1 MPM Terminal Login [_ a -_ .} • • Click on the Icon for the MPM GUI, a login- window like User. +User • the one in Passworrt P • Terminals: • Figure 1 will appear. If the Name I Server name/IP address (, desired MPM terminal is not available in the list, it must L Terminal mpmaoop tErrran • be added. Click the plus button to add a terminal to the • list. Enter the server name or IP address of the terminal • and press add. • Enter user name and password, and click "Connect ". • The User interface window should appear. r Press plus to add or remove a terminal • l Connect I Cancel • • • • Figure 1 Login Window • • 5.2 Remote Access • The MPM User interface can be accessed from a remote computer if it is installed on the same network as the MPM terminal. • To set up the user interface on a remote computer, the following is necessary: • Both computers must have access to the same TCP /IP network (internet type connection) A user account (user name and password) must be available on the MPM terminal GUI for the remote • user. • The MPM Software must be installed on the remote computer. • • 5.2.1 Setting up the remote computer • Assuming that the remote and the MPM terminal is on the same network, and that a user account • exists, the setup process is straightforward: • Copy the MPM GUI software to a folder on the remote computer Advanced users may want to create a shortcut (icon) in the Windows start menu, on the desktop for • easy access. If so, the shortcut should point to the file MPMGUI.exe.The software installation is now • done. For first time used, a server name has to be added, see 5.1.1 for instruction on how this is done. • • TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 • Project Name: Magnolia, Entrada Page 21 of 41 Project Confidential • • • • • • • • • mpm • • • 5.2.2 Main page • The Main Page of the user interface consists of a standard MS Windows GUI divided into three parts, • a menu bar (top of window), an information area (left hand side of window) and a graphics area (see • Figure 2). In addition, the status bar (lower part of the window) is used to give some information about the meter. • The Main Page serves several purposes • - Provide a trend of flow rates, fluid properties and flow condition — as a function of time. • - Shows numerical, instantaneous values of flow rates, fluid properties and flow condition. • - Display information of the meter state The menu gives access to meter configuration, adding or removing MPM Meters, select different • trend, and look at diagnostics information. Consult MPM personnel in order to alter meter add or • remove MPM Meters and to select the variables and units displayed in the main page. • MPM GUI v3.0.0.2124 <Subsea Prinrrry> (1010) •tX • Login and conBWaton Meter Service Degnosac 30 vrn. a 1 • Update trends and values - Trends --- -- -- -_ -- -- - _ -- ..- -- - - - • ® Update — D. ,-ir. n: Graph averages • - Oil, pas and water flaw - 3as (m=.1 Flow ratio (Actual collations) — wax lm =� Oil I 6 - 0�m',h • 011 m', m'fi Gas I 0.0I0fi Gas 11111111M oil, Water 1 O Olin% • Water OM 1 I sJ I [Injected MIL m Q ,h ' E • lLFartrtion MBE m',h Measured tractions - -- • W.R - _. 11 ' : .3 1011 'e - 2:05 .Y 2331 WVF 4 , 231,30 11311.X ;tam • �. 4 — 5.;.(al Gras* overages - - GVF Salinity and Corductiwty — CcrG :TSs, GDR MIME m'im' Sal I 0.61 S. • -- -- - Other 2 Cord. I O.wirnsicn • - �7 - --- -- Temperature llllllllliiip Beware O 1 Barg K 1 sa I • Density MU We meer • Velocity llllllllll ': reds SM IIIi .] 23i •s- -»a u. - rot • Water conductivity ME n+s' n 1231023 ura 325333 Water aalirity Illllllllli %: —w.® Graph averages - Stale • k Idas 11111111 E' L,7R and GVf —5a °, Vigil 1 70C C'� : � ix •z N - active p r o c e s s data set - --- -. - s. / 4 1 s;- -c x • S t 3 K Q Status' OK - is u - _o: ... Q Meter Online z _ -c • mpm • . 3 ZZOI n ' utlm ua• us:z 0 Undefined 0 WGM nwde (3phase) 0 Measured w. density 0 Measured w. conductivity ;Sialie / Slug 'Quality 0% t 700%: ,: Figure 2 Main page showing Menu (1), Information area (2), Graphics area (3) and status bar (4) • • • • TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 22 of 41 • Project Confidential • • • • • • • • • • mPm • • 5.2.3 Menu • The Menu (Figure 3) gives access to the following items: • Login • Login in as another user, (change user level) • Select Meter • Select other Meter to display data from (if more than one meter is installed) at the MPM Terminal • Configuration Report • Prints the configurations of the MPM terminal • View event log • View details about events on the meter (See also Section 5.4) • • MPM GUI v2.0.0.1902 <Local meter? ( #100) • Login and configuration Meter Service Diagnostic • Figure 3 MPM Terminal Menu • • • • • • • • • • • • • • • • • • • • • TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 23 of 41 • Project Confidential • • • • • • • mpm • • t.,....,,e,..$ • 5.2.4 The Information area • • The Information area displays current values for — Update trends and vales --- • flow rates, measured fractions and other ® Update • measurements. - - - - -- - -- _ ..�..- - Flow rates (Actual conditions) A check box on the top makes it possible to Oi 328 invh stop the updating of values. This is useful if the Gas 253.5 m sm • operator wants to stop the update and evaluate — the data . .._..__._ 3 ' 4 "y' • The flow rates are presented in the selecte fractions • _ . 1NLR 9 . 3 x • units. WVF 0.0% • Measured fractions display the fractions =, GVF 87.5 % calculated by the MPM Meter. GOR 0.0 r'lm= ; • • The area called "Other" show some of the Other transmitter readings, calculated velocity, Temperature ! NAlt • measured Water Conductivity (converted to P rime 16.3 Barg 25 °C) and measured Water Salinity. Density 0.0 kg/m' 4 • The status light is green if no alarms are active d 204.9 mBar • on the meter. If an alarm situation occurs, the Velocity 0.0 mis j • light switches to red. SY,n 0.0 y • Click on the light to view Alarm status. From the Water conductivit 263 mS/cm • Alarm status it is possible to click "View event log" to see the details (See also section 5.3). Water sanity 0. Scale Index 1 NA % • The meter connection state light is green when • the meter is online. If the meter is offline or Status having communication error (no contact with the Q Status: OK meter), the light switches to red. 0 Meter Online = • I If Remote, yellow light is displayed if limited or • no connectivity. If limited or no connectivity Figure 4 Information area • exceeds one minute, the light switches to red. • • • • • • • • • • TD-010 — Installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 24 of 41 • Project Confidential • • • • • • • • �. ., • • • • 5.2.5 Graphics area • Trend: • _ Graph averages ! Qil, pas acx aterflaa el I 32.0'n?hr • _' {�' i1i "" I v � R( N,{ r +tM �.�N1# lrfsn�'\ Water 3.5kn, • • Gas I 258.11rrr/h • • 12 11:.7gr37 '1:5 tlaT.Y. -- - sa. (; _ Gr aph averages Sal 0.8k _ • Salirity and Cor uctrrity 3_ -- or, . t S':r5 OrMAr } �` J�� V a— . • ! l� r l r P�i �t3 �� h � t � � j ��(L °ter` s Cond. 2.73jmS /cm Graph averages -- M x 7 rN r �� "� 1r�1�4�1( • • • d d- 2 d s _ • d2 • d 46.1120[- d. t�12,15T �t�� "?� dittt7C0111.2X7 '17775 i 11590 I • — WLR • d - WLR 9.81x • -. GVF 87.9k a • - _sa • • • • • 01112X7 01112X7 11�, 05172247 05172247 6; � 122520 ' v5 r. 1114sx Figure 5 Graphics area MPM • The graphics area shows three trend plots that are continuously updated. The graphics area shows • trend of selected variables. Graph averages of the trends are shown on the right hand side. It is possible to right click in the trend area and set or change axis limits. • If the trends are static, it is most likely caused by either update is turned off, a communication error, or • the meter is not enabled in the configuration. Each graph can be configured to display different data independently. It is also possible to set the Y- • axis and Y2 -axis for each graph to fixed min and max values; the default is auto. The available trends • • are dependent on logged variables. • • • TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 25 of 41 Project Confidential • • • • • • • • • mpm • 5.2.6 Status bar • The main window have a status bar (Figure 6) in the bottom of the window that displays information about the metering state. • Q4 Maid - - - - _- - - -- • � p Measured w.a p :sue •t -- -- - mug Quay cm p 1on • Figure 6 Status bar • • From left to right, the items on the status bar are as follows: • • Liquid Phase, Oil Continuous/Water Continuous, 3D BB disabled o In MPM Mode, this section shows whether the flow is oil continuous or water • continuous o In WetGas Mode this flag is undefined • • Multiphase Mode/Wetgas mode, 3D BB disabled • o This flag show the selected mode of the meter • Measured density • o This flag is green if measured water density is used. If it is grey, a static value or • LivePVT is used. • Measured conductivity • o This flag is green if measured water conductivity is used. If it is grey, a static value or • LivePVT is used. • Stable /Slug • o This indicates a stable flow regime (few gas - slugs) or sluggish regime (many gas • slugs). The measurement is based on data from the last 20 seconds. • Quality Index o Not implemented. • • • • • • • • • • • • • • • • • • TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 • Project Name: Magnolia, Entrada Page 26 of 41 Project Confidential • • • • • • • • • • tut1 MPM • • 5.3 Alarm Status • The Alarm status provides information about the transmitters, Software and External Communication. • When a transmitter is installed it will display a green Tight when everything is ok and a red light if • errors are encountered. If a transmitter is not installed a grey light is displayed. • If errors occur, click the "View event log" button to see the details (see section 5.4). • Alarm status • • 1 2 Gamma • Q dPlniet 0 • dPOutlet • Pressure ( • Temperature • 3D Broadband • Software (� • External Communication (� • ij OK Q Failed (;) Unavailable • I View event log I Close • • • Figure 7 Alarm status • • • • • • • • • • • • • • TD -010 - Installation and User Manual - MPM Topside Meter.Rev01 • Project Name: Magnolia, Entrada Page 27 of 41 Project Confidential • • • • • • • • Mm • • • f ,,frf,; • 5.4 Event log 0 • The event log lists events with the severity "Info ", "Warning" or "Error ". It is possible to get a selection of events limited by severity, process and /or event id. To view additional event information (Figure 9), • double click the event in the list. • Event log an • e • Sevaty Process Event id _ ❑ Irk ❑ DSP Intedece ❑ Mete Corenesnicatico Service iA data Trout (Transmitter data a boadbe d datal has laded (16398) • ; lace gap m raw-data owned. No interpolation done (76400) ❑ Wang ❑ External Communication ❑ Process Supervisor ;A strange data vane has occued (164011 IAccumdated pehse at channel (20492) ❑ Ena ❑ Flow Cdculatims 0 Transmitter Interlace ! Calculation issue (163881 • Could not Ind poses: (4100) ❑ Lag Could not open fee weh cdbrabon constants (16396( .. _.... ___ 1 Soda Proem l Evan Id Event D esaptign Date Swirly • ► 08.1220061303 Wang Fbw Calol MSS 88 Calculation issue • I 06.1 2 2006 1258 Warning Flow Calculations 1 Calouletiwror e 08.1 2 2006 1253 6388 Warning Flow Calculations 16388 Calculation issue 08.1220061250 4? trio DSP Interface 20491 DSP/Electarics diagnosis value III 08.1220061250 VII* DSP Interfae 20492 Accun/atedpehse ref charnel 08.1220061293 ` Flo trio DSP Interface 20490 DSP Send pat diagrosisvdxs C18.122006 1048 Wamg Flow Calculations 16388 Cdculaton issue ..... 06.1 2 2006 1243 Warning w Cak,etlons 16368 Cakulalion issue • 03.122006 1238 Warring Flow Calculations 16388 Cakulalion issue 08.1220061235 J Info DSP Interface 20492 Accumulated pahse ref charnel • (0122(�1210 122006 , )irfo DSP Wed ace 20491 DSPiElecbaics dagnosis values 06.1 2 2006 12% Ir4e DSP Interface 20490 DSP Said port dragrosif value= • .08.122006 1233 m Waring Fbw Cakulatan 16388 Cakuldion issue 08.1 2 2006 1228 4 Wamg Flow Calculations 16388 Calculation roue _ 0E1220061223 Waring Flow Cebietiorn 16388 Cdciation issue • - _ 08.12.2006 1220 Info DSP Interface 204% DSP Said da port gnosis values 06.1 2 2006 1220 i Into DSP Interface 20491 DSP/Electaria degrosc vdueo - 00.1220061220 3) Into DSP Interface 20492 AmanJded Dehse ref charnel • 08.1220061218 Wang Flow Calculations 16388 Calculation issue 08.122006 1213 .Waring Flow Calculations 16388 Calculation issue oat 220061208 Wamarg Fbw Calculations 16388 Calculation issue • 01122006 1205 ) M Info DSP Interface 20492 AcUb at ted pehse ref channel I Fist page I I Previous page I Nerd page I I Last Page I 'Page 1!1200 I • • Figure 8 Event log • Event properties n' Event Id 20490 Seventy Irdo * • Date: 08.12 2006 12 50:56 Process DSP Interface I 4. J 1 • Meter Local Meter Description: ._ • DuagmErrmasum • • Adcitiond data: C Bytes (Hex) f Ted • �_ PSU -OK, TXU -OK, PXSMU -OK, TXSMU- OK 41CU .RXU -OK, H-OK • • • • • • Figure 9 Event properties • • TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia; Entrada Page 28 of 41 Project Confidential • • • • • • • • • • mm • ttaPhaseMe firs • • 5.5 Trend /export data • This dialogue is available for user with Supervisor privileges. in order to log on as Supervisor, select • Login dialogue from the "Login and configuration" menu. • In the "Trend /Export Data" dialogue it is possible to view historical data for all meters with the log • interval: user defined (e.g. 0.5 sec), 1 minute or 1 hour. It is also possible to export data to a comma separated file. • • - trend and export data ■ ®_S • Mete: Il lntemal test meter _i Start 10611.2007141201 ' 15 mates _1 i — Log interval '0.5 second [ View I I Export I Close I Trend • Available variables: • Local meta dPl det dPlr sl1 dPlnkt2 • — nocatw Ln:tnt.t7 — Via.- .anst. — miat.tA..aroe.. : [m =:nt dPOutlet dPOulell •`"' dPOutlet2 • Emulsion codex _� ,p FCStatus • \A-3,1.,AlrtiMelt ^uU�` p '0ytt'.A` .P , Seer - 1 ' .kdri 4't�1 4U F ` / Pidlp"' GammaCourA Gas density • Gee velocity G0R Mass G05 Standard Mara • KR Standard Volume GOP. Volume GVF Actual VoYme • Liquid velocity MeteStatus Mix deredy • w Oil densiy - Pressure Pressure' • Pressure2 QFWa amW ater Actual Mass QFamWater Actual Volume • QFamWater Standard Mass QFormWater Standard Volume QGas Actual Mass • QGas Actual Volume QGas Standard Mass y:_ QGas Standard Volume • 00d Actual Mass .ri.,,ti...„,.,,n...yr.,s , 1r-•yvv , .w.., , -„ ,,,,,�,. - .,,...,v-s�� ,r 00i Actual Volume • QOd Standard Man QOd Standard Volume 1 c _� .,� Quaitylndex I ( .., -.... QWater Actual Man .. • • • Figure 10 Trend /export data • • • • • • • • • TO -010 — Installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 29 of 41 Project Confidential • • • • • • • • mpm • mopttAwas • • • Dialogue toolbar • v • • Figure 11 Toolbar Button • • The toolbar button (Figure 11) functions are as follows: • 1. Page setup 2. Print the graph • 3. Print preview 4. Copy the graph • 5. Previous • 6. Next • • 5.6 Meter Configuration • These dialogues are available for user with Supervisor privileges. In order to log on as Supervisor, • select Login dialogue from the "Login and configuration" menu. • • 5.6.1 Select active process data set • With this menu option the user may select a process data set for the current MPM meter. There are • 10 process data sets available for each MPM meter; each set can be configured individually. The next • section explains the various data input fields available in a process data set. • 5.6.2 Create New Look -Up tables (PVT gas and oil properties) • • In order to create a new look up tables in the process data set, density gas, density oil, viscosity gas, • viscosity oil, surface tension and Gas - oil - ratio(GOR at actual conditions) as function of temperature and pressure is needed. When these parameters are available, open the Process Data Configuration • page and choose which process data set you want to enter data into. Open the PVT, oil and gas • properties page and type your obtained parameters into the tables as function of temperature and pressure. • Then close the window and press 'send to meter' to upload the tables to the meter. • • • • 5.6.3 Process data configuration • • TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 • Project Name: Magnolia, Entrada Page 30 of 41 • Project Confidential • • • • • • • • • mm • In order to get accurate measurements it is vital to give the MPM meter accurate information about • the physical properties of the fluid components. • This is done by selecting Process data configuration from the Meter menu. • Process data configuration • 41_ 1 7 .1 1 Process datamt -- - -- - - - - -- - - - _ -- -- -- - Information - - -- — - - -- -- -- - -- -- - --- - -- - - - Water calibration - - -- - -. _ .. ..- - -_ . - -- - • Name Iowa/roe Compodion for of welts on Chafe( I j : water conductivity Q Fared 0 Measured - - - • DescrPtron ' Water d re y Q Feted 0 Measured - Water • I ; Density Trr[[ - - Density k9/m3 at temperature ® deg. C ■ Conductivity 91 mS /cm at temperature 25 deg. C • -- -... - __ -- - - . _ .. ..._.,. - -- - Conde '.e - - - - - - --- -- - --- - -. .. _ - Metering rater Measurement mode O WetGas Q Multiphase O Automatic MPM GVF I 90 , - 1 _) • :- : -., WGM GVF 1 97.01: 1 , . ,r . H ,, • ® Use Broad Band den* - Standard conditions • Mminum OVF for Broad Band measurement 1 99.51 Dense a 1 x.0071 kglm* 1 1 51 deg. C Maratrram GVF for Gamma rmeasumant 99.01 Derek, gas 1 0.9071 k97nf M 1 OI bag • ❑ Use Movrg Average filter on output data ..; , • ❑ Use faced OCR Fixed GOR 1 1 ' , O Use Lookup table ❑ Disable 88 Feed WLR 1 7 1 ❑ Add flashed gas from oa • ❑ Enable Live PVT input - Dielectric constant ❑ Overrde 1 Dielectric constant et offset - - Gas - - - - , Water/gas surface tension - - • 00 1 , ) dog. C Oa 1 01 Gas Isenbopic Exement 1 1 41' ® Cale surface tension from water safe* • Gas 1 ' 1 ❑ Oven, at 1 1 bar , Gas 1 0 1 Use D Ai Dainty ❑ Surface tension water ( � - ,1 N/m • - Salt water factors Viscosity at actual conditions -- - - Water viscosity Was - - Water sanity liter Inds - - - - Mass absorption coefficient -- - 80 1 - 1 Oil 1 0.0081491Pas DO 1 07181 Misvalue 1 D51x 00 1 1 ❑ Override • 91 1 1 Gas 1 1.59E-05IPas D1 1 0.003591 Maevalue1 41$ Water 1 1 ❑ Override • B2 1 1 Water 1 ,. 1p4, ❑ we D2 1 01 : Gas 1 1-0 ® Override • I Close • • Figure 12 Process data configuration • In the following is provided information about the different options and input data: • Function Description • Metering settings Selection of measurement mode. The Meter may be forced to use • multiphase or wet gas measurement mode. If automatic measurement mode is selected, the meter switches between multiphase and wet gas • measurement mode. • There are two wet gas modes namely 2 -phase and 3- phase. In two • phase mode the GOR is required as an input parameter. A Zook -up table for the GOR can be entered in the PVT properties section. This table is • typical calculated from the composition of the well using a PVT simulator • (Equation of State) • The switching works such that if the GVF is above the GVF value "WGM GVF ", wet gas mode is selected. Similarly, if the GVF is below the value • • TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 • Project Name: Magnolia, Entrada Page 31 of 41 Project Confidential • • • • • • • • mpm • Function Description • "MPM GVF", multiphase mode is selected. WGM GVF should always be • larger than MPM GVF. In the section between MPM GVF and WGM • GVF, the last setting is used. • For low pressure applications (e.g. below 10 -15 barg), recommended • switching area would typical be around 90% GVF. For higher pressure applications, it may be desirable to use a higher GVF setting, typical • around 95% GVF. • For ultra high GVFs, an additional BB based GVF measurement may be • used. This measurement is particularly accurate for ultra high GVFs. The GVF range for the BroadBand GVF measurement can be configured by • the parameters Minimum GVF for BroadBand GVF and Maximum GVF • for Gamma measurement. Recommended values are 99.5% for Minimum GVF for 3D- BroadBand GVF and 99.0% for Maximum GVF for • Gamma measurement • Note: The Broadband GVF measurement is not available in multiphase • mode. • A moving average filter of 20 seconds can also be added to the output • data in order to provide some damping on the output data. The meter can also be configured to be forced to use a fixed GOR. This • function can be used to provide measurements from the meter if the • gamma detector fails. However, the uncertainty of the measurement will • be significant higher. • The broadband electronics can also be disabled in this section. If the • broadband unit is disabled, a fixed WLR value can be downloaded to the meter which will be used together with the remaining transmitter • measurement providing simplified calculations of the flow rates. The measurement uncertainty for disabled broadband electronics is • significantly higher particularly for slugging flow conditions. • NOTE : If the meter is configured to measure the water salinity in wet • gas flow conditions, this function will only be enabled if wet gas mode is • selected. I.e., the meter will not measure the water salinity in wet gas flow conditions if mode selection is set to AUTOMATIC. • Dielectric Constant This section allows the user to entering a fixed value for the dielectric • constant of oil and gas which over rides the dielectric models in the MPM • Meter • Dielectric Constant Offset This section allows for correcting the dielectric constant models with a • constant offset and can be used for fine- tuning or correction for error in the PVT input data. • Salt Water Factors These parameters allows for use of different salt water models for • calculating the temperature dependency of the water density. The default • values correspond to NaCI salt. • TD-010 — Installation and User Manual — MPM Topside Meter.Rev01 • Project Name: Magnolia, Entrada Page 32 of 41 • Project Confidential • • • • • • • • • MPM • • Function Description • Viscosity at actual The oil and gas parameters are not used and will be removed in future • conditions versions of the GUI SW. (The oil and gas viscosity is calculated based • on the temperature and pressure look -up tables) • The water value can be used to over ride the viscosity calculation • performed based on the salinity for the water • Water Viscosity Factors These are salt composition related factors which are used to configure • the models for calculation the water viscosity based on the water salinity. • Water Calibration The water density and conductivity can either be entered into the meter manually (fixed option) or measured by the meter (measured option). • The fixed values are entered at a given temperature (and 0 barg) which • usually are 25 °C for the conductivity and 20 °C for the water density. The MPM meter performs temperature and pressure corrections for the • density to the actual T and P conditions. • If the measured conductivity and density is used, it is still recommended • that the meter is configured with a typical fixed values for conductivity and density since this is used as fall -back values when the salinity • measurement is out of range (the water salinity measurement is only • available in water continuous flow) • Standard Conditions The standard conditions calculations are configured by entering the oil • and gas density at standard conditions. These parameters are typical • calculated from the composition of the well. The temperature and • pressure conditions for standard conditions are also defined here. • In this section flashed gas there is also an option to add flashed gas from the oil. The oil at standard conditions will then be reduced • accordingly such that the total hydrocarbon mass flow rate is conserved. When this option is enabled, it is possible to enter a temperature and • pressure look -up table for the mass transfer factor from oil to gas. • • Gas This section allows specifying if some additional properties for the gas • such as the Gas lsentropic Exponent. • There is also an option for using equations for dry air for calculating gas density which is used during testing of the meter in the MPM flow • laboratory. When this option is enabled, the temperature and pressure • look -up table for gas density will not be used. • Water Salinity Filter Limits This is filtering limits for the water salinity measurement for removal of • measurement outliers. It is recommended to set the filter limit • approximately 25 - 50% above the highest salinity which can be • expected and 25- 50% below the lowest salinity which can be expected • TD-010 — Installation and User Manual — MPM Topside Meter.Rev01 • Project Name: Magnolia, Entrada Page 33 of 41 Project Confidential • • • • • • • • MP • F.L €l aF_Pn�wltt5 • • Function Description • for the wells. For water injection wells, the upper value may be the salinity of the • formation water whereas the lower salinity limit may be the value of the injection water (e.g. seawater). • Water / Gas surface The water / gas surface tension is calculated by the meter based on the • tension salinity and measured temperature when the "Calc surface tension from water salinity" option is enabled. A fixed value can also be entered. • Mass absorption The mass absorption coefficients for oil water and gas at 660 keV can • coefficient either be calculated by the meter or entered manually if the over ride • function is used. The meter calculates the absorption coefficient from the • oil and gas density and water salinity assuming NaCI salt. • The mass absorption coefficient for oil, gas and water can be calculated • form the composition using the XCOM database at NIST (National Institute of Standards and Technology) • ( http: // physics .nist.Qov /PhvsRefData /Xcom /html /xcom • NOTE . The mass absorption coefficients calculated by XCOM has been • found to be slightly lower compared to measured mass absorption coefficients by the MPM Meter. Also ,a gas mass absorption coefficient • of 1.0 has been found to provide satisfactory result in most applications • involving hydrocarbon gas. • • • • • • • • • • • • • • • • • • TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 • Project Name: Magnolia, Entrada Page 34 of 41 Project Confidential • • • • • . • • • • inPm • • • 5.7 Dialog toolbar • Send to meter '3 3 • • Figure 13 Toolbar Button • • The toolbar button (Error! Reference source not • found.) functions are as follows: 1. Select the process data set to view • 2. Erase all data from the process data set 3. Enter PVT, Oil and Gas Properties (See • Figure 14) • 4. Upload current data set to meter 5. Export current data set to file • 6. Import from file into current data set • • The dialog has two free -text fields, Name and Description, where the operator may enter any • information as pleased. • For PVT calculations several options are available: • • Density and GOR If this option is selected, densities are calculated using look -up tables and interpolation (see Figure 14). GOR is used in Wetgas 2 Phase mode. • Simplified PVT (Currently not implemented) Use LivePVT If this option is checked, LivePVT will be used. LivePVT means that Oil, • Water and Gas densities are continuously updated from ModBus registers. • • • • • • • • • • • • • • • TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 35 of 41 Project Confidential • • • • • • • • mpm • 4» ,,f1P4vra 1.Retwa • • 5.8 PVT, Oil and Gas properties dialogue • • tail and has t?rvtaertics �� J • PVT input type ® table C: _ • Veicosty I GOR (Actual conditions) ] Surface tension oiVgas 1 Oil -, gas mass transferfactor 1 • Density of Pmt • Temperature [deg C[ • 60 70I 80 94' 100 250E 5441 620: 620 62 620 • 260 624 I 5862 1 584 584.9 5 r 9.6 r Pressure 2 t0 1 620. 583.6 584.9: 577.9, 574.5 • 2E01 620 590.4' 5 77.E 574.8 571 5 • 2931 6201 577.2 ; 574.6 i 571.6 562.4 • Density gas Point31 • Temperature [deg. q 30I 3 40 45 50 • 190 145; 140.91 136.9, 13 129.8 • Pressure 195 142.4 , 144.2 140.2 ' 136.5 _ 133 • [Barg] 2Z01 151.8 147.5 ' 143.4 : 139.6 ' 136 205 ' 1 150. 146.6 142.7 1391 • 210 152.3 ; 153.9 I 149.7 , 145.E 142.1 • • I OK 1I Cancel ! • - • Figure 14 PVT • If Density and GOR is selected as PVT method, densities are added by pressing PVT, Oil and Gas • Properties button in the tool bar (button 3 in Dialog bar). Oil and gas densities are entered with • increasing temperature and pressure in the tables. Pressure, Temperature and densities should be entered. • Below is also a picture of the table entry for oil to gas mass transfer factor. This table is only available • if the "add flashed gas from oil" option is enabled in the Standard Condition part of the process data • setup (se section 5.7) • • • • • • • • TD -010 - Installation and User Manual - MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 36 of 41 • Project Confidential • • • • • • • • • • mM t.?umi Meta • Oil dnd gas properties s PVT input tyPe Q table .} r. moo;1k11 • Day j Viscosity! GOR (Actual conctions)1 Surface tension odlgas OR -> gas mass transfer factor I • Od -> gas mass transfer factor • Temperature (deg. C( • 40 — 100 110 so • 20 0.02 j 0.021 ; 0.022 0.023' 0.024 25 0.02 r 0.021 i 0. D.023 ` 0.024 rQ f1 ; 0.022 0.023 a 0.024 ; - - _. _.- 0.026.1. ....._ 0.028 • 35 0.028 , 0.03; 0.032 j 0.035 ! 0.037 40 0.03 0.031 i 0.034 0.037 0.04 • • • • • • • • • ( OK II Cancel • • • • • • • • • • • • • • • • • TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 37 of 41 • Project Confidential • • • • • • • • • 6 MAINTENANCE • • The MPM Topside Meter requires some maintenance. • The following maintenance activities are suggested by MPM: • • 6.1 Operations Integrity Services (OIS agreement) — link to MPM Operations Centre • • It is highly recommended that a OIS agreement is made for the continuous in -situ verification and diagnostics of the Meter, with regular reports being issued and submitted by MPM to the Operator. • The OIS agreement contains the following elements: • • • Remote Connection to Meter • • Reports sent regularly from Meter to MPM Operation Centre — Events, Alarms, Quality Index and raw measurements for In -situ verification . • Assessment and In -Situ Verification of — Overall performance / Quality Index • — PVT / configuration data • — 3D Broadband — Transmitters • — Gamma Detector • Client reporting • — At defined intervals and events (SMS, e -mails etc) • The link to the MPM Operations centre is shown in the Figure below: • Further details are provided in the Agreement for Technical Services (ATS). III • - ____ _ • _ __ _ OP Centre Server _ —. ,...,...... • MPM --- - - - N Operations Centre r • Internet Example: • FIELD B - Africa Example: .Ai • FIELD A - North Sea UM «R - erminal dair o y • g V o � �� s rAOe s • 1 • ,_ , ,,_ . 1,0_ v .. • • • • • TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 38 of 41 • Project Confidential • • • • • • • • • mpm • 1,a:.1V -11 rkt£n • • • 6.2 Verification / recalibration of Venturi Cd • • Verification of the venturi Cd is recommended being done only if sand is being produced (erosion of pipe internals). To be able to verify the Venturi Cd, the Meter must be compared to a well proven • reference, preferable with single phase flow. • • 6.3 PVT maintenance • It is recommended that the to verify the PVT data used to configure the MPM Meter on an annual • basis. Some applications may require more frequent verification and some Tess depending on the stability of the total hydrocarbon composition from the wells. A well composition verification can be • done by verifying the measured GOR from the MPM Meter with the flashed GOR using a PVT • Simulator based on the total hydrocarbon composition for the well. If a deviation is observed, a re- calculation of the total composition for the well may be required. Measurements from the MPM Meter • or the MPM Meter simulator, together with a PVT simulator can be used for this purpose. Please • contact MPM for further details. The MPM Meter may also be used to measure single phase properties during shut down periods; however this may depend on the particular installation and flow • conditions. If the Meter is filled with pure oil or gas during a shut down, measurements can be taken • to verify the quality of PVT input (please contact MPM for further details). • 6.4 Communication Tests • There are two types of communications tests; one is to check how the internal communication runs • the other is how the communication runs between MPM meter and the terminal. These tests are run from the MPM GUI and can be found under flag `Diagnostic' choosing subflag `Hardware'. The • window in figure 15 below will appear. • Meter ,Ern Maamoura 01. (#4027) eD • Communication with meter Last reset time: 01.04.2006 0&37:47 • f non: 0 • Tots* 395 I Reset error counter 1 • Plnlet Transmdter Errors I Total j ' lrl 0 1592 • cFlrdet2 N4 — NA d0uJett NA NA • cPOullet2 NA NA — Gammat 0 1241 • Ga anal NA NA • — Pressuret 0 1591 P NA NA • Temparature1 0 1591 Temperatrse2 I NA NA • I React 1I Reset I I pose I • I • Figure 15 Communication and error reading • • TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 • Project Name: Magnolia, Entrada Page 39 of 41 Project Confidential • • • • • • • • mpm • N ;l, ,, tc emrarer; • The errors in communication between the MPM meter and the MPM terminal can be read from the • upper left comer. It shows the last reset time, how many errors on the total of communication • packages received. This communication can either be run on Modbus over TCP /IP or Modbus over • RS485, depending on what was requested for the application The errors in communication between the transmitters and the flow computer can be read as seen on • figure 15. These values do not update automatically, in order to update press `Read'. • The normal acceptance criterion is that less than 0.5% of the readings can be errors. Error rate • should be even lower than this, it should be zero. But if the error rate exceeds 0.5% something is • wrong and MPM technical support shall be contacted. • 6.5 Mechanical Maintenance • • The topside meter requires annual inspection of the EX- components and a general visual inspection. • The EX- components consists of the P -, T- and dP- transmitters and also the gamma detector and the • electronics canister. Depending on the application the P -, T- and dP- transmitters are intrinsic safe EX- • components. As regards the EXD components — we recommend EX maintenance according to IEC 60079 -17 /IEC • 60079 -1( NEK420) • • See Instrument Datasheet for details on EX -parts Double Block and Bleed Valves: • We recommend interval for periodical maintenance operation and flushing /cleaning of valve and seal • flanges to follow Company procedures for the specific system and service. • Open lids on antenna boxes to check for moist • • Check shutter mechanism on gamma source that the lock operates as it should. Gamma source will have to be replaced after 15 years. • Transmitters, Dp and PT. • Calibration routines to follow Company procedures for the applicable system the meter is specified • for. Check that supports of cables and hoses are tight and undamaged • • • • • • • • • • TD-010 — Installation and User Manual — MPM Topside Meter.Rev01 • Project Name: Magnolia, Entrada Page 40 of 41 • Project Confidential • • • • • • • • • mpM • • • 7 REFERENCE DOCUMENTS • • Document title Document number Document revision • • Transport, Handling and Preservation TP -008, MPM internal 4 Procedure document • MPM Topside Meter — Technical Description TDS -001, MPM intemal NA • document MPM Subsea Meter — Report from Design and 4015 - REP -003, Project 1 • Qualification Program document Test report - MPM Subsea Meter at SWRI REP -007, MPM internal 4 • document • White paper 1: Unparalleled measurement Internal document NA accuracy and sensitivity • White paper 2: Water Salinity Measurement Internal document NA • White paper 3: Dual Mode functionality Internal document NA • • • • • • • • • • • • • • • • • • • • • • TD-010 — Installation and User Manual — MPM Topside Meter.Rev01 • Project Name: Magnolia, Entrada Page 41 of 41 Project Confidential • • • #14 . . Conocrif)hillips Jack Walker ConocoPhillips Alaska 700 G Street Anchorage, AK 99501 Phone: 907.276.1215 cr,--E' :; ...:þg¡¡- ", '~~, ß-~ " ;'b",\1~, kÏ\£'¡¡""¡; è ~if '. 0 Vi· fb.~ g=i~' March 2, 2007 /" é A r, " ~/lf-i k-f ¡ftJ ÔJ,\ r1 n r""'-- ", r\ .ï.P ¿;; ¿ uu¡ ,0, ¡"'....íL. rr; ., - t-""',w.;'¡~'¡f\;$}1 ,!;/i!: Ji.t~ ~ ~ '" ~'IaI>'~'~:J.:aSf."f'~1i:' f<'_'"'i<, . . Ti't¥,.:i~-~ ~0:--¡;"TItr'J:'-I~{"et~~ 11 ·'n, ~""",d, µ'fI¡¡:;hf[jra¡g~ "' Mr. John Norman, Chair Alaska Oil and Gas Conservation Commission 333 West ill Avenue, Suite 100 Anchorage, AK 99501 Re: Colville River Field, Nanuq Oil Pool, Well CD4-214 Dear Chairman Norman: / Subject well CD4-214 was permitted and completed as a WAG service well in the Nanuq Oil Pool of the Colville River Field under Permit to Drill 206-145. ConocoPhillips Alaska, Inc. (CP AI) as operator ofthe Colville River Unit is submitting a 10-403 form for approval to treat CD4-214 with acid to improve productivity, and then produce CD4-214 via the permanent drill site facilities. We are also seeking an administrative approval to produce CD4-214 up to 60 days without an SSSV to monitor its gas:oil ratio (GOR) trend. The CD4-214 GOR was significantly higher than expected during the flowback. Understanding the GOR performance is needed for improving the reservoir description and positioning future wells. CD4-214 was planned as an injector, and completed with a wireline-retrievable injection valve type SSSV which will not allow production. Installing a pressure-operated SSSV (K-valve) would complicate the test program because well performance information is needed to properly set the K-valve, and the range of conditions during the transient flow period is very difficult to cover with a single K-valve setting. Operating the test without an SSSV will improve the quality of the test data. An SSV will be mounted immediately downstream of the wellhead. Please call me at 265-6268 with any questions. Very truly yours, Q~~ North Slope Operations and Development ConocoPhillips Alaska, Inc. Attachments . C)~f:~F= ~ '" ~ 'l..."r a:: . fIlii 13 P,' (f¡ GJ; I r n -, ~ It. ~I' kI 2uu/ STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVAL 20 MC 25.280 & Gas C~ns~ CC1hmm~~3iD~ fi,.,,,~,,,,,,,,,,,,,., "'d"":1!l\tiGtiI~¡u.; 1. Type of Request: Abandon 0 Suspend 0 Operational Shutdown 0 Perforate 0 Waiver 0 Other 0 Alter casing 0 Repair well 0 Plug Perforations 0 Stimulate 0 Time Extension 0 Change approved program [] r Pull Tubing 0 Perforate New Pool 0 Re-enter Suspended Well 0 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: ConocoPhillips Alaska, Inc. Development 0 Exploratory 0 206-145 3. Address: Stratigraphic 0 Service [] 6. API Number: P. O. Box 100360, Anchorage, Alaska 99510 50-103-20537-00 7. If perforating, closest approach in pool(s) opened by this operation to nearest property line 8. Well Name and Number: where ownership or landownership changes: Spacing Exception Required? Yes 0 No 0 CD4-214 9. Property Designation: 10. KB Elevation (ft): 11. Field/Pool(s): ADL 380077, 384209, 388902 RKB 56' Colville River Field I Nanuq Oil Pool 12. PRESENT WELL CONDITION SUMMARY Total depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 15072' 6280' Casing Length Size MD TVD Burst Collapse CONDUCTOR 114' 16" 114' SURFACE 2620' 9-5/8" 2677' PRODUCTIQN .... - - ----- 8639' 7" 8696' . SLOTTED LINER 6320' 4-1/2" 14814' . Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 4-1/2" L-80 8507' Packers and SSSV Type: Packers and SSSV MD (ft) Premier Packer ~ Packer = 7523' SSSV= fooHA .:cJAd'e.¿h~ V&../~ SSSV= 2189' 13. Attachments: Description Summary of Proposal 0 14. Well Class after proposed work: Detailed Operations Program 0 BOP Sketch 0 Exploratory 0 Development 0 Service 0 15. Estimated Date for 16. Well Status after proposed work: Commencing Operations: March 2007 Oil 0 Gas 0 Plugged 0 Abandoned 0 17. Verbal Approval: Date: WAG 0 GINJ 0 WINJ 0 WDSPL 0 Commission Representative: 18. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Jack Walker @ 265-6268 Printed Name Jack Walker ~ Title: Production Engineer Signature k~ Phone 265-6268 Date 3/:2-107 "-.,...J Commission Use Only Conditions of approval: Notify Commission so that a representative may witness Sundry ~7 - oB 3 Plug Integrity 0 BOP Test 0 Mechanical Integrity Test 0 Location Clearance 0 Other: Subsequent Form Required: 4.0,-\ \ W --\-<è<=,\. \. ""'-~ n.l'V\....O-\-~ (S) " r'ì 0 , C'; 1\ I [1 i COMMISSIONER APPROVED BY Approved by: THE COMMISSION Date: - n¡:;l?nn¡:; V Q '" n V ¡'\!IUtl!-. /~ ., -' -' C',,¡...,.......;..¡.... n.,....li.......... /ñ7C' I=nrm 1 n An:>. Rp\/I,,-pr! ..c . . Colville River Field, Nanuq Oil Pool Well CD4-214 Proposed Acid Treatment & Production Test March 2,2007 1. Pull injection valve SSSV rrom profile at 2189'RKB. 2. Rig up temporary flowline to permanent CD4 drill site facilities with SSV with electronic controls with automatic, remote and local shut in capabilities. 3. Establish baseline performance by producing well and metering well rates via CD4 test separator. 4. Shut in well and treat horizontal, slotted liner completion with nitrified 12% HCI with corrosion inhibitor via coiled tubing. 5. Flowback CD4-214 to portable flowback separator with separator gas stream connected into facilities and separator liquid leg to atmospheric tanks. Neutralize flowback liquids as necessary and inject in approved Class II disposal well. 6. Divert well stream to permanent facilities, and produce up to 60 days. Test well every 10 days. - ,Nanuq Sand Top Structure o "00 ~o ::r~ o I -I'\) CD..... r'¡::" o CO SE - rl .< rl rl rl rl Horizontal Section - 6376 Feet ~,._-,~.._-- -'---~'''~'-'-------''-~'' _ ~_ ____ ~-- "-:~-i-- _~_~:.m_~_'__'____·'___ _;~~....,-,----c--- . rl rl . N " M N rl rl rl rl rl rl rl N rl rl ~~ oeer:__~_" -:;¿- ~Lobe 4 "":-- _~l__m -- 6230 r ª Lobe 2 . . . . ,; . " g . . . . . . rl rl o " . 8696' 7" Casing pt NW 6130 6180 :J J ~ROOUCTJON ic-a696 , OD:7.OOO, Wt28.DD1 SURFACE 1a-2677 , OD:9.525. Wt40.(0) Gas Lift Mandrel/Valve 1 (7419-7420, PACKER (7523-7524, 00:5970) NIP (7581-7582, 00:5.000) P.~ (8688-14713; SLOTTED LINER 18494-14814, OD:4.500, WU.2.60) . . CD4-214 ConocoPhillips Alaska, Inc. Annular Fluid:! ~'Ä\;'US1'RINéS· ..... , Size 16.000 9.625 7.000 4.500 WI 68.00 40.00 26.00 12.60 4.500 3.812 1.125 3.875 3.725 3.958 Date Note 1/131200 NOTE TREE FMC 4-1116" 5000 si - TREE CAP CONNECTION: 7" OTtS #13 . . Colville River Unit Gas Off Take Analysis Background: On February 8, 2007, ConocoPhillips Alaska, Inc. ("CPAI") applied for an allowable gas offtake rate for the Colviller River Unit ("CRU"). Through an agreement between their predecessor Arco Alaska, Inc. and Kuukpik Corporation, CP AI is obligated to provide the village ofNuiqsut a limited volume of natural gas. According to the terms of the agreement, if there is just one producing pool in the CRU CP AI is obligated to supply up to 500 thousand standard cubic feet of gas per day ("MCFPD") to the village, if two or more pools are on production then the obligation increases to 1 million standard cubic feet of gas per day ("MMCFPD"). The North Slope Borough ("NSB") is in the process of acquiring the permits necessary to commission the pipeline from the CRU to the village, and expects to be able to begin gas deliveries sometime this winter. The NSB is estimating that actual gas deliveries to the village will be 500 MCFPD or less; however, this analysis will evaluate the effects of the maximum rate allowed under the terms of the land use agreement. CP AI must have an allowable gas off take rate for pools within the CRU before severing gas from the unit. There are currently four defined pools in the CRU: Alpine Oil Pool (C0443A), Nanuq Oil Pool (C0562), Nanuq-Kuparuk Oil Pool (C0563), and Fiord Oil Pool (C0569). Exploration and development activities are ongoing in the CRU, and it is possible that additional pools will be established in the future. Production from all existing pools, and likely from any future pools, is being commingled and processed in the Alpine Central Facility ("ACF"). Since all production is commingled prior to processing and sales metering, it is impossible to establish a specific gas off take rate for a specific pool and thus a gas off take rate must be established for the unit. Analysis: The Alpine Oil Pool has been on regular production since November 2000, with the other pools coming on production much more recently. Total production from the CRU, through October 2006, is 221.6 million barrels of oil ("MMBO"), 255.5 billion standard cubic feet of gas ("BCFG"), and 7.1 million barrels of water ("MMBW"). For 2006, production from the unit has averaged approximately 125 thousand barrels of oil per day, 150MMCFPD, and 15 thousand barrels of water per day ("MBWPD"). The pools in the CRU are all being developed using enhanced recovery methods. To date, the total injection volumes for the unit are 223.3 BCFG and 218.1 MMBW. For 2006, injection rates have averaged 130 MMCFPD and 135 MBWPD. Based upon the 2003 through 2005 Annual Report ofInjection Project filings by CPAI for the CRU, the formation volume factor for injected gas has averaged about 0.76 reservoir barrels per thousand standard cubic feet of gas ("RB/MSCF"). Assuming that injected water is . . essentially incompressible and applying the injection gas fonnation volume factor yields a current reservoir voidage replacement rate of approximately 233.8 thousand reservoir barrels per day (135 thousand reservoir barrels of water per day + 130 MMCFPD * 0.76 RBIMSCF). The maximum gas shipment rate provided for in the agreement between CP AI and the Kuukpik Corporation is 1 MMCFPD. This volume would be deducted from the gas that is available for re-injection into the pools for pressure maintenance and miscible gas injection processes. Applying the same fonnation volume factor for the injection gas stream that is used above yields a maximum potential voidage replacement loss of 760 reservoir barrels per day. In their application CP AI stated that the as long as miscible injectant is manufactured at the ACF there will be a significant amount of lean gas that will be injected into the Alpine Oil Pool. Currently this gas is injected into well CD 1-06 and does not provide any enhanced recovery benefits as that area of the field has already been effectively swept. During 2006 injection in the CDI-06 well averaged almost 9 MMCFPD. Therefore, even with exporting up to 1 MMCFPD there will still be excess lean gas within the unit and the manufacture of miscible injectant will not be affected. Conclusion: The total loss in daily reservoir voidage replacement rate is about 0.3% at the maximum allowable gas shipping rate and current operating conditions. This small amount will not have a significant effect on ultimate recovery from the unit. Additionally, the more miscible components of the gas stream will be stripped before gas is shipped to the village and will re-enter the gas injection stream. Since a gas off take rate of up to 1 MMCFPD will not promote waste, it is appropriate to establish a gas off take rate for the CRU via administrative approvals. Since all CRU pools are currently commingled, it will be necessary to issue an administrative approval that amends the pool rules for each of the four current pools. These administrative approvals will establish a gas off take rate for the entire unit, not each individual pool. Rules for future CRU pools that commingle production at the ACF must also include a rule recognizing the CRU gas offtake rate. ~~~~;r~/ February 13, 2007 #12 . . ":y ConocoPhillips Alaska, Inc. Maria Kemner Alpine Production Engineer 700 G Street, A To-1764 Post Office Box 100360 Anchorage, Alaska 99510-0360 Telephone 907-265-6945 February 8, 2007 f1 ,Q"", .¿J fJ Mr. John Norman Alaska Oil and Gas Conservation Commission 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501 f?, ~"'''' f',,, .~ 'f' " . . '" ,,",!"',.j;c\\jlj~.i.;¡¡;)ìl1Rmi~~¡©&? j~~çhor~lJa' ,. ''', .', RE : Gas Allowable Colville River Field Alpine Oil Pool Fiord Oil Pool Nanuq Oil Pool Nanuq-Kuparuk Oil Pool Dear Mr. Norman: ConocoPhillips Alaska, Inc. ("ConocoPhillips") and Anadarko Petroleum Company are contractually committed to provide Kuukpik Corporation with up to one million cubic feet of natural gas per day (1,000 mcfd) from the Colville River Field. This natural gas is to be delivered to Kuukpik or its successors, assignees, or licensees at the custody transfer meter at the Alpine Central Facility ("ACF'). Kuukpik or its successors, assignees, or licensees will then transport the natural gas to the village of Nuiqsut. Initial deliveries are expected to commence in Spring 2007. The regulations promulgated by the Alaska Oil and Gas Conservation Commission ("Commission") do not expressly address gas allowables or specify procedures for Commission approval of natural gas production from an oil field, and most existing pool rules do not address the issue. However, we recognize the authority of the Commission under AS 31.05.030(e)(1)(F) to regulate for conservation purposes the quantity and rate of production of gas from a property. For the reasons set forth below, ConocoPhillips, as operator and on behalf of the working interest owners of the Colville River Unit, seeks Commission approval of the above-referenced gas deliveries to Kuukpik on the grounds that this offtake is consistent with good oilfield engineering practices and conservation purposes. The Colville River Field is comprised of the Alpine Oil Pool, the Fiord Oil Pool, the Nanuq Oil Pool, and the Nanuq-Kuparuk Oil Pool, which are all processed through the ACF. As part of the miscible gas enhanced oil recovery ("EaR") project conducted in the Colville River Field, natural gas is transferred among the above-referenced oil pools and commingled. . . February 8, 2007 Page 2 of2 The miscible gas for the EOR project is manufactured at the ACF by removing heavy components from the produced gas and then blending them into a portion of the available lean gas. The high-pressure lean gas not blended with the extracted liquids is injected into the top of the Alpine Oil Pool at CDI-06 and acts as a ready source of fuel to restart the ACF as needed. This lean gas no longer participates in the recovery of oil from the Alpine Oil Pool. Before the CDI-09 production well was shut in last year, this gas provided additional reservoir pressure support in the CDI-09 pattern. However, since the CDI-09 production well has been shut in due to reaching full recovery, the gas injected at CDI-06 no longer provides pressure support and is only used for gas storage. As long as miscible gas is manufactured at the ACF, there will be a significant amount of lean gas that needs to be injected into the Alpine Oil Pool. Thus, diverting up to 1,000 mcfd of lean gas from injection to gas sales will not have a measurable impact on production or ultimate recovery of oil from the Colville River Field oil pools. Because the volume of miscible gas available for injection will remain unchanged, the diversion will not impact the Colville River Field EOR project. In conclusion, pursuant to Rule 10 of Conservation Order No. 443 (Alpine Oil Pool), Rule 12 of Conservation Order No. 562 (Nanuq Oil Pool), Rule 12 of Conservation Order No. 563 (Nanuq- Kuparuk Oil Pool), and Rule 12 of Conservation Order No. 569 (Fiord Oil Pool), ConocoPhillips asks the Commission to administratively approve gas deliveries of up to 1,000 mcfd from the Colville River Field beginning in Spring 2007. If you have any questions concerning this request, please contact me at 265-6945. Sincerely, 1Y{~~ Maria Kemner CD 1 Production Engineer c: David Hodges, North Slope Borough Lanston Chinn, Kuukpik Corporation Marlene Staley, Anadarko ~I' . . COLVILLE RIVER UNIT APPLICA nONS FOR THE FORMATION OF THE NANUQ KUPARUK AND NANUQ NANUQ PARTICIPATING AREAS FINDINGS AND DECISION OF THE DIRECTOR, DIVISION OF OIL AND GAS, UNDER DELEGATION OF AUTHORITY FROM THE COMMISSIONER STATE OF ALASKA DEPARTMENT OF NATURAL RESOURCES November 14,2006 REC IVt.=D 1 '7 ZODS . . Table of Contents I. INTRODUCTION, BACKGROUND AND DECISION SUMMARY...............................2 II. APPLICATION FOR THE FORMATION OF THE NANUQ KUP ARUK AND NANUQ NANUQ PARTICIPATING AREAS . ................... ......... ...................... ........... ....2 III. DISCUSSION OF DECISION CRITERIA .......... ................ ............... .................. ..............5 A. Decision Criteria considered under 11 AAC 83.303(b)...........................................5 1. The Environmental Costs and Benefits of Unitized Exploration and Development............ ......................... ......... ................................ ..................5 2. The Geological and Engineering Characteristics, and Prior Exploration Activities in the Proposed Participating Areas ........................6 3. Plans for Exploration or Development for the Participating Areas............. .'.............................................................................................. 8', 4. The Economic Cósts and Benefits to the State ............................................9 5. Any Other Relevant Factors the Commissioner Determines Necessary or Advisable to Protect the Public Interest Factors................... 10 B. Decision Criteria considered under 11 AAC 83.303(a) .........................................12 1. Promote The Conservation of All Natural Resources................................ 12 2. The Prevention of Economic and Physical Waste .....................................12 3. The Protection of All Parties ofInterest, Including the State ....................12 . IV. FINDINGS AND DECISION ............................................................................................13 . . COLVILLE RIVER UNIT FORMATION OF THE NANUQ KUP ARUK AND NANUQ NANUQ P ARTICIP ATING AREAS I. INTRODUCTION, BACKGROUND, AND DECISION SUMMARY By letters dated August 3, 2006, ConocoPhillips Alaska, Inc. (ConocoPhillips), as Colville River Unit (CRU) Operator, applied for itself and the other Colville River Unit working interest owners (WIOs) to form the Nanuq Kuparuk (Nanuq Kuparuk PA) and Nanuq Nanuq (Nanuq Nanuq P A) Participating Areas within the boundaries of the CRU (Applications). On September 7, 2006, and October 23, 2006, ConocoPhillips submitted revisions to the Applications (Revised Applications). The Revised Applications will result in two additional participating areas in the CRU, which will be developed from a single new drillsite--CRU Drillsite CD4. The proposed Nanuq Kuparuk P A includes all or portions of one State of Alaska lease, one Arctic Slope Regional Corporation (ASRC) lease and eight leases that are held jointly by the State and ASRC. The State-only lease comprises approximately 69.89 acres, the ASRC-only lease comprises approximately 600 acres and the joint State/ASRC leases comprise 5,515.72 acres, for a total Nanuq Kuparuk PA of approximately 6,185.61 acres. The proposed Nanuq Nanuq P A includes all or portions of two State of Alaska leases and nine leases that are held jointly by the State and ASRC. TheState-only leases comprise approximately 777.29 acres and the joint State/ASRC leases comprise 7,379.69 acres, for a total Nanuq NanuqPA of approximately 8,156.98 acres. ConocoPhillips provided the State with geological, geophysical and engineering data regarding the proposed Nanuq Kuparuk P A and Nanuq Nanuq P A. The data indicate that the Kuparuk Reservoir within the Kuparuk formation and the Nanuq Reservoir within the Torok formation are capable of producing or contributing to the production of hydrocarbons in paying quantities. The Division approves the Revised Applications to form the Nanuq Kuparuk P A and Nanuq Nanuq PA. The Nanuq Kuparuk PA and the Nanuq Nanuq PA each encompass an area that is "reasonably known to be underlain by hydrocarbons and known or reasonably estimated. .. to be capable of producing or contributing to production of hydrocarbons in paying quantities." 11 AAC 83.351(a). The effective date ofthe two participating areas is November 1,2006. II. APPLICATIONS FOR THE FORMATION OF THE NANUQ KUPARUK AND NANUQ NANUQ PARTICIPATING AREAS ConocoPhillips submitted separate Applications, both dated August 3, 2006, to form the Nanuq Kuparuk PA under 11 AAC 83.351 and Sections 9.1, 9.3 and 9.5 of the CRU Agreement, and to form the Nanuq Nanuq PA under 11 AAC 83.351, and Sections 9.1, 9.3, 9.5 and Subsection 10.1.10 of the CRU Agreement. The Nanuq Reservoir is a Gas Cap Reservoir, as defined in Subsection 10.1.10 of the CRU Agreement, because it is a Reservoir that contains 2 . . crude oil (with gas in solution) as well as an associated gas cap under original reservoir conditions. It is the first Gas Cap Participating Area to be formed within the CRU; it will have two sets of Unit Tract Participations--a Liquid Unit Tract Participation and a Gas Unit Tract Participation. The other CRU participating areas, Alpine, Fiord Kuparuk, Fiord Nechelik and the proposed Nanuq Kuparuk, have a single Unit Tract Participation for each Unit Tract in their participating areas. Under Subsection 10.1.lO(a) of the CRU Agreement, the Liquid Unit Tract Participation is based on the recoverable volumes and recoverable participating area volume of crude oil and other Unitized Substances in the form of liquid in the Reservoir plus condensate contained in gas in the Reservoir. The Gas Unit Tract Participation is based on the estimated total volumes of gas or gaseous Unitized Substances originally in place in the respective Unit Tracts in the participating area both in the form of free gas in the Reservoir, the original free gas in place, and in the form of gas entrained in solution in liquid Unitized Substances in the Reservoir, the original solution gas in the crude oil. Or more simply stated, the Liquid Unit Tract Participation is based on recoverable tertiary oil in place, while the Gas Unit Tract Participation is based on the original solution gas in place plus the original non-solution (Gas Cap) gas in place. By letters, dated September 7, 2006, ConocoPhillips submitted a revised ExhibitE (Allocation of Participating Area Expense) and Exhibit F (Allocation of Unit Expense) for each' proposed participating area, and a revised tract participation schedule (ExhibitC to the CRU Agreement) for the Nanuq Nanuq P A. Further, by letters, dated October 23, 2006, ConocoPhillips revised the tract participation schedules (Exhibit C to the CRUAgreement) for both proposed participating areas. The Application for the Nanuq Kuparuk P A includes the original Applîcation for the Nanuq Kuparuk P A, dated August 3, 2006, and the revisions dated September 7, and October 23, 2006. The Application for the Nanuq Nanuq P A includes the original Application for the Nanuq Nanuq PA, dated August 3, 2006, and the revisions dated September 7, and October 23, 2006. Taken together, these materials constitute the Revised Applications for the two Nanuq Participating Areas. The proposed 6,185.61 acre Nanuq Kuparuk PA is comprised of all or portions of: 1) one State of Alaska lease, ADL 372097; 2) one ASRC lease; and 3) eight leases that are held jointly by the State and ASRC, ADLs 380075, 380077, 384211, 387208, 387209, 388902, 388903, and 388905. The proposed Nanuq Kuparuk PA acreage encompasses the Kuparuk Reservoir within the Kuparuk formation in the southern part of the CRU The tracts/leases proposed for inclusion and the proposed tract participation schedule for the Nanuq Kuparuk P A are listed in Attachment 1 to this Findings and Decision. A map depicting the outline of the proposed Nanuq Kuparuk PA and the Unit Tracts proposed for inclusion in the Nanuq Kuparuk PA is Attachment 2 to this Findings and Decision. The proposed 8,156.98 acre Nanuq Nanuq PA is comprised of all or portions of: 1) two State of Alaska leases, ADLs 25559 and 372097; and 2) nine leases that are held jointly by the State and ASRC, ADLs 380075, 380077, 380082, 384211, 387208, 387209, 388902, 388903, and 388905. The proposed Nanuq Nanuq PA acreage encompasses the Nanuq Reservoir within . . the Torok formation in the southern part of the CRU. The tracts/leases proposed for inclusion and the proposed tract participation schedule for the Nanuq Nanuq PA are listed in Attachment 3 to this Findings and Decision. A map depicting the outline of the Nanuq Nanuq PA and the Unit Tracts proposed for inclusion in the Nanuq Nanuq PA is Attachment 4 to this Findings and Decision. Because the Nanuq Kuparuk P A and the Nanuq Nanuq P A will include lands held jointly by the State and ASRC, the outline of each participating area depicted in Exhibit D to the CRU Agreement (Attachments 2 and 4 to this Findings and Decision) is prescribed by Section 9.5 of the CRU Agreement. The boundaries depicted in Attachment 2 and 4 are the product of a mechanical methodology that involves drawing circles and tangents around proposed development wells, combined with a mapping evaluation of the hydrocarbon-bearing Kuparuk and Nanuq Reservoirs. The mapping evaluation used well and seismic data to estimate the area within the CRU that is underlain by hydrocarbons and capable of producing or contributing to production of hydrocarbons in paying quantities. Subsection 9.5.1 of the CRU Agreement describes how a participating area for the Kuparuk Reservoir and the Nanuq Reservoir must be drawn using the circle and tangent method. The boundaries of the participating area are those lands encompassed within the outermost circles or ellipses and connecting tangents drawn around qualified, drilled and proposed injection or production wellbores. The radius of the circles and ellipses is one-half mile, and the area encompassed includes the entirety of each quarter-quarter section whether or not the entirety of that quarter-quarter section falls within the drawn configuratiQn. The initial Plan of Development (POD) for each of the two participatîng areas includes a listing and schedule of drilled and proposed injection and production wells. The Attachments provided for each participating area show the drilled and proposed bottomhole locations, actual and proposed injection points (in injection wells) and actual and proposed completion intervals (in production wells), and the resulting Nanuq Kuparuk P A and Nanuq Nanuq P A after applying the circle and tangent method. The proposed Nanuq Kuparuk P A and Nanuq Nanuq P A outlines encompass those lands that ConocoPhillips has drilled or intends to drill and put into production or on injection within two years of commencement of production from each participating area. The lands proposed to be included in each participating area (as described in Exhibit C and depicted in Exhibit D to the CRU Agreement) are a result of each participating area's POD and the application of Section 9.5 of the CRU Agreement. Similar to the Fiord Participating Areas' Application (See the Findings and Decision of the Director, Application for the Fiord Kuparuk and Fiord Nechelik Participating Areas, dated September 25,2006), the Revised Applications did not comply with the terms and conditions for the Nanuq Expansion Area contained in the Findings and Decision of the Director, Application for the Second Expansion of the Colville River Unit, dated November 8, 2002 (Second Expansion Decision). The Second Expansion Decision required that the entirety of eight specific CRU Tracts be included in an approved Nanuq Participating Area within four years of the effective date of the Second Expansion Decision or the entirety of the Nanuq Expansion Area would contract from the CRU The Revised Applications did not include all eight ofthe required CRU Tracts. When the parties resolved this similar issue for the Fiord Expansion Area and the Fiord Participating Areas' applications, it also agreed to apply the same solution for the Nanuq Expansion Area. The Revised Applications requested that this same resolution methodology apply to the Nanuq Expansion area leases. The terms and conditions for retaining the Nanuq . . Expansion Area Lands within the CRU are set out in Attachment 5 to this Findings and Decision. Finally, Section 9.8 of the CRU Agreement provides that the effective date for each subsequent participating area (other than the initial participating area, the Alpine Participating Area) shall be established by the proper authority. ConocoPhillips did not request any effective date in the Revised Applications. Because sustained production from the two participating areas is scheduled for mid-November 2006, the Division approves the Nanuq Kuparuk PA and the Nanuq Nanuq PA with an effective date of November 1,2006. III. DISCUSSION OF DECISION CRITERIA The Commissioner of the Department of Natural Resources (Commissioner) reviews applications to form participating areas under 11 AAC 83.303--11 AAC 83.395. By memorandum dated September 30, 1999, the Commissioner approved a revision of Department Order 003 and delegated this authority to the Director of the Division of Oil and Gas (Director). The Division's review of the Revised Applications is based on the criteria in 11 AAC 83.303(a) and (b). A participating area may include only land reasonably known to be underlain by hydrocarbons and known or reasonably estimated through use of geological, geophysical, or engineering data to be capable of producing or contributing to the production of hydrocarbons in paying quantities. 11 AAC 83.351(a). "Paying quantities" means: quantities sufficient to yield a return in excess of operating costs, even if drilling and equipment costs may never be repaid and the undertaking as a whole may ultimately result in a loss; quantities are insufficient to yield a return in excess of operating costs unless those quantities, not considering the costs of transportation and marketing, will produce sufficient revenue to induce a prudent operator to produce those quantities. 11 AAC 83.395(4). A discussion of the 11 AAC 83.303(b) criteria, as they apply to the Revised Applications to form the Nanuq Kuparuk PA and the Nanuq Nanuq PA, is set out below, followed by a discussion ofthe subsection (a) criteria. A. Decision Criteria considered under 11 AAC 83.303(b) 1. The Environmental Costs and Benefits of Unitized Exploration and Development DNR considered environmental issues in the lease sale process and the initial unitization process for the CRU leases; DNR will review them again during the unit plan of operations approval process. Unitized exploration, development, and production minimize surface impacts by consolidating facilities and reducing activity in the field. The Nanuq Kuparuk P A and Nanuq Nanuq PA PODs have been designed to minimize the amount of surface impact from the facilities necessary to develop the Kuparuk and Nanuq Reservoirs, which will be developed from one gravel pad. The infield development is planned from a new gravel pad, CD4, and drill site . . facilities that will be connected to the existing Alpine infrastructure via a gravel road. The CD4 development project facilities and infrastructure include produced oil, water injection, miscible injectant, and gas lift pipelines, and electric power from the Alpine Central Facility (ACF) to the Nanuq CD4 drillsite. All pipelines, including the infield lines, will be built at least five feet above ground level to ensure passage of migrating caribou. The CD4 development will share all existing Alpine fluid processing facilities and infrastructure. The Nanuq Kuparuk PA and Nanuq Nanuq PA will promote efficient development of the State's resources, while minimizing impacts to the region's cultural, biological, and environmental resources. These impacts would be significantly greater if the Kuparuk and Nanuq Reservoirs were developed on a lease-by-Iease basis, rather than on an integrated unitized basis. 2. The Geological and Engineering Characteristics, and Prior Exploration Activities of the Nanuq Kuparuk and Nanuq Nanuq Participating Areas The Revised Applications define the Nanuq Reservoir and the Nanuq Kuparuk Reservoir from the Nanuk No.2 well as the intervals between 7,043 feet measured depth (md) to 7,223 feet md and 7,956 feet md to 7,972 feet md, respectively. Prior to submitting the Revised Applications, ConocoPhillips held, numerous meetings with the Division and provided pre- application data and information that included net pay maps of each reservoir, a discussion ofthe development wells drilled to date, a discussion of reservoir fluid contacts and quality, well logs and core data from both reservoirs, structure maps at the top Nanuq sandstone and on the Lower Cretaceous Unconformity (LCU), stratigraphic cross sections and well test data from both reservOIrs. Two 3D seismic data sets cover the CD4 development area, the Alpine 3D seismic shot in 1996 and the Nanuq 3D seismic shot in 2003. Although these two data sets were acquired with different line directions, they were merged into one 3D seismic data set. The merged data are generally of good quality except below the large lakes. Two exploration wells and three delineation wells define the core of the CD4 development area. The two exploration wells are Nanuk No.1 and Nanuk No.2, and the three delineation wells are Nanuq No.31, Nanuq No.5 and CDI-229. ARCO drilled the Nanuk No.1 well in 1996. It was a delineation well for the Alpine Reservoir as well as an exploratory well for additional hydrocarbon accumulation targets in the CRU. This well reached a total depth of7,630 feet md, bottomed in the Jurassic, and is the discovery well for the Nanuq sandstone interval. The well encountered: (l) 144 feet true vertical depth (TVD) thickness ofNanuq interval with approximately 100 feet TVD above an oil-water- contact (OWC); and (2) 9 feet TVD of oil-bearing Kuparuk C sandstone equivalent approximately 700 feet TVD below the Nanuq interval. Formation evaluation logs, rotary side 1 After the Nanuk No.1 and Nanuk No.2 were drilled, the spelling of Nan uk was changed to Nanuq. 6 . . wall cores (SWC) and Repeat Formation Tester (RFT) data were gathered from the well, which was plugged and abandoned in April 1996. In 2000, ConocoPhillips drilled the Nanuk No.2 well to a total depth of9,112 feet md, also bottoming in the Jurassic. This well confirmed the Nanuq discovery and it is the formation type log for the Nanuq Kuparuk and Nanuq Nanuq Reservoirs. The Nanuq Reservoir was encountered at 7,043 feet md (6,136 feet true vertical depth subsea (TVDSS)), and is 176 feet TVD thick at this location. The N anuq interval was cored with core porosity and permeability indicating good reservoir with porosity ranging from 11.0 % to 18.9%, and permeability ranging from under 1 millidarcy to 22 millidarcies. The Kuparuk C sandstone was encountered 734 feet TVD below the Nanuq Reservoir, at 7,956 feet md (-7,046 feet TVDSS). It is 12 feet TVD thick and oil-bearing. The Nanuq No.3 well encountered 121 feet TVD ofNanuq sandstone and approximately 10 feet TVD ofKuparuk C sandstone. The Kuparuk interval was cored at Nanuq No.3 with an average core porosity of 22%, and average core permeability of 240 millidarcies. A long term production test at CDl-229 confirmed the production potential of the Nanuq Reservoir. The additional data collected in these wells, together with the 3D seismic data, helped establish the size of the Nanuq and Nanuq-Kuparuk accumulations. " The Nanuq Reservoir sandstone is an informally named sandstone that occurs in the Lower Cretaceous Torok Formation as a toe of slope, submarine fan complex. Deposition by sporadic turbidity flows resulted in an accumulation oflobe-sheet deposits separated by thick intra-lobe shales. There are four primary sandstone units that are separated by three shale units. The sandstone beds are continuous across the development area, although the thickness of individual sandstone bodies varies. Gross Nanuq sandstone thickness ranges from approximately 176 feet at Nanuk No.2 to approximately 120 feet at Nanuq No.3. The Nanuq sandstone is stratigraphically trapped. It is encased in shales of the Torok Formation directly above and below the sandstone and the sandstone shales out radially from depositional sources located to the west. The top structure map indicates that the Nanuq sandstone occurs on a local high that dips to the south and east. Sandstone connectivity is assumed to be good across the development area because no major faults occur in the Nanuq sandstone. Nanuq sandstone reservoir properties vary within the sand lobes, but porosity averages about 17% and permeability averages about 2.5 millidarcies. Net pay for the entire Nanuq sandstone averages 35 feet TVD. Initial Nanuq Reservoir pressure is 2,740 psia. From formation log data, a gas-oil contact (GOC) is estimated at approximately -6,100 feet TVDSS. An OWC is identified in the Nanuk No.2 well at -6,207 TVDSS. The Nanuq sandstone was tested and co-mingled with production from the Kuparuk River Formation at Nanuk No.2 where the combined flow rate was 1,750 BOPD, 1,000 BWPD and 1.2 million cubic feet per day of gas. The tested Nanuq oil had an API gravity of 39 degrees and the Kuparuk oil had an API gravity of 40 degrees. Subsequent tests indicate Nanuq oil gravity ranges from 39 API to 42 API and oil viscosity is approximately 0.5 centipoise. Solution gas-oil ratio (GOR) is approximately 990 standard cubic feet/stock tank barrel (SCF/STB). . . Underlying the Nanuq Reservoir by roughly 700 feet is the second CD4 development target, the Nanuq Kuparuk Reservoir. The Nanuq-Kuparuk Sandstone is stratigraphically trapped. It is overlain, in ascending order, by shales and mudstones of the Kuparuk River Formation D member, the Kalubik Formation and the Highly Radioactive Zone shale (HRZ). It is underlain by shales ofthe upper Jurassic Miluveach Formation. The Kuparuk River Formation is Neocomian (Early Cretaceous) in age and is subdivided into four major informal members that are designated with letters A through D. The A member is the oldest and the D member is the youngest. The C and B members are separated by a significant major regional unconformity, the Lower Cretaceous Unconformity (LCU). The LCU in the CD4 area dips gently to the west- southwest at 0.7 degrees and only the Kuparuk C member is preserved as a thin, transgressive sandstone lag. The Kuparuk C sandstone was deposited in paleogeographic lows that were sculpted by the erosional effects of the LCU carving into the underlying shale of the Miluveach Formation. The Kuparuk C sandstone consists of fine to medium grained, quartz-rich sandstone with variable quantities of glauconite and silt. Maximum gross thickness of the transgressive sandstone lag is 12 feet TVD at the Nanuk No.2 well location, with net pay of approximately 6 feet TVD. No fluid contacts have been identified to date În the Nanuq-Kuparuk Reservoir. Porosity and permeability tend to be excellent except where the sandstone is cemented with siderite. Across the CD4 development area, porosity averages 22% and permeability averages 200 millidarcies. Faulting is considered to be minimal in this area and is not anticipated to impact ultimate oil recovery. Oil properties of the Nanuq Kuparuk Reservoir, as measured from production tests and RFT data, indicate the oil is closely related to the Nanuq Nanuq Reservoir oil. Samples Îndicate that oil gravity ranges from 40 to 41 API, with oil viscosity estimated at 0.5 centipoise. Solution GOR is approximately 990 SCF/STB. Initial Nanuq Kuparuk Reservoir pressure is 3,249 psia. ConocoPhillips submitted data that supports the mapped Nanuq and Nanuq-Kuparuk Participating Areas being underlain by hydrocarbons and capable of producing or contributing to the production of hydrocarbons in paying quantities. The participating area outlines are drawn in accordance with the rules described in subsection 9.5.1 of the CRU agreement. The Division's evaluation ofthe subsurface geology supports the configuration of the proposed Nanuq Nanuq and Nanuq Kuparuk Participating Areas. 3. Plans of Development for the Nanuq Kuparuk and Nanuq Nanuq Participating Areas Under Subsections 8.1.2(b) and 8.1.2( c) of the CRU Agreement, the term of the Initial Nanuq Kuparuk PA POD and Nanuq Nanuq PA POD is a period commencing with Sustained Unit Production from a participating area and ending two years after the commencement of Sustained Unit Production. Sustained Unit Production from the CD4 Drillsite is scheduled to commence in mid-November 2006. ConocoPhillips' PODs for both participating areas anticipate a horizontal pattern miscible water-alternating-gas (MW AG) recovery process in both the Kuparuk and Nanuq Reservoirs. Four . . wells, two horizontal producers, one horizontal injector and one vertical injector, are initially planned from CD4 to develop the Nanuq Kuparuk PA. Within the Kuparuk Reservoir, these wellbores will parallel each other, the horizontal wells will be approximately 6,000 feet in length, and all wells will be spaced approximately 6,000 apart. Sixteen long-reach horizontal wells, nine producers and seven injectors, are planned from CD4 to develop the Nanuq Nanuq PA. Within the Nanuq Reservoir, these wellbores will parallel each other, approximately 6,100 feet in length, and spaced approximately 1,500 feet apart. ConocoPhillips represented to the Division that implementation of enhanced oil recovery (EOR) is integral to the CD4 project as reservoir modeling and laboratory work show the MW AG recovery process will result in significant oil recovery from both reservoirs. The peak projected commingled annual oil production rate from the two participating areas is estimated to be 11,000 BOPD. ConocoPhillips anticipates that approximately 55 million barrels of oil will be recovered from the two reservoirs over the 23-year project life. Prior to sustained production from the CD4 Nanuq Drillsite, ConocoPhillips operated certain Nanuq Nanuq wells, CD4-208 and CD4-209, and certain Nanuq Kuparuk wells, CD4-318 and CD4-319, as CRU Tract Operations to ensure wellbore cleanup and gather additional reservoir information. Three ofthe four wells, CD4-208, CD4-318 and CD4-319, produced during February- March 2006, and CD4-209 was flowed-back for clean-up in August 2006. 4. The Economic Costs and Benefits to the State Approval of the Nanuq Kuparuk and Nanuq Nanuq Participating Areas will provide near- term economic benefits to the State by creating jobs associated with the construction of the CD4 project facilities, operation of the two fields, and the assessment of the hydrocarbon potential of the other leases within the CD4 project area. The State will also benefit from the Nanuq Kuparuk PA POD and Nanuq Nanuq PA POD, which will maximize the physical recovery of hydrocarbons from the Kuparuk Reservoir and Nanuq Reservoir, respectively. Maximum hydrocarbon production will enhance the State's long-term royalty and tax revenues. The WIOs have provided sufficient technical data to define the participating areas, and have agreed to PODs for each participating area that will ensure a timely sequence of drilling and development activities to evaluate and develop both participating areas. The leases in the Nanuq Kuparuk PA and Nanuq Nanuq PA are written on a variety of forms. Previously, during the CRU Agreement negotiations, the parties bargained for amendments to the terms and conditions of the leases to harmonize them. By amending, in the unit agreement, the terms of the older leases, the State avoided costly and time-consuming re- litigation over problematic lease provisions in the older forms. Under the CRU Agreement, the State will benefit economically from a number of amendments to the individual leases. Specifically, the State's royalty share of production from the two participating areas will be free and clear of all field costs incurred on the North Slope of Alaska. Any additional administrative burdens associated with the Nanuq Kuparuk P A and the 9 . . Nanuq Nanuq P A will be far outweighed by the additional royalty and tax benefits from the production from each participating area. 5. Any Other Relevant Factors the Commissioner Determines Necessary or Advisable to Protect the Public Interest Under 11 AAC 83.351 and 11 AAC 83.371, ConocoPhillips must submit for Commissioner approval a proposed division of interest setting out the percentage of production and costs to be allocated to each lease or portion of lease within each participating area. Furthermore, the proposed division of interest allocating production and costs may not take effect until approved by the Commissioner in writing. The Revised Applications include an allocation of production (CRU Agreement, Exhibit C for the Nanuq Kuparuk P A and Exhibit C for the Nanuq Nanuq P A, both dated October 23, 2006), an allocation of participating area costs (CRU Agreement, Exhibit E for the Nanuq Kuparuk PA and the Nanuq Nanuq PA, both dated September 7, 2006), and an allocation of unit costs (CRU Agreement, Exhibit F for the Nanuq Kuparuk PA and the Nanuq Nanuq PA, both dated September 7, 2006) for the leases in each participating area. The proposed division of interest schedule distributes production and ultimately costs among the tracts in each participating area according to original recoverable oil- in-place. The Exhibit C for the Nanuq Kuparuk PA and the Nanuq Nanuq PA includes the division of interest allocating unittract participation within the proposed participating areas as determined by ConocoPhillips in accordance with the standards and principles set forth in Article 10 of the CRU Agreement. The basis of the Nanuq Kuparuk P A unit tract participation schedule, original recoverable oil in place, is set forth in Subsection 10.1.1 of the CRU Agreement. 'The basis for, the Nanuq Nanuq PA's liquid unit tract participation schedule, original recoverable oil-in-place, and the gas unit tract participation schedule, original solution gas plus non-solution (gas cap) gas- in-place, is set forth in Subsection 10.1.10 of the CRU Agreement. Under Section 9.3 of the CRU Agreement, the division of interest submitted by ConocoPhillips allocating unit tract participation for the Nanuq Kuparuk PA and the Nanuq Nanuq PA does not require approval by the Commissioner or the President of ASRC, and remains effective until changed by Section 10.1 of the CRU Agreement. Even if the parties had not agreed to Section 9.3 of the CRU Agreement, the Division finds that the methodology embodied in the Exhibits C acceptable for allocating production to the various tracts in each of the two participating areas. Further, under Section 9.3 of the CRU Agreement, ConocoPhillips submitted, for Commissioner approval, Exhibit E, Allocation of Participating Area Expense, and Exhibit F, Allocation of Unit Expense, with the Revised Applications. Participating Area Expense has two components, capital expenditures and operating expenditures. The September 7, 2006, Exhibit E for both Nanuq Participating Areas clarifies how these two components of Participating Area Expense are to be allocated to the Tracts in the two participating areas. Ultimately, each Unit Tract in the Nanuq Kuparuk P A and Nanuq Nanuq P A has the same percentage of Participating Area Expense as the percentage of Unitized Substances allocated to the tract under Exhibit C. Similarly, Unit Expense has two components, capital expenditures and operating 10 . . expenditures. The September 7, 2006, Exhibit F for both Nanuq Participating Areas clarifies how these two components of Unit Expense are to be allocated to the Tracts in the two participating areas. Ultimately, each Unit Tract in the Nanuq Kuparuk P A and Nanuq Nanuq P A has the same percentage of Unit Expense as the percentage of Unitized Substances allocated to the tract via Exhibit C. Exhibit E and Exhibit F for each participating area are based on Exhibit C. Allocated Unit Tract costs are ultimately based on recoverable oil-in-place. The Division finds the Exhibits E and Exhibits F for each participating area, dated September 7, 2006, acceptable for allocating costs among the Unit Tracts in the Nanuq Kuparuk P A and the Nanuq Nanuq P A2. ConocoPhillips has no plans for stand-alone processing facilities at the Nanuq Kuparuk and Nanuq Nanuq PAs. Produced fluids from the CD4 participating areas will be processed through the existing processing facilities at the ACF. CD4 produced fluids will be commingled with Alpine Participating Area produced fluids prior to final processing and custody transfer metering. All produced fluids from the various participating areas within the CRU will be treated identically in the commingled stream irrespective of individual stream quality differences, if any. Only one commingled stream from the ACF will be tendered to the Alpine Pipeline for delivery to the Trans Alaska Pipeline (TAPS). The indigenous gas from all the CRU participating areas will be commingled at the ACF where some of it will be flared, some will. be used as fuel in support of Alpine, Fiord Kuparuk, Fiord Nechelik, Nanuq Kuparuk and Nanuq Nanuq Participating Areas, and the remainder, an enriched. gas and a dry gas, will be injected into each unit participating area as an EOR mechanism. An integral part of a successful implementation of commingled production is the allocation of the produced fluids back to the originating reservoir for revenue and reservoir management purposes. Two issues regarding commingled production from multiple reservoirs through common surface facilities are not addressed in the Revised Applications, but were negotiated between the State, ASRC, and ConocoPhillips. These issues are: 1) a methodology for allocating the commingled fluid streams through the common Alpine processing facilities; and 2) a unit-wide gas management agreement for the allocation of commingled produced gas that will be used for development and production, repressuring, recycling, storage or enhanced recovery purposes of all reservoirs in the CRU This Findings and Decision does not address these issues. Rather, they were addressed under a separate document, the CRU Gas Management Agreement, effective July 1, 2006. Finally, Section 9.8 of the CRU Agreement provides that the effective date for each subsequent participating area shall be established by the Proper Authority. ConocoPhillips did not request an effective date in the Revised Applications. Since sustained production from CD4 is anticipated by mid-November 2006, the Division approves the Nanuq Kuparuk PA and the Nanuq Nanuq PA with an effective date of November 1, 2006. 2 For the Nanuq Nanuq P A, the Liquid Unit Tract Participation factor of its Exhibit C will apply for its Exhibit E and Exhibit F. . . B. Decision Criteria considered under 11 AAC 83.303(a) 1. Promote the Conservation of All Natural Resources The formation of oil and gas units, as well as the creation of participating areas within units, generally conserves hydrocarbons. The coordinated development of leases held by diverse parties maximizes total hydrocarbon recovery and minimizes waste. The formation of the Nanuq Kuparuk PA and the Nanuq Nanuq PA provides for more efficient, integrated development of the entire Nanuq Kuparuk Reservoir and Nanuq Nanuq Reservoir. The CRU Operating Agreement and the POD for each participating area avoids duplicative development efforts on and beneath the surface. The number of facilities required to develop the resource and the area of land that may be required to accommodate those facilities is reduced when resources on several leases are developed as one participating area. Facilities can be located to maximize recovery and to minimize environmental impacts, without regard for individual lease ownership. 2. The Prevention of Economic and Physical Waste Generally, the formation of a participating area facilitates the equitable division of costs and allocation of hydrocarbon shares, includes a diligent development plan that maximizes the ,physical and economic benefits from a reservoir's production. The creation of the Nanuq KuparukPA and the Nanuq Nanuq PA prevents economic and physical waste .by eliminating redundant expenditures, and maximizes the ultimate recovery from each reservoir by adopting a unified reservoir management strategy. Oil and gas resources can be produced through a single facility infrastructure system. The Nanuq Kuparuk PA and the Nanuq Nanuq PA will improve the efficiency of developing their respective reservoirs, which have variable productivity across adjoining leases. Economically marginal reserves, which otherwise would not be produced on a lease-by-Iease basis, can be developed through the participating areas. Further, facility consolidation saves capital and promotes better reservoir management through pressure maintenance and enhanced recovery procedures. These factors allow the Kuparuk Reservoir and the Nanuq Reservoir to be developed and produced in the interest of all parties, including the State, while preventing economic and physical waste. 3. The Protection of All Parties of Interest, Including the State Because hydrocarbon recovery will be maximized resulting in additional production- based revenue from the Nanuq Kuparuk PA and the Nanuq Nanuq PA production, the State's economic interest is promoted. Also, diligent exploration under a single unit, without the complications of competing leasehold interests, promotes the State's interest. The formation of each participating area promotes efficient evaluation and development of the State's resources, yet minimizes impacts to the area's cultural, biological, and environmental resources. Operating under the CRU Agreement provides for accurate reporting and record keeping, State concurrence with operating procedures, royalty settlement, in-kind taking, and emergency storage of oil. These all protect the State's interests. 12 . . The formation of each participating area protects the economic interests of all WIOs of each reservoir in each participating area. Combining interests and operating under the terms of the CRU Agreement and CRU Operating Agreement ensures that each individual working interest owner an equitable allocation of costs and revenues commensurate with the resources of its lease(s). IV. FINDINGS AND DECISION Considering the facts discussed above and the administrative record as a whole, I hereby make the findings and impose conditions as follows. 1. The formation of the Nanuq Kuparuk P A and N anuq Nanuq P A, under the terms and conditions of the Revised Applications and this decision, will promote the conservation of all natural resources, promote the prevention of economic and physical waste, protect all parties of interest, and are necessary and advisable to protect the public interest. AS 38.05.180(p); 11 AAC 83.303. 2. The available geological and engineering data demonstrate that a paying quantities certification is appropriate for the tracts proposed for both the Nanuq Kuparuk PA and the Nanuq Nanuq PA. The data also indicate that the acreage is underlain by hydrocarbons and known and reasonably, estimated to be capable of production, or contributing to production in sufficient quantities to justify the formation of the Nanuq Kuparuk P A and the Nanuq Nanuqp A within the CRU 3. The Nanuq Kuparuk PA POD and Nanuq Nanuq PA POD, both dated August 3, 2006, meet the requirements of 11 AAC 83.343 and Section 8.1 of the CRU Agreement. The Nanuq Kuparuk PA POD and Nanuq Nanuq PA POD, which provide for the rational development of the hydrocarbon accumulations within the proposed participating areas, are approved. 4. ConocoPhillips shall submit annual updates to the initial PODs to DNR consistent with the provisions of 11 AAC 83.343 and Article 8 of the CRU Agreement. The annual updates must describe the status of projects undertaken and the work completed, and any proposed changes to the PODs. 5. The available geological and engineering data and PODs justify the inclusion ofthe proposed tracts within the Nanuq Kuparuk PA and the Nanuq Nanuq PA. In accordance with the regulations governing the formation and operation of oil and gas units (11 AAC 83.301 - 11 AAC 83.395), the CRU Agreement, and the terms and conditions under which these lands were leased from the State, the lands described in Attachment 1 to this Findings and Decision are included in the Nanuq Kuparuk P A, and the lands described in Attachment 3 to this Findings and Decision are included in the Nanuq Nanuq P A. 13 . . 6. The formation of the Nanuq Kuparuk PA and the Nanuq Nanuq PA provide for the equitable allocation of produced hydrocarbons and costs to the tracts within each participating area, and set out PODs designed to maximize physical and economic recovery from the reservoirs within each approved participating area. Under Section 9.3 of the CRU Agreement, 11 AAC 83.351(a), and 11 AAC 83.371(a), the Allocation of Participating Area Expense (CRU Agreement, Exhibit E for the Nanuq Kuparuk PA and the Nanuq Nanuq PA, both dated September 7, 2006) and the Allocation of Unit Expense (CRU Agreement, Exhibit F for the Nanuq Kuparuk PA and the Nanuq Nanuq PA, both dated September 7, 2006) are approved. 7. All produced fluids from the various participating areas within the CRU will be treated identically in the commingled stream irrespective of individual stream quality differences, if any. Only one commingled stream from the ACF will be tendered to the Alpine Pipeline for delivery to TAPS. The Revised Applications did not address quality differences between the Nanuq Participating Areas and the Alpine Participating Area and the Fiord Participating Areas, and this Findings and Decision does not recognize any quality differences in the commingled stream for royalty payment purposes. 8. The commingling of Nanuq Kuparuk P A and N anuq N anuq P A production with Alpine Participating Area and the Fiord Participating Areas production in surface facilities before custody tránsfer is not authorized under this Findings and Decision. The implementation Of a production allocation methodology, the terms and conditions governing the commingling of the various CRU participating area produced fluids through the ACF,and the term.s and conditions governing the transfer of gas among the various CRU participating areas for production and development, repressuring, recycling, storage, and enhanced recovery purposes are the subject of another agreement document, the CRU Gas Management Agreement, effective July 1, 2006. 9. The WIOs have been allocating production for royalty reporting purposes from the Nanuq Nanuq Tract Operations for the CD4-208 and CD4-209 wells (Accounting Code "CRNN"), and from the Nanuq Kuparuk Tract Operations for CD4-318 and CD4-319 wells (Accounting Unit Code "CRNK"). Both these CD4 Nanuq Tract Operations and Account Codes expired on October 31,2006. 10. For royalty accounting purposes, the Nanuq Kuparuk PA is assigned Accounting Unit Code "CRKN". The Nanuq Nanuq PA is assigned two accounting unit codes: (1) Accounting Unit Code "CRNL" for the Liquid Unit Tract Participation factor; and (2) Accounting Unit Code "CRNG" for the Gas Unit Tract Participation factor. Effective November 1, 2006, all operator reports and royalty reports for the two participating areas must reference these Accounting Unit Codes. 14 . . 11. The Second Expansion Decision required that the entirety of eight specific CRU Tracts be included in an approved Nanuq Participating Area within four years of the effective date of the Second Expansion Decision. The Applications did not include all eight of the required CRU Tracts. The provisions of the Second Expansion Decision regarding the Nanuq Expansion Area lands are modified to incorporate the terms and conditions outlined in Attachment 5 to this Findings and Decision. For the reasons discussed in this Findings and Decision, I hereby approve the formation of the Nanuq Kuparuk P A and the Nanuq Nanuq P A, and their respective allocation of participating area expense and allocation of unit expense schedules. These approvåls are effective November 1, 2006. A person affected by this decision may appeal it, in accordance with 11 AAC 02. Any appeal must be received within 20 calendar days after the date of "issuance" of this decision, as defined in 11 AAC 02.040(c) and (d), and may be mailed or delivered to Michael Menge, Commissioner, Department of Natural Resources, 550 W. 7th Avenue, Suite 1400, Anchorage, Alaska 99501; faxed to 1-907-269-8918; or sent by electronic mail to dnr _appeals@dnr.state.ak.us. This decision takes effect immediately. An eligible person must first appeål this decision in accordance with 11 AAC 02 before appealing this decision to Superior Court. A copy of 11 AAC 02 may be obtained from any regional information office of the Department of Natural Resources. M~L/tj207?C Date / Attachments: 1) Exhibit C to the CRU Agreement for the Nanuq Kuparuk P A 2) Exhibit D to the CRU Agreement for the Nanuq Kuparuk P A 3) Exhibit C to the CRU Agreement for the Nanuq Nanuq P A 4) Exhibit D to the CRU Agreement for the Nanuq Nanuq P A 5) Terms and Conditions for Retaining the Nanuq Expansion Area Lands in the CRU CRU _ NanuqKuparukP A _NanuqNanuqP A_ Appv.doc 15 Exhibit C Nanuq Kuparuk Participating Area Attached to and made a part of the Colville River Unit Agreement Tr. ADLNoJAK Legal Depth Original Tract Working Tract No, NO.ffobin No. Description Acres Restrictions Royalty NPSL (%) Owners Interest (%) Allocation 23 ASRC-2 T11N,R4E-D.M. None 16.667 CPAI 78.000000 0.01982444 4743 Sec. 21: SII2SE1/4, APC 22.000000 932128 NE1/4SE1/4 l2Q..OO 100.000000 120.00 59 380075 T11N-R4E, D.M. None 16.667 CPAI 78.000000 0.00981036 . 4608 Sec. 14: SE1/4SW1/4, APC 22.000000 932034 S1/2SE1/4 l2Q..OO 100.000000 TOTAL 120.00 60 380075 T11N-R4E, D.M. None 16.667 CPAI 78.000000 0.01428954 4608 Sec. 13: SI/2S1/2 1&00 APC 22.000000 932034 TOTAL 160.00 100.000000 61 372097 T11N,R5E-U.M. Above 12.5 CPAI 78.000000 0.00747736 4553 Sec. 18: Sl/2SW1/4, D2...82 APC 22.000000 931996 TOTAL 69.89 100.000000 71 384211 T11N,R5E-U.M. Above 7,631' 16.667 CPAI 78.000000 0.06455466 . 4702 Sec. 19: W/12, W1/2El/2, APC 22.000000 932080 SEl/4SE1/4 ill.26 100.000000 TOTAL 481.26 72 380077 TIIN,R4E-U.M. None 16.667 CPAI 78.000000 0.11135684 4609 Sec. 24, All MQ..QQ APC 22.000000 932036 TOTAL 640.00 100.000000 Nanuq Kuparuk PA October 20, 2006 Attachment 1 Page 1 Exhibit C Nanuq Kuparuk Participating Area Attached to and made a part of the Colville River Unit Agreement Tr. ADL NoJAK Legal Depth Original Tract Working Tract No. NO.ffobin No. Description Acres Restrictions Royalty NPSL (%) Owners Interest (%) Allocation 73 380077 TlIN,R4E-D.M. None 16.667 CPAI 78.000000 0.10920400 4609 Sec. 23, All 64.Q.OO APC 22.000000 932036 TOTAL 640.00 100.000000 74 380077 TlIN,R4E-D.M. None 16.667 CPAI 78.000000 0.03486139 4609 Sec. 22: EI/2 APC 22.000000 . 932036 excl. NPRA 2l..U5 100.000000 TOTAL 217.95 75 387208 TlIN,R4E-D.M. None Sliding CPAI 78.000000 0.05082693 4831 Sec. 22: E1I2, SWI/4, Scale APC 22.000000 932193 SEI/4NW1I4, 16.66667* 100.000000 within NPRA 3il2..D2 TOTAL 302.02 76 387209 TlIN,R4E-U.M. None Sliding CPAI 78.000000 0.12127257 4832 Sec. 27: Unsurveyed, Scale APC 22.000000 932195 All, within NPRA 6H.1Q 16.66667* 100.000000 TOTAL 614.70 . 77 380077 TlIN,R4E-U.M. None 16.667 CPAI 78.000000 0.00670175 4609 Sec. 27: Unsurveyed, APC 22.000000 932036 All, excl. NPRA 24.15. 100.000000 TOTAL 24.35 78 387209 TlIN,R4E-D.M. None Sliding CPAI 78.000000 0.00501703 4832 Sec. 26, All, within NPRA 25..23 Scale APC 22.000000 932195 TOTAL 25.23 16.66667* 100.000000 Nanuq Kuparuk PA Attachment 1 October 20, 2006 Page 2 Exhibit C Nanuq Kuparuk Participating Area Attached to and made a part of the Colville River Unit Agreement Tr. ADL NolAK Legal Depth Original Tract Working Tract No. NO.ffobin No. Description Acres Restrictions Royalty NPSL (%) Owners Interest (%) Allocation 79 380077 T11N,R4E-D.M. None 16.667 CPAI 78.000000 0.15403629 4609 Sec. 26, All, excl. NPRA .6l.4.11 APe 22.000000 932036 TOTAL 614.77 100.000000 80 384209 T11N-R4E,U.M. None 16.667 CPAI 78.000000 0.11843119 4700 Sec. 25, All .64Q.QQ APe 22.000000 932195 TOTAL 640.00 100.000000 . 81 384211 T11N,RSE-U.M. None 16.667 CPAI 78.000000 0.05262994 4702 Sec. 30, All .604..00 APe 22.000000 932080 TOTAL 604.00 100.000000 120 ASRC T11N,R4E-U.M. None 16.667 CPAI 78.000000 0.08968258 4743 Sec. 28: El/2, E1/2NW1/4, APe 22.000000 932128 NEl/4SWl/4 440.00 100.000000 Sec. 34: NE1/4NE1/4 4Q..OO TOTAL 480.00 121 388905 T11N,R4E-U.M. None Sliding Scale CPAI 78.000000 0.00410726 4947 Sec. 35: Nl/2NW1/4, Royalty APe 22.000000 932357 within NPRA 12.2.8 16.6666700* 100.000000 . TOTAL 32.98 122 388902 T11N,R4E-U.M. None 16.667 CPAI 78.000000 0.01333303 4944 Sec. 35: Nl/2Nl/2, APe 22.000000 932351 Unsurveyed, excl. NPRA .121.m. 100.000000 TOTAL 127.02 Nanuq Kuparuk P A October 20, 2006 Attachment 1 Page 3 Exhibit C Nanuq Kuparuk Participating Area Attached to and made a part of the Colville River Unit Agreement Tr. ADLNoJAK Legal Depth Original Tract Working Tract No. NO.fTobin No. Description Acres Restrictions Royalty NPSL (%) Owners Interest (%) Allocation 123 388902 T11N,R4E-U.M. None 16.667 CPAI 78.000000 0.01132938 4944 Sec. 36: N1/2N1I2, APC 22.000000 932351 Unsurveyed, 1&00 100.000000 TOTAL 160.00 124 388903 T11N,R5E-U.M. None 16.667 CPAI 78.000000 0.00125346 . 4945 Sec. 31: N1I2 NW1I4, APe 22.000000 932353 NW1/4~1/4, Unsurveyed .ll.1ÆI: 100.000000 TOTAL 111.44 TOTAL PA ACREAGE 6,185.61 *Sliding Scale Overriding Royalty - The Original Royalty Percentage of this lease will vary between 16.66667% and 33.33333%. KEY: CPAI: APC: ASRC: ConocoPhillips Alaska, Inc. Anadarko Petroleum Corporation Arctic Slope Regional Corporation . Nanuq Kuparuk P A October 20, 2006 Attachment 1 Page 4 - - - Unit Boundary Tract Boundary Proposed Participating Area Tract Number Exhibit D lie Proposed Nanuq ruk Participating Area 05121303801 Exhibit C Nanuq Nanuq Participating Area Attached to and made a part of the Colville River Unit Agreement Tr. ADL NojAK Legal Depth Original Tract Working Liquid Tract Gas Tract No. NoJrobin No. Description Acres Restrictions Royalty (%) NPSL (%) Owners Interest Allocation Allocation 44 25559 T11N,R5E-U.M. None 12.5 CPAI 78.000000 0.00396439 0.00393185 4717 Sec. 7: SWl/4, SWl/4SEl/¿ 1.18..22 APC 22.000000 932104 TOTAL 178.29 100.000000 50 380075 T11N-R4E, U.M. None 16.667 CPAI 78.000000 0.00133420 0.00143395 . 4608 Sec. 12: SEl/4, SI/2SWl/4 24Q.OO APC 22.000000 932034 TOTAL 240.00 100.000000 59 380075 T11N-R4E, U.M. None 16.667 CPAI 78.000000 0.00098914 0.00337047 4608 Sec. 14: SI/2,~1/4 48Q.QQ APC 22.000000 932034 TOTAL 480.00 100.000000 60 380075 T11N-R4E, U.M. None 16.667 CPAI 78.000000 0.04474421 0.06467247 4608 Sec. 13, All ~ APC 22.000000 932034 TOTAL 640.00 100.000000 61 372097 T11N,R5E-U.M. Above 12.5 CPAI 78.000000 0.08128247 0.11894988 4553 Sec. 17: SWl/4SWl/4 40.00 APC 22.000000 931996 Sec. 18: SI/2, NWl/4, 100.000000 . NW1I4~1I4, S1I2~1I4 lli.OO TOTAL 599.00 70 384211 T11N,R5E-U.M. Above 7,631' 16.667 CPAI 78.000000 0.05487561 0.05368143 4702 Sec. 20: SWl/4, APC 22.000000 932080 S1I2NW1I4, NW1I4NWl/4, 100.000000 SW1I4SE114 12Q..QQ TOTAL 320.00 Nanuq Nanuq PA Attachment 3 October 19, 2006 Page 1 Exhibit C Nanuq Nanuq Participating Area Attached to and made a part of the Colville River Unit Agreement Tr. ADL NojAK Legal Depth Original Tract Working Liquid Tract Gas Tract No. NoJTobin No. Description Acres Restrictions Royalty (% ) NPSL(%) Owners Interest Allocation Allocation 71 384211 T11N,R5E-D.M. Above 7,631' 16.667 CPAI 78.000000 0.13672878 0.16524606 4702 Sec. 19, All 6.QLOO APe 22.000000 932080 TOTAL 601.00 100.000000 72 380077 T11N,R4E-D.M. None 16.667 CPAI 78.000000 0.15189959 0.15267645 4609 Sec. 24, All 64Q.OO APe 22.000000 932036 TOTAL 640.00 100.000000 . 73 380077 T11N,R4E-D.M. None 16.667 CPAI 78.000000 0.07029177 0.06285506 4609 Sec. 23, All 64Q.OO APe 22.000000 932036 TOTAL 640.00 100.000000 74 380077 T11N,R4E-D.M. None 16.667 CPAI 78.000000 0.00258281 0.00462472 4609 Sec. 22: El/2SEl/4, APe 22.000000 932036 excl. NPRA 1.2.1Q 100.000000 TOTAL 72.30 75 387208 T11N,R4E-U.M. None Sliding CPAI 78.000000 0.00030024 0.00022185 4831 Sec. 22: El/2SEl/4, Scale APe 22.000000 932193 within NPRA 7..:Æ 16.66667* 100.000000 . TOTAL 7.78 76 387209 T11N,R4E-D.M. None Sliding CPAI 78.000000 0.00150424 0.00105888 4832 Sec. 27: El/2NEl/4, Scale APe 22.000000 932195 within NPRA ß!û 16.66667* 100.000000 TOTAL 55.63 Nanuq Nanuq PA October 19, 2006 Attachment 3 Page 2 Exhibit C Nanuq Nanuq Participating Area Attached to and made a part of the Colville River Unit Agreement Tr. ADL NojAK Legal Depth Original Tract Working Liquid Tract Gas Tract No. Noffobin No. Description Acres Restrictions Royalty (% ) NPSL(%) Owners Interest Allocation Allocation 77 380077 T11N,R4E-U.M. None 16.667 CPAI 78.000000 0.00098713 0.00069265 4609 Sec. 27: EII2NEl/4, APe 22.000000 932036 excl. NPRA 24.35 100.000000 TOTAL 24.35 78 387209 T11N,R4E-U.M. None Sliding CPAI 78.000000 0.00079033 0.00055456 4832 Sec. 26, All, within NPRA 25..23. Scale APe 22.000000 . 932195 TOTAL 25.23 16.66667* 100.000000 79 380077 T11N,R4E-U.M. None 16.667 CPAI 78.000000 0.05979268 0.04195588 4609 Sec. 26, All, excl. NPRA ill.l1 APe 22.000000 932036 TOTAL 614.77 100.000000 80 384209 T11N-R4E,U.M. None 16.667 CPAI 78.000000 0.13717617 0.10919518 4700 Sec. 25, All .64Q..QQ APe 22.000000 932195 TOTAL 640.00 100.000000 81 384211 T11N,R5E-U.M. None 16.667 CPAI 78.000000 0.09788954 0.10373820 4702 Sec. 30, All DíM.QQ APe 22.000000 932080 TOTAL 604.00 100.000000 16.667 78.000000 0.05059148 0.03915652 . 82 380082 T11N-R5E,U.M. None CPAI 4614 Sec. 29: Wl/2, W l/2NE 1/4, APe 22.000000 932046 NWl/4SE1/4 44Q..QQ 100.000000 TOTAL 440.00 Nanuq Nanuq PA October 19, 2006 Attachment 3 Page 3 Exhibit C Nanuq Nanuq Participating Area Attached to and made a part of the Colville River Unit Agreement Tr. ADL NojAK Legal Depth Original Tract Working Liquid Tract Gas Tract No. Noffobin No. Description Acres Restrictions Royalty (% ) NPSL (%) Owners Interest Allocation Allocation 121 388905 T11N,R4E-D.M. None Sliding Scale CPAI 78.000000 0.00105855 0.00074277 4947 Sec. 35: E1I2NW1I4, Royalty APe 22,000000 932357 Unsurveyed, 16.6666700* 100.000000 within NPR-A 2Jl11 TOTAL 20.77 122 388902 T11N,R4E-D.M. None 16.667 CPAI 78.000000 0.02336865 0.01639753 . 4944 Sec. 35: NE1I4, E1I2NW1I4, APe 22.000000 932351 N1I2SE1I4, Unsurveyed, 100.000000 excluding the NPR-A 222..2l TOTAL 299.21 123 388902 TIIN,R4E-D.M. None 16.667 CPAI 78.000000 0.03994446 0.02802883 4944 Sec. 36: N1I2, Nl/2S1I2 APe 22.000000 932351 Unsurveyed, 48Q.OO 100.000000 TOTAL 480.00 124 388903 TllN,R5E-D.M. None 16.667 CPAI 78.000000 0.03790356 0.02681481 4945 Sec. 31: N1I2, N1I2 SW1I4, APe 22.000000 932353 NW1I4SE1I4, 100.000000 Unsurveyed, 414.65 . Sec. 32: N1I2NW1I4, SW1I4NW1I4 Unsurveyed, .12Q..QQ TOTAL 534.65 TOTAL PA ACREAGE 8,156.98 *Sliding Scale Overriding Royalty - The Original Royalty Percentage of this lease will vary between 16.66667% and 33.33333%. Nanuq Nanuq PA October 19, 2006 Attachment 3 Page 4 Tr. No. ADL NoJAK No.ffobin No. KEY: Nanuq Nanuq PA October 19, 2006 CPAI: APC: ASRC: Legal Description Acres Exhibit C Nanuq Nanuq Participating Area Attached to and made a part of the Colville River Unit Agreement Depth Original Tract Restrictions Royalty (%) NPSL (%) Owners ConocoPhillips Alaska, Inc. Anadarko Petroleum Corporation Arctic Slope Regional Corporation Working Interest Liquid Tract Allocation Gas Tract Allocation . . Attachment 3 Page 5 - - - Unit Boundary Tract Boundary Proposed Participating Area CD Tract Number Exhibit D Colville River Unit p 05121303COO . . ATTACHMENT 5 ConocoPhillips and the other CRU Working Interest Owners (WIOs) agreed to the following terms and conditions to retain the Nanuq Exparision Area lands, as described in Section A.3. of the November 8, 2002, Second Expansion Decision, within the CRU 1) The WIOs shall make lease payments to retain the Nanuq Expansion Area lands to the State and ASRC in the amount of $111,776.06 and $116,860.31, respectively, by October 1, 2006, and $214,100.26 and $202,392.08, respectively, by October 1, 2007. The WIOs have made the 2006 payment. The 2007 payment is not subject to the provisions of3, below. 2) The WIOs shall make a payment of $35.00 per acre on October 1,2008, for each acre of Nanuq Expansion Area land not included in a Nanuq PA by that date. The WIOs shall make a payment of $45.00 per acre on October 1,2009,2010, and 2011, for each acre ofNanuq Expansion Area land not included in a Nanuq P A by those dates. 3) The WIOs may voluntarily contract Nanuq Expansion Area land from the CRU on a tract-by-tract basis. Any tracts contracted before July 1 of a given year, beginning in 2007, will result in' payment reduction on an acreage, basis for the following year (e.g., any tracts eontracted before July 1, 2007, would result in a payment reduction on an acreage basis on;the October 1, 2008, payment date). Otherwise, annual payments will be due under 2,' above, for the Nanuq Expansion Area lands retained within the CRU, but not included within a Nanuq Participating Area. 4) The Division approves a deferral, until August 1,2011, of the ten-year automatic contraction required under Section 12.2 of the CRU Agreement for the Nanuq Expansion Area lands. 5) If the WIOs fail to timely make the payments required, above, any Nanuq Expansion Area lands not included in a Nanuq P A on the date that a payment is due will automatically contract from the CRU. #10 . . Conoc6Phillips Chris Alonzo Development Supervisor. WNS ConocoPhillips Alaska 700 G Street Anchorage. AK 99501 Phone: 907.276.1215 November 7,2005 Mr. John Nonnan, Chair Alaska Oil and Gas Conservation Commission Alaska Department of Revenue 333 West 7th Avenue, Suite 100 Anchorage,AJe 99501 Re: Supplemental Infonnation for Area Injection Order(s) for Proposed Nanuq and Nanuq-Kuparuk Oil Pools Colville River Field Dear Mr. Nonnan: On September 15,2005, ConocoPhillips Alaska, Inc. (CPA!) as operator of the Colville River Unit and on behalf of the Working Interest Owners, requested an area injection order (AIO) authorizing enhanced recovery operations in the proposed Nanuq and Nanuq-Kuparuk oil pools. Mr. Steve Davies communicated some questions and comments regarding the Nanuq AIO on October 28,2005. Attached to this letter are responses to the questions and comments. I hope that this infonnation meets your needs and I am available to discuss it with you and your staff if needed. Please call me at 265-6822 or Jack Walker at 265-6268 if you have questions. Very truly yours, Chris Alonzo Development Supervisor, Western North Slope ConocoPhillips Alaska, Inc. Attachment . . Applications for Area Injection Order(s) for Proposed Nanuq and Nanuq-Kuparuk Oil Pools Colville River Field November 7, 2005 Page 2 cc: Alaska Department of Natural Resources Division of Oil and Gas Attention: Mike Kotowski 550 W. 7th Avenue, Suite 800 Anchorage, Alaska 99501 Arctic Slope Regional Corporation Attention: Teresa Imm 3900 C Street, Suite 801 Anchorage, Alaska 99503-5963 Kuukpik Corporation Attention: Isaak Nukapigak P.O. Box 187 Nuiqsut, Alaska 99789-0187 Kuukpik Corporation Attention: Lanston Chinn 825W. 8th Avenue, Suite 206 Anchorage, Alaska 99501 Anadarko Petroleum Corporation Attention: Bill Shackelford 1201 Lake Robbins Drive P.O. Box 1330 Houston, Texas 77251-1330 ConocoPhillips Alaska, Inc. Attention: Matt Elmer ATO 1750 700 W. G Street P.O. Box 100360 Anchorage, Alaska 99510-0360 . . ~upplementallnformation for the Nanuq and Nanuq-Kuparuk AIO AOGCC questions (some cases statements with blanks filled in by CPAI) are shown in normal font. CPAI responses are shown in bold, italicized font. 1. Production and injection rate estimates are needed for each pool for public record: Annualized peak production rates for the Nanuq Oil Pool are expected to be between 4,000 and 11,000 barrels of oil per day ("BOPD"). Annualized waterflood injection rates are estimated to peak between 3,500 and 9,600 barrels of water per day ("BWPD") and miscible gas injection rates are expected to peak at 12 to 33 million standard cubic feet of gas per day ("MMSCFD"). Annualized peak production rates for the Nanuq-Kuparuk Oil Pool are expected to be between 3,700 and 8,500 barrels of oil per day ("BOPD"). Annualized waterflood injection rates are estimated to peak between 3,500 and 7,900 barrels of water per day ("BWPD") and miscible gas injection rates are expected to peak at 3.5 to 8 million standard cubic feet of gas per day ("MMSCFD"). 2. Recovery estimates are needed for public record. Are the following statements accurate? The Nanuq Oil Pool is estimated to contain 84 to 169 million stock tank barrels ("STB") of original oil in place ("OOIP") within the development area, based on exploratory drilling and seismic mapping. Computer simulation suggests primary recovery for the pool is expected to be approximately 10% of the OOIP. Waterflood is expected to increase recovery by 10 to 15%. and use of MWAG technology should produce an additional 9 to 14% of the OOIP. The Nanuq-Kuparuk Oil Pool OOIP is estimated to be 21 to 36 million STB within the development area. Primary recovery is estimated to be approximately 15% of OOIP. Incremental waterflood recovery is expected to recover an additional 25 to 37% above primary. Reservoir simulation supports an incremental increase of 17 to 25% for the MW AG process. Yes, these statements are accurate. 3. A general description of the Nanuq and Nanuq-Kuparuk structure is needed for the record. The Nanuq reservoir is a basin floor submarine fan system dominated by lobe-sheet deposits. The fan system lies 1 to 2 miles east of the time equivalent, northeast-southwest trending base of slope. The Nanuq reservoir occurs at a local high in the Drillsite CD4 area with structure dipping to the south and east, and absence of sand to the north and west. The trap is stratigraphically created. There are no major faults cutting the Nanuq reservoir. The Nanuk #1 and #2 and Nanuq #3 and #5 wells define the core of the development area for the Nanuq reservoir. Log and core data confirm an oil-water contact at 6,207 subsea true vertical depth (TVD). The CD1-229 test indicated a possible gas cap. Page 1 of 3 11/7/2005 CPAI Responses to AOGCC Questions · . ~upplementallnformation for the Nanuq and Nanuq-Kuparuk AIO The Nanuq-Kuparuk reservoir is a shallow marine transgressive sandstone that lies below the Kalubik shales and just above the Lower Cretaceous Unconformity (LCU). The structure dips from east to west at approximately 0.7 degrees. Trap is stratigraphic in nature with sand encased above and below by shales. The northern edge of the reservoir has one mapped fault which not expected to affect recovery. 4. In the application, there is a statement that a single, small fault has been mapped in the northern portion of the development area, but is not expected to affect reservoir performance. Does this fault affect both intervals? That fault cuts only the Nanuq-Kuparuk reservoir, and is not apparent in the Nanuq reservoir. 5. Please provide a statement regarding compatibility of produced water with the reservoir. Will produced water be used for EaR purposes at CD4? Based on commingled processing of several pools (Alpine, Fiord and Nanuq initially and others later) at CD1 it appears possible that multiple produced waters could be injected at CD4. If so, please provide a statement addressing compatibility of that water with the Nanuq and Nanuq-Kuparuk Oil Pools. The water injection plan for the Nanuq and Nanuq-Kuparuk Oil Pools is based on a single water injection pipeline between the Alpine Central Facility (ACF) and Drill Site CD4. Processing of all production from all pools in the Colville River Field is planned via the ACF. Drill Site CD4 is the surface location for all development wells planned for the two proposed pools. Seawater is planned as the initial waterflood source water for Drill Site CD4 and produced water or mixed water is planned for injection later in the field life. Production commingling on the surface is planned for all pools in the Colville River Field at the ACF. Compatibility of waters will be managed with the addition of scale inhibitors. Scale inhibitor is presently used for produced water and seawater mixing upstream of one of three water injection pumps at the Alpine Central Facility (ACF). By mixing produced water and seawater, pump utilization can be maximized in the interim when produced water volume is sufficient to only partially load a water injection pump. The other two ACF water injection pumps are presently dedicated to seawater service. The mixed water and seawater injection lines are segregated and each flow to a separate set of wells. The mixed produced water and seawater are presently directed to a certain subset of wells at Drill Site CD1. As produced water increases beyond the capacity of a single pump, the segregation of the mixed water may be ceased and all wells served by the ACF water injection system may receive mixed seawater and produced water. Page 2 of 3 11m2005 CPAI Responses to AOGCC Questions . . ~upplementallnformation for the Nanuq and Nanuq-Kuparuk AIO 6. Is it possible that non- hazardous filtered water collected from the initial Alpine development area will be considered for injection at CD4? If so, appropriate statements of request and justification are needed. Yes, Commission-approved fluids used for injection in the Alpine Oil Pool will be considered for injection at CD4. Non-hazardous fluids from several sources in the Colville River Reid are normally injected into the WD-02 Class I disposal well. But, the WD-02 well is occasionally unavailable due to compliance testing or diagnostics. The Commission approved blending of specific non-hazardous fluids with existing Class II fluids used for EaR in the Alpine Oil Pool (Ala 188.002). When WD-D2 is unavailable, current practice is to blend specific non- hazardous fluids (NHF) approved by the Commission with the mixed water stream discussed in section 5. Manifolding at the Alpine Central Facility allows the segregation of the blended NHF stream for injection into a subset of CD1 wells. As produced water increases and exceeds the capacity of a single water injection pump, all injection water for the Colville River Field may become mixed water, and the NHF will be blended into that stream. If NHF is blended in the entire stream of Colville River Field EaR injection water, the concentration of NHF will decrease to 0.02% of the EaR injection water. This concentration is not expected to cause any change to the EaR effciency in any of the Colville River Field pools. Page 3 of 3 11/7/2005 CPAI Responses to AOGCC Questions . .__.... ___ _",_n._.. _.__.. _ ____u____ '<._._..~__ _......_._. . Subject: Nanuq Area Injection Order: Additional Questions for Operator From: Stephen Davies <steve _ davies@admin.state.ak.us> Date: Fri, 28 Oct 2005 14:42:52 -0800 To: Jack.A. Walker@conocophillips.com CC: Tom Maunder <tom_maunder@admin.state.ak.us>, John Hartz <jack_hartz@admin.state.ak.us> Jack, Attached are a few more questions from AOGCC concerning the Nanuq Area Injection Order. I apologize for the delay in getting them to you. These are the last few questions we have prior to completing the order. The public hearing scheduled for Tuesday, Nov. 1 has been vacated. Please call me at 793-1224 if you have any questions. Sincerely, Steve Davies Petroleum Geologist Alaska Oil & Gas Conservation Commission Content-Type: applicationlmsword 051027_ Questions_ for_Operator _ Nanu«L AIO _.doc Content-Encoding: base64 10fl 1/19/2006 8:52 AM . . Nanuq AIO Questions for Operator 1. Production and injection rate estimates are needed for each pool for public record: Peak production rates for the Nanuq Oil Pool are expected to be between and barrels of oil per day ("BOPD"). Waterflood injection rates are estimated to peak between and barrels of water per day ("BWPD") and miscible gas injection rates are expected to peak at million standard cubic feet of gas per day ("MMSCPD"). Peak production rates for the Nanuq-Kuparuk Oil Pool are expected to be between and barrels of oil per day ("BOPD"). Waterflood injection rates are estimated to peak between and barrels of water per day ("BWPD") and miscible gas injection rates are expected to peak at million standard cubic feet of gas per day ("MMSCPD"). 2. Recovery estimates are needed for public record. Are the following statements accurate? The Nanuq Oil Pool is estimated to contain million stock tank barrels ("STB") of original oil in place ("OOIP") within the development area, based on exploratory drilling and seismic mapping. Computer simulation suggests primary recovery for the pool is expected to be % of the OOIP. Waterflood is expected to increase recovery by 10 to 15%, and use of MWAG technology should produce an additional 9 to 14% of the OOIP. The Nanuq-Kuparuk Oil Pool OOIP is estimated to be million STB within the development area. Primary recovery is estimated to be %. Incremental waterflood recovery is expected to recover an additional 25 to 37% above primary. Reservoir simulation supports an incremental increase of 17 to 25% for the MWAG process. 3. A general description of the Nanuq and Nanuq-Kuparuk structure is needed for the record. 4. In the application, there is a statement that a single, small fault has been mapped in the northern portion of the development area, but is not expected to affect reservoir performance. Does this fault affect both intervals? 5. Please provide a statement regarding compatibility of produced water with the reservoir. Will produced water be used for EOR purposes at CD4? Based on commingled processing of several pools (Alpine, Fiord and Nanuq initially and others later) at CD1 it appears possible that multiple produced waters could be injected at CD4. If so, please provide a statement addressing compatibility of that water with the Nanuq and Nanuq-Kuparuk Oil Pools. 6. Is it possible that non- hazardous filtered water collected from the initial Alpine development area will be considered for injection at CD4? If so, appropriate statements of request and justification are needed. AOGCC Page 1 of 1 2/14/2006 051020_ Questions_for _Operator _ Nanu<L AlO.doc #9 . . STATE OF ALASKA OIL AND GAS CONSERV A TION COMMISSION Conservation Order Hearing Nanuq and Nanuq-Kuparuk Oil Pools TESTIFY (Yes or No) NAME - AFFILIATION ADDRESSIPHONE NUMBER (PLEASE PRINT) __)ò~M w·,€s<:,·- c1'1\.( '~\\ ~~~-"h?k-ry DAY ÀN.L :~rs--L(S-'() :rtcëL WA.LL¿¿v ê.?kJ-. 7/1 j,v. &; (~lS A lo"Y?:o (p/t-:Ç 700 (S.. 5teJ~ {Woo rh.CLIÎ~ Cfft'1 1ro 6-,St .. :T/ \N'\ ÞeV1f1Z+f- ('ÞÆ-r7tJ[) C 'f.¡.... 'ß~¡&,;:, ¡.,.{& ( c14£ 7Ú(; (,. It- {){){U'r()DI(.1 A c.f A r 700 r; --S r . W/!:JII!4 //lh j)~lUfl ()¿,C;&l1 1/é~,3Sßt?)(5LJ3? JOI-lN Â _ W ì-\l TN&( BPTAQU 112A ~4-:323[ Ka.ttl ,ftJÇ;I-I¡:I~ C PH:! "7ðo 0' Sf- '1õ~ ~t~ê\ r:{::lò~ A~LC D~YDD&J~ y~~. Y<2wY /'1,0 2&5 -~<2r;[1J 2c,ç,(ògz2. Ye- 5. X> Àb S- - 6C¡b.r . 20 5--- 'Sr-K 7J Alð 2¿ J-c:" 977 dtvr;-,&¡)97 lies / i-JO ÆJc-, ~ ,Jù ¡(JO (J &5""-- /ó¡ s- ~s-\dçù '793-/2.2-4 ~G,r· eat ~ #8 . . 1 ALASKA OIL AND GAS CONSERVATION COMMISSION 2 Before Commissioners: John K. Norman, Chairman Daniel T. Seamount Cathy Foerster 3 4 In the Matter of the Application ) of CONOCOPHILLIPS ALASKA for Pool ) 5 Rules for Colville River Field, ) Proposed Nanuq oil Pool and ) 6 Proposed Nanuq-Kuparuk oil Pool ) ) 7 8 ALASKA OIL and GAS CONSERVATION COMMISSION Anchorage, Alaska 9 October 4, 2005 9:00 o'clock a.m. 10 11 VOLUME I PUBLIC HEARING (EXCERPT) 12 BEFORE: John K. Norman, Chair Daniel T. Seamount, Commissioner Cathy Foerster, Commissioner 13 14 15 16 17 18 19 20 21 22 23 24 25 R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 . 1 TABLE OF CONTENTS 2 Opening Remarks by Chair Norman . 3 Testimony of Jordan Wiess . . . . . 4 Testimony of Steve Moothart . . . 5 Testimony of Jim Bennett. . . 6 Testimony of Brian Noel . ........... 7 Testimony of Jack Walker. . . . . . . 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 . . . . . . . . . . . . . . . ....... . . . . . R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 · . . . . . . . · . . · . . · . . 03 · . . 07 · . 18/55 . . . . .46 . .61 · . . .79 . . 1 PRO C E E DIN G S 2 Tape 1 3 0015 4 (On record - 9:00 a.m.) 5 CHAIR NORMAN: Good morning. I'll call this hearing to 6 order. This is a hearing before the Alaska oil and Gas 7 Conservation Commission. The hearing is being held on the 8 morning of Tuesday, October 4th, 2005 at the commission's 9 offices, 333 West Seventh Avenue, suite 100, Anchorage, Alaska. 10 with me on my right is commissioner Dan Seamount. To my 11 left is commissioner Cathy Foerster and I am John Norman, the 12 third Commissioner and Chairman of the commission. We have a 13 quorum of the commission present today. 14 I would first like to address the American With 15 Disabilities Act and the Commission's policy in extending 16 accommodations to any persons who wish to participate in the 17 meeting and who may need special accommodations to do so. If 18 you are such a person and you have any problem hearing or with vision or with access you may see the Commission's special assistant Jody Columbie. Ms. Columbie, would you hold up your 19 20 21 hand, please, and she will assist you in any way we can. 22 These proceedings are being recorded. There will be a 23 transcript of these proceedings as with any other of the 24 Commission's hearings. 25 This application was filed by conocoPhillips as operator R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 3 . . 1 on August 11th, 2005. It's an application to classify the 2 Nanuq and Nanuq-Kuparuk reservoirs as oil pools and to 3 prescribe rules for the development and operation of those 4 pools. 5 The applicant has filed documentation in support of the 6 application. There has been a request that certain items of 7 information filed be held confidential and the request is made 8 pursuant to Alaska -- for confidentiality is made pursuant to 9 Alaska statute 31.05.035(d) and 20 -- Alaska Administrative 10 Code 25.537 which does authorize the Commission upon a proper 11 showing to maintain confidentiality as to proprietary 12 information. 13 The commission does have a bias, however, on having a 14 maximum amount of information made public and if any persons 15 are in doubt we will at least try to provide a summary so that 16 we know -- so that persons can know the type of information 17 that for which confidentiality has been asserted. 18 The application indicates that develop a drilling for 19 these reservoirs is anticipated for some time later this month 20 and first production is anticipated for the fourth quarter of 21 2006. 22 The notice of this Public Hearing was published in the 23 Anchorage Daily News on the 18th of August. Any persons 24 wishing to get a copy of the application as published can see 25 the Commission's special assistant. R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 4 . . 1 The Commission's staff had certain additional questions 2 regarding the application and those questions were responded to 3 in a supplemental response filed by the operator with the 4 Commission. That is dated September 28th, 2005. 5 Briefly the Commission had a question about boundaries and 6 whether property lines, ownership and all other issues had been 7 resolved and -- or whether these would encroach within 500 feet 8 and create any such issues and that answer was no. 9 Additionally, the Commission had a question about whether 10 affected working interest ownership, land ownership, surface 11 ownership issues had been addressed and the response is yes, 12 that those issues have been addressed. 13 Initially the proposed conservation rule requested a 300 14 foot setback from external boundary lines. In response to the 15 Commission's request that has been amended to request 500 feet 16 from external -- exterior boundary lines which is more in 17 keeping with the Commission's traditional rules. 18 Other questions will be addressed and I anticipate that 19 either the applicant or the Commissioners will develop those, 20 but any persons desiring any of this response, some portions of 21 it are indicated as confidential and so we will need to redact 22 it, but we would make available the supplemental information so 23 that any persons desiring that information will have access to 24 it. 25 We will begin by hearing first from the applicant. We do R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 5 . . 1 prefer sworn testimony. We give greater weight and credibility 2 when testimony is delivered under Oath. If any persons object 3 to being sworn, however, we certainly will allow you to 4 testify, but for obvious reasons we assign greater credibility 5 to sworn testimony. 6 We normally do not entertain cross examination. We will 7 if any persons present at this hearing today do wish to have 8 questions answered, you could write them out, provide them to 9 the Commission and we will try to see that any questions are 10 answered. 11 Following the applicant we will also then hear from any 12 others present who have relevant testimony on the matter before 13 us today. 14 Additionally, if any persons are testifying from the 15 perspective of expertise then we will request a statement of 16 qualifications so we can determine whether the person 17 testifying does qualify as an expert witness. 18 Commissioner Seamount, do you have anything further before 19 we start? 20 COMMISSIONER SEAMOUNT: I have none, Mr. Chairman. 21 CHAIR NORMAN: Commissioner Foerster? 22 COMMISSIONER FOERSTER: No. 23 CHAIR NORMAN: Okay. All right. We're ready to begin 24 then and I'll ask the first witness to begin by raising your 25 right hand and we will swear you and then..... R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 6 . . 1 (Oath Administered) 2 MR. WIESS: Yes. 3 CHAIR NORMAN: Okay. Would you, please, begin by stating 4 your name and who you represent. 5 TESTIMONY BY JORDAN WIESS 6 MR. WIESS: My name is Jordan Wiess. I am the Nanuq and 7 Fiord development coordinator for ConocoPhillips Alaska within 8 the Alpine development area. I'm going to be providing 9 introduction as well as some of the technical information on 10 the development for the Nanuq development that we are trying to 11 proposed approvals for. 12 First, I'd like to thank everyone for being here and 13 Commissioners and audience that's gathered. We're here this 14 morning to present testimony to support our application for the 15 pool rules for both the Nanuq and Nanuq-Kuparuk pool rules and 16 to establish those rules. 17 ConocoPhillips has been designated the operator of the 18 Nanuq development and we'll be providing testimony on behalf of 19 the CD4 Nanuq working interest owners. The scope of this 20 testimony will include the development as we currently 21 understand the geology and reservoir properties, as well as our 22 plans for the reservoir development and additional information 23 on our wells and facilities that we intend to put in place 24 during the next two year. 25 We have prefiled written testimony with the commission as R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 7 . . 1 you've discussed already today. In addition we do have copies 2 of the presentation we're providing today and we can provide 3 those to you if you wish to see those right now. 4 CHAIR NORMAN: And we'll -- what you are able to file, 5 will that be copies of the slides that you will be 6 presenting..... 7 MR. WIESS: That is correct. 8 CHAIR NORMAN: .....on the power point? Good,..... 9 MR. WIESS: That is correct. 10 CHAIR NORMAN: .....that -- that's very helpful. 11 And I would ask -- this is a general comment to everyone 12 who may be testifying, keep in mind that there will be a 13 written transcript and that it's possible that a year or two 14 from now someone will be reading the transcript and so when 15 you're referring to a map or a chart or other exhibit try to 16 identify it in a way that it will take the reader back to the 17 attached prefiled testimony and exhibits. 18 Please proceed, Mr. Wiess. 19 MR. WIESS: In verbal testimony this morning we want to 20 provide a general foundation information on the development we 21 have planned, as well as a brief discussion of the 11 proposed 22 pool rules for the Nanuq CD4 development. 23 The agenda that we have proposed for today we're going to 24 go through an introduction, which I will do. I'll discuss the 25 location, the pool rules request, the background of the R & Reo U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 8 . . 1 development and what our planned development is. 2 steve Moothart will be discussing the geology and there 3 will be a confidential section within his presentation and we 4 ask to go into confidential session for that and we could 5 return from that and continue on with the reservoir discussion 6 with Jim Bennett. steve Moothart will again talk regarding the 7 annular disposal for the development. 8 Brian Noel will discuss the well construction and then 9 Jack Walker will discuss the well operations as well as our 10 facilities and then I will wrap up for the testimony for today. 11 So just as a means for introduction the first slide here 12 is just an introduction slide. Just over a year ago, you know, 13 ConocoPhillips and Anadarko Petroleum announced the development 14 for the Nanuq CD4 field. You know, the field is located 15 approximately four miles south of the Alpine development pads 16 within the Colville River unit. 17 And the next three slides I will show are our maps and 18 will show the location of the area of the development as well 19 as the proposed CD4 Nanuq pool rules area. 20 COMMISSIONER SEAMOUNT: Mr. Wiess, would you like us to 21 see if we could fix the projection? 22 MR. WIESS: Yes, that would help. COMMISSIONER SEAMOUNT: This happens all the time. Our 23 24 expert is coming right now. 25 MR. WIESS: On the first location slide I have here is R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 9 . . 1 effectively a map of the North Slope oil fields. There is a 2 small inset map which locates where the oil fields are within 3 the State of Alaska on the Alaska North Slope. 4 What you see on the large map is all of the oil fields 5 that ConocoPhillips has a working interest in. And one of the 6 things you can see from this is as you move from the eastern 7 oil fields to the western ones, the conocoPhillips working 8 interest does increase. And within the Alpine region where 9 both the Nanuq and Fiord developments are occurring, 10 conocoPhillips has a 78 percent working interest. 11 The other 22 percent is owned by Anadarko Petroleum 12 Company and there are several owners of the royalty interest 13 which include Arctic Slope Regional corporation as well as the 14 State of Alaska. 15 We'll zoom in on the red box next. This is a more 16 detailed map showing the location of the Nanuq development in 17 relation to the Alpine field. The drill site that we're 18 proposing on the development is located down through here. 19 This drill site is located approximately four miles south of 20 the current Alpine drill site and is about halfway between the 21 Alpine development and the Village of Niuqsut limits. 22 At the same time that we are developing the Nanuq field, 23 as we announced back in December of last year, we are also 24 developing the Fiord field up through here and both of these 25 fields are being developed in conjunction with each other to R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 10 . . 1 ensure that we have synergies within our drilling operations as 2 well as our construction operations for the next three years. 3 On the third slide we show a picture of the proposed 4 affected area of the pool rules. 5 CHAIR NORMAN: Mr. Wiess, if I could just -- since we're 6 making a record, on the -- on the printouts here in the lower 7 right hand corner there are page references and right now we 8 have on the screen what shows on ours as page 5, is that -- is 9 tha t. . . . . 10 MR. WIESS: The location..... 11 CHAIR NORMAN: I just want to..... 12 MR. WIESS: Yes. 13 CHAIR NORMAN: .....match this up with the record so when 14 you say on the third slide, but it shows page..... 15 MR. WIESS: On the third map slide, sorry. 16 CHAIR NORMAN: On the third map slide..... 17 MR. WIESS: Yes. 18 CHAIR NORMAN: .....which is on page 5 of the handout. 19 MR. WIESS: The third page slide will be page 6 which will be the proposed affected area of pool rules. CHAIR NORMAN: I'm sorry, page 6 you're right. 20 21 22 MR. WIESS: Yes. 23 CHAIR NORMAN: Thank you. 24 MR. WIESS: Okay. 25 COMMISSIONER SEAMOUNT: which is on the third page of the R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 11 . . 1 handout. 2 MR. WIESS: This map shows the current colville River Unit 3 as well as the PA for the Alpine proper field, showing the CD1 4 and CD2 drill sites and we are showing the proposed preliminary 5 PAs for the Nanuq field, the Nanuq participating area and then 6 the Nanuq-Kuparuk participating area. And then the green 7 outline is the proposed affected area for the Area Injection 8 Order and pool rules. The entire region of the area affected 9 is within the boundaries of the colville River unit with the 10 exception of this one section here within the southwest region. 11 Slide 7 shows the 11 pool rules that we're proposing for 12 the Nanuq and Nanuq-Kuparuk development. Now these should be 13 very familiar to you and you should note that they are very, 14 very similar to rules that have been proposed and approved for 15 both Tarn and Alpine in the past and we've used both of these 16 for models for the Nanuq and Nanuq-Kuparuk pool rules. We'll 17 be supplying testimony today to support the rules that we both 18 propose for the Nanuq and the Nanuq-Kuparuk rules. 19 The next slide, which is slide 8, I'd just briefly like to 20 discuss the key points that we feel are appropriate to use as a 21 basis for the pool rules and the items considering as we 22 develop the list of proposals. 23 Now the first three should be very familiar. I'm sure the 24 Commission -- in preventing waste and promoting the 25 conservation, as well as promoting the correlative rights for R & Reo U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 12 . . 1 all the owners and promoting the maximum recovery for the 2 developments and for the state. And we feel that our 3 development plans and the pool rules we're proposing are very 4 much in keeping with these ideals. In addition, as I've already mentioned, we would like to seek to have consistency with the Alpine pool rules that have 5 6 7 been prior approved and we are going to be operating within the 8 Colville River Unit. As well as proposing additional pool 9 rules, we want to ensure that we have consistency between the 10 Alpine, the Nanuq and then the future proposed pool rules that 11 we'll have for Fiord and other operations. 12 On slide 9, just showing a quick time line of the Nanuq 13 development and we'll be getting into greater details in terms 14 of the development with steve and Jim, but, you know, 15 effectively what we have here is a time when the Alpine field 16 proper was discovered in 1994 and through the delineation of 17 the Alpine field we actually discovered Nanuq in 1996. 18 Now, there was continued operations and continued work to 19 further delineate the Alpine reservoir and we didn't do any 20 additional drilling on the Nanuq development, the Nanuq 21 discovery until 1999. After that we actually raised internal 22 documents to begin delineating the Nanuq development in earnest 23 in 2001 and that's when we put together a larger delineation 24 program and drilled a couple of wells in the 2000/2001 time 25 frame and then drilled a couple more wells between 2201/2002. R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 13 . . 1 During 2003 and 2004 we actually had an EIS for the entire 2 development proposed for CD3 Fiord, CD4 Nanuq, as well as other 3 developments towards the west and we completed that at the end 4 of 2004 and sanctioned the Nanuq development at the end of 5 2004. We are currently expecting to see start up of this 6 development with first oil in November 2006. 7 Slide 10 is a quick overview of what the development is 8 going to be comprised of. We're looking at developing two 9 different reservoirs off the Nanuq CD4. The first one is the 10 Nanuq reservoir which you'll hear more details of later. And 11 the second one if the Nanuq-Kuparuk which is a Kuparuk interval 12 which is underlaying the Nanuq interval. 13 Overall we have 19 wells planned for this development, 14 three within the Kuparuk and 16 within the Nanuq development 15 res- -- development plan. All these wells will be horizontal 16 and we are planning to have miscible alternating WAG with a 17 waterflood for the recovery mechanism. 18 This drill site is actually tied back to the existing 19 development at CD1 and CD2 with a permanent road and, again, 20 we're located about four miles south of the Alpine pad. 21 There will be more information on the overall facilities 22 with Mr. Walker's discussion, but on slide 11 we show a quick 23 picture of what the drill site looks like. This is pretty much 24 a standard drill site which has been built off the learnings 25 and knowledge of the Kuparuk developments and we've used that R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 14 . . 1 as a basis for standardization as we moved into the Alpine 2 extension areas for CD3 and CD4. 3 Slide 12 shows the current status of where we are today. 4 We've got several pictures shown here, but during our 2005 5 winter construction season we completed two main endeavors. 6 The first one was to lay all the gravel for the CD3 and CD4 7 development and what we have here are several pictures. 8 The top picture which is in the upper right hand side is 9 the gravel mine, the cells that we took the gravel out of from 10 the ASRC pit. The overburden that was used from this pit was 11 actually used and to recover the cell from the CD1 and CD2 12 development so that's -- the overburden has been placed here 13 and this has been sculpted to create some lakes and islands for 14 bird habitat. The gravel was placed at the CD3 and CD4. 15 And down the lower left hand side is a picture of the CD4 16 drill site and access road as it moves off to the left hand 17 side of the picture. 18 The second main thing that we completed this year was to 19 install all the VSMs and piles on the drill site to allow 20 ourselves to come in this next winter season and place all the 21 facilities and infrastructure on the drill site. 22 As I mentioned earlier we are planning a development with 23 both CD3 and CD4 simultaneously. We are planning to use a 24 single rig for completing those developments so the CD4 25 development will be occurring effectively during the summertime R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 15 . . 1 or non-ice road access times of the year. It will be connected 2 up to the CDl and CD2 drill site such that the road and support 3 can be provided from CDl and CD2 as well as air support. And 4 then in the wintertimes in '05, '06, '07 and '08 we'll be up 5 actually on the Fiord CD4 drill site which is a winter only 6 access. 7 Again, we're planning first oil for both the CD3 and CD4 8 developments to be in the November 2006 time frame. 9 Now, our top priority with this development is to protect 10 the health, safety and human resources of all people involved 11 as well as the environment as we continue to exploit (ph) and 12 extract the resources within the Alpine area. 13 You know, these proposed pool rules will prevent the waste 14 and promote the -- you know, conservation and they will also 15 allow the protection of the correlative rights and promote 16 maximum, ultimate recovery from these developments. 17 You know, that is the end of my testimony and steve 18 Moothart will actually continue on unless there's some 19 questions on the information as presented to now. 20 CHAIR NORMAN: Okay, thank you, very much for that 21 testimony. Let me see just for a moment if there are any 22 questions before we move to the next witness. Commission 23 Seamount? 24 COMMISSIONER SEAMOUNT: I just have one question, sir. A 25 philosophical question, that's why is consistency between the R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 16 . . 1 -- and rules between the pools so important if there are 2 differences in the characteristics and the conditions? I mean, 3 are these pools so similar that the consistency is important? 4 MR. WIESS: Within the Nanuq and the Nanuq-Kuparuk, you 5 know, the reservoirs are different, but they're all being 6 developed from a single drill site. We do have single 7 operations within the entire Colville River area and to have 8 differential rules, you know, guiding us for development of one 9 reservoir versus the other would, you know, create some 10 administrative issues, as well as potentially could cause us to 11 do things that would not appropriately conserve the resources. 12 COMMISSIONER SEAMOUNT: Okay, thank you. 13 COMMISSIONER FOERSTER: I only have one question and it's 14 for curiosity nature (ph). What's the total area of the drill 15 site? 16 MR. WIESS: The acreage? 17 COMMISSIONER FOERSTER: Yeah. 18 MR. WIESS: I don't -- the gravel footprint, I don't 19 recall that. 20 UNIDENTIFIED VOICE: It's less than 10 acres (ph). 21 COMMISSIONER FOERSTER: Thank you. 22 COURT REPORTER: I didn't hear that, Mr. Wiess. 23 MR. WIESS: The answer was less than 10 acres. 24 COURT REPORTER: Thank you. 25 CHAIR NORMAN: Very good. We can proceed to the next R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 17 . . 1 witness. And I ask you to go ahead and get comfortable there 2 and make sure you have the microphone. 3 MR. MOOTHART: Yup. 4 CHAIR NORMAN: If you'll raise your right hand, please? 5 (Oath Administered) 6 MR. MOOTHART: Yes, I do. 7 CHAIR NORMAN: And could you, please begin by stating your 8 name, who you represent and if you are offering any technical 9 or expert testimony, than your credentials? 10 TESTIMONY BY STEVE MOOTHART 11 MR. MOOTHART: My name is steve Moothart. I'm currently a 12 senior geologist with ConocoPhillips working the Alpine field 13 and Alpine satellite field development. 14 I will be providing technical information, so I graduated 15 from Oregon state University with a BS in 1986, returned and 16 received a Masters from there in 1992. Upon graduation I went 17 to work for ARCO Alaska up here and since that time I've been 18 working primarily the development of Alaska North Slope fields 19 since then including Kuparuk, Tabasco, Tarn, Meltwater and now 20 for the last three years the horizontal well development at 21 Alpine oil field. 22 CHAIR NORMAN: Let me pause there for a moment and see if 23 there are any questions concerning your credentials. 24 Commissioner Seamount? 25 COMMISSIONER SEAMOUNT: I have no questions. R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 18 . . 1 CHAIR NORMAN: Commissioner..... 2 COMMISSIONER FOERSTER: No, I don't (ph). 3 CHAIR NORMAN: Good. We will accept your credentials as 4 an expert witness. 5 MR. MOOTHART: Thank you. 6 CHAIR NORMAN: Please proceed. MR. MOOTHART: As Jordan mentioned I will be talking today 7 8 about the geology of the development of the Colville River 9 field and the reservoirs. Primarily I'll be talking 10 addressing the first two pool rules, rules 1 and 2, concerning 11 field name and then definition of the oil pools within the 12 field for development. 13 The first slide is just a slide showing the proposed field 14 name for this development as Colville River field. Within this 15 development in this field we've identified two oil pools. The 16 first one to talk about is the Nanuq oil pool and then 17 stratigraphically deeper is the Nanuq-Kuparuk oil pool. 18 Next slide. This slide is a stratigraphic column of oil 19 fields, with oil fields from the Alaskan North Slope plotted on 20 it. I put this up just to -- as a reference to show where the 21 oil pools within the proposed Colville River field lie 22 stratigraphically in relation to other developed fields. The Nanuq oil pool is Cretaceous in age and it's correlative to the Tarn and Meltwater fields. 23 24 25 Stratigraphically deeper is the Nanuq-Kuparuk oil pool and R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 19 . . 1 this is equivalent to -- its early Cretaceous in age and it's 2 equivalent to the Kuparuk C sand that's developed over to the 3 west in the Kuparuk River field. 4 vertical definitions of the oil pools. The Nanuq oil pool 5 is the accumulation of oil and gas common to and correlating to 6 the interval found in the Nanuk number 2 well, which I'll show 7 very shortly here, between the depths of 7,043 feet and 7,223 8 feet measured depth. 9 stratigraphically deeper the Nanuq-Kuparuk oil pool is the 10 accumulation of oil and gas common to and corresponding to the 11 interval found in, again, the Nanuk number 2 well between the 12 depths of 7,956 feet and 7,972 feet measured depth. 13 This is a log from the Nanuk number 2 well. This is the 14 type log for this -- both these oil pools. I'll talk about 15 Nanuq first and then I'll move down to the deeper Kuparuk -- 16 Nanuq-Kuparuk interval. 17 Again, on the right side of the slide you see the depths 18 which define the top and base of the interval. On the log 19 itself on the left hand track is gamma ray and resistivity. 20 You'll notice common in this interval the interbedded sand and 21 shale nature of the reservoir. We'll be talking about that a 22 little bit in more depth later. 23 Should note on that last slide that the Nanuq-Kuparuk 24 interval, that stratigraphically deeper interval, is about 700 25 feet TVD below this, the Nanuq interval. R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 20 . . 1 This is top -- a map of the top Nanuq structural depth. 2 This is created both from well control data from wells in the 3 area as well as seismic data. Overlaying on this map is the 4 proposed Nanuq participating area boundary and then also the 5 as Jordan mentioned earlier, the 16 planned development wells 6 for this interval. 7 I want to also note the four existing wells, exploration 8 and delineation wells within the PA area, Nanuk 2 is this well 9 here which is again the type well for both of the intervals. 10 Also note to the north the abundant well control to 11 delineate both structure and reservoir in the Alpine reservoir 12 to north of us. 13 CHAIR NORMAN: And just to keep the record synchronized 14 with your testimony, you're referring now to slide 19, the 15 diagram there and the north part of that slide? 16 MR. MOOTHART: Yes, I am. 17 CHAIR NORMAN: I believe that's correct, yeah. 18 MR. MOOTHART: Again, this next slide is the Nanuk, a 19 portion of the Nanuk number 2 well log depicting the Nanuq- 20 Kuparuk oil pool. On the right the structural depths or the 21 measured depths which define the top and the base of the 22 interval. 23 I mentioned earlier this interval is equivalent to the 24 Kuparuk C interval as developed to the west. This is a thin 25 sand here. Only about five to 15 feet thick, thin, R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 21 . . 1 transgressive sand that is the base of the interval that is 2 deposited upon the lower Cretaceous unconformity which, again, 3 defines the base of this interval. 4 Next I will show a map on that lower Cretaceous 5 unconformity. Because the Kuparuk interval is so thin it's 6 very difficult -- it's below our seismic resolution so 7 structurally the best interval to map defining that reservoir 8 is the basil structure on that LCU erosional surface. 9 As before this LCU structure map I've overlaid the 10 proposed Nanuq-Kuparuk PA boundary and then also the planned 11 three horizontal wells planned to develop this interval. Just 12 for general reference structurally shallower depth structure is 13 the cool colors in the blue and the purple and, kind of, in the 14 upper right hand portion of the slide and then structurally we 15 deepen more to the southwest to the lower left. 16 That concludes my public testimony for the definition of 17 the two oil pools -- proposed oil pools. At this time, as 18 Jordan mentioned, I would like to ask that we go into private 19 session to discuss more confidential matters. 20 CHAIR NORMAN: Yes, thank you, Mr. Moothart. Could you 21 briefly summarize the nature of the confidential information? 22 What I'd like, without getting into any of the details, of 23 course, but just a statement so that if there are any persons 24 present who -- at least they will understand what it is -- the 25 proprietary basis or what it is that you're attempting to R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 22 . . 1 protect and also if there are any persons that object to it, 2 then the Commission would hear from them. 3 MR. MOOTHART: All right, thank you. What I will show 4 during this set -- private session are both interpretations and 5 seismic data which is proprietary to conocoPhillips. 6 Discussion will -- from that data we'll be discussing those 7 interpretations, more in depth interpretations and depositional 8 settings of the intervals and will be used to, kind of, clarify 9 more on aerial extent and that's it. 10 CHAIR NORMAN: Very good. Commissioner Seamount, do you 11 have any questions on the confidentiality issue? COMMISSIONER SEAMOUNT: I have none, Mr. Chairman. COMMISSIONER FOERSTER: Nor do 1. 12 13 14 CHAIR NORMAN: commissioner Foerster. Okay. The Chair is 15 satisfied that this is interpretive information and accordingly 16 we will..... 17 COMMISSIONER SEAMOUNT: Mr. Chairman..... 18 CHAIR NORMAN: Yes, Ma'am, do you want to . . . . . 19 MS. OLSON: Yes, I have a..... 20 CHAIR NORMAN: .....do you want to come forward and state 21 your name? 22 MS. OLSON: My name is Dana Olson. I'm a member of the 23 public. I feel that the so far the information I have 24 received is not adequate for my understanding. I'm sorry, I'm 25 not an oil industry expert, but I don't feel in the R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 23 . . 1 presentation that I've had so far that there's been adequate 2 presentation on conservation or waste and I don't know how that 3 relates to the confidentiality 'cause those are the issues that 4 I am interested in. 5 CHAIR NORMAN: All right, thank you, Ms. Olson. I 6 understand what you're saying. What I would suggest is that as 7 I understand it there are a number of other witnesses who will 8 be testifying and most of their testimony will be public 9 information and so I would anticipate that many of your 10 questions may be answered in the course of that, but if..... 11 MS. OLSON: May I ask..... 12 CHAIR NORMAN: .....they're not then..... 13 MS. OLSON: May I ask one other..... 14 CHAIR NORMAN: .....we'll certainly hear from you (ph). 15 MS. OLSON: .....question, please? 16 CHAIR NORMAN: Certainly. 17 MS. OLSON: This is something that I've wanted to ask, 18 that's why I went and got paper. I'm not sure how the EIS 19 relates to consistency because an EIS doesn't use consistency 20 necessarily and so that's a question I have and I would hope 21 that that would be answered. 22 CHAIR NORMAN: All right, thank you. 23 MS. OLSON: Thank you. 24 CHAIR NORMAN: Okay. At this point the Commission is 25 going to receive testimony of a confidential nature which R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 24 . . 1 involves proprietary, interpretive information by the applicant 2 and so I'll ask the applicant to indicate persons and designate 3 those you wish to remain in the room. And then we will ask all 4 others -- I will ask the Commission staff also to remain with 5 the understanding it will be receiving this in confidentiality. 6 Can you indicate who you would like to remain? 7 MR. MOOTHART: All ConocoPhillips in place. 8 CHAIR NORMAN: Is it necessary for them all to be here? 9 MR. MOOTHART: It's not necessary for any of them to 10 leave. They're opened to this information. 11 CHAIR NORMAN: All right. Okay. 12 MR. MOOTHART: So -- but all others I would ask that they 13 leave. 14 UNIDENTIFIED VOICE: DNR..... 15 (Simultaneous speech) ..... 16 MR. MOOTHART: Oh, DNR, the State (simultaneous 17 speech) ..... 18 MS. OLSON: I would object. 19 CHAIR NORMAN: I think your basis for saying DNR is that 20 DNR is the lessor ..... 21 UNIDENTIFIED VOICE: Bound by confidentiality..... 22 CHAIR NORMAN: .....yes, um-hum, all right. 23 UNIDENTIFIED VOICE: .....underneath their agreement (ph). 24 CHAIR NORMAN: Okay. 25 MR. MOOTHART: Yes. R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 25 . . 1 CHAIR NORMAN: All right. Okay. The -- because that -- 2 DNR is the landowner this information..... 3 MR. MOOTHART: Right. 4 CHAIR NORMAN: .....is available to DNR anyway. Your 5 point is they can remain, okay. I want to avoid selectively 6 excluding people and so that's why I think..... 7 MR. MOOTHART: Right. 8 CHAIR NORMAN: .....if you can indicate those that have 9 the need to be here during this confidential presentation for 10 continuity and to keep the presentation moving that would be 11 best and any others we'll ask to leave the room. 12 MR. MOOTHART: Do you want me to -- I mean, physically 13 point -- point out those? 14 CHAIR NORMAN: If you would, yes, um-hum, since we're 15 doing that, yes. 16 MR. MOOTHART: You, just..... 17 MS. OLSON: Right, but I would like the Commission to 18 address why DNR is separate from the people of the state (ph)? 19 COURT REPORTER: I can't really record what you're saying. 20 (Side conversation commissioner Foerster to Chair Norman) 21 COURT REPORTER: Yes, ma'am. DNR is the landowner and the 22 lessor. And by virtue of the terms of the leases and 23 development plans they are entitled to receive certain 24 information so they have a definite ownership interest that is 25 separate and distinct from anyone else. R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 26 . . 1 On lands now that presumably that DNR does not own, if 2 there are any, for example, ASRC lands, then that relationship 3 doesn't exist, but DNR has a definite proprietary ownership 4 interest in these lands that's why we will allow DNR to remain. 5 MS. OLSON: I'd like to respond to that. Under the Alaska 6 Lands Interest Act..... 7 COURT REPORTER: I need by a mic. 8 CHAIR NORMAN: Ms. Olson, could you come forward again, 9 please. 10 COURT REPORTER: Thank you. 11 MS. OLSON: I'd like to respond to the issue about DNR 12 being allowed to participate and the public being excluded. 13 The Alaska Lands Interest Act transferred the role to the 14 Commission, Administrative Order 42. 15 To go in and say that the public would be excluded both by 16 DNR and its process under the Alaska Lands Interest Act and 17 then also to be excluded by the Commission would be -- would 18 violate under the Constitution other safeguards prescribed by 19 law because you're excluding the public from both process. And 20 virtually there is no public process if they're being excluded 21 by both the lands -- both the Alaska Lands Interest Act and the 22 oil and Gas Commission. 23 CHAIR NORMAN: Okay, thank you. Your objected is noted. 24 MS. OLSON: Thank you. 25 CHAIR NORMAN: We do intend to make a maximum effort to R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 27 . . 1 have as much information as possible made public and we intend 2 to hold to a minimum the amount of information we receive 3 without it. 4 MS. OLSON: One other question, will I be writing my 5 questions -- you mentioned something about writing questions 6 and presenting them to you? 7 CHAIR NORMAN: Yes, ma'am. 8 MS. OLSON: So out there I can write them, correct? 9 CHAIR NORMAN: Yes, ma'am, you certainly can. 10 MS. OLSON: Thank you. 11 CHAIR NORMAN: Okay. Now, would you, please, Mr. 12 Moothart, take a careful look around the room and make sure 13 you're satisfied and then we will proceed with testimony. 14 MR. MOOTHART: Yeah, I have to apologize, I inadvertently 15 pointed to John Goltz (ph), our attorney, to have him excluded 16 and I have -- I haven't had occasion to be introduced to him 17 prior so I wasn't aware that he was our attorney, so I would 18 ask..... 19 CHAIR NORMAN: I understand. 20 MR. MOOTHART: .....that he be allowed to stay. 21 COMMISSIONER FOERSTER: Excluding attorneys is probably a 22 generally good practice, wouldn't you say? 23 MR. MOOTHART: Yes. And other than that I'm satisfied 24 that..... 25 CHAIR NORMAN: All right. R & Reo U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 28 . . 1 MR. MOOTHART: .....all parties here are..... 2 CHAIR NORMAN: All right. Please proceed now and the 3 Commission is proceeding to receive a briefing of confidential 4 information of a proprietary nature. 5 (Confidential Excerpt starts Page 29 Line 5 6 through Page 40 Line 9 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 29 . . 1 2 3 4 5 6 7 8 9 10 CHAIR NORMAN: Commissioner Seamount. 11 COMMISSIONER SEAMOUNT: Thank you, Mr. Moothart for a very 12 complete and informative presentation. I guess I have a 13 question to all of you, is there going to be any more 14 confidential presentation? 15 MR. MOOTHART: No, there isn't. 16 COMMISSIONER SEAMOUNT: That's all I have. 17 CHAIR NORMAN: Commissioner Foerster. 18 COMMISSIONER FOERSTER: I do have one question going back 19 to the Nanuq reservoir. Do you expect aerial continuity of the 20 four lobes across the development area? 21 MR. MOOTHART: Of the individual lobes? 22 COMMISSIONER FOERSTER: Yes. 23 MR. MOOTHART: Yes, we do basin floor fans tend to be 24 quite aerial and can be extensive. 25 COMMISSIONER FOERSTER: Thank you. R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 40 . . 1 CHAIR NORMAN: Mr. Moothart, the confidential testimony 2 began with slide number 23 and you have finished with slide 3 number 32 (sic), is that correct? 4 MR. MOOTHART: Yes, it is. 5 CHAIR NORMAN: Okay. I think..... 6 MR. MOOTHART: No,..... 7 MR. WIESS: No. 8 MR. MOOTHART: Sorry. 9 CHAIR NORMAN: .....right now we've been at..... 10 COMMISSIONER FOERSTER: 35. 11 CHAIR NORMAN: 35, is it? 12 MR. WIESS: Yes. 13 MR. MOOTHART: 35. 14 CHAIR NORMAN: 35, yes, thank you, Commissioner. 15 MR. MOOTHART: Sorry. 16 CHAIR NORMAN: We've been at this for about an hour and 10 17 minutes so I think it might be an appropriate time to take a 18 break. When we reconvene -- we'll take about a 10 minute break 19 and then come back on the record. 20 I would like you to give, again, in the public hearing a 21 quick, brief description of each slide, not the content of 22 them, but simply state that slide 23 depicted this, et cetera, 23 so that we do have spread on the public record what we have 24 just been through here. 25 We'll take a recess and reconvene in 10 minutes. R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 41 . . 1 (Off record - 10:15 a.m.) (On record - 10:25 a.m.) 2 3 CHAIR NORMAN: We're back on the record after a recess of 4 approximately 10 minutes. The time is 10:25 a.m and we will 5 continue with the hearing. We have been in a Confidential 6 Session to receive certain proprietary information based on 7 interpretations of that proprietary information some graphics. 8 In order to complete the record, however, Mr. Moothart, I 9 would like to ask you if you would begin with the first slide 10 and go all the way through the last slide and give a brief 11 summary of what was covered in the confidential session so that 12 the record will reflect that and also members of the public who 13 were not here can at least have some general understanding of 14 what was presented. 15 MR. MOOTHART: Within the Confidential Session that we 16 just had the first slide that I showed was an interpretative 17 interpreted slide of the interpreted log, type log, for the 18 Nanuq interval. 19 CHAIR NORMAN: That would have been -- that's starting 20 with slide 23? 21 MR. MOOTHART: That's starting with slide 23, correct. 22 CHAIR NORMAN: Okay. And then if you'd just proceed and 23 give a..... 24 MR. MOOTHART: Okay. 25 CHAIR NORMAN: .....brief summary of each. R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 42 . . 1 MR. MOOTHART: Slide 24 was petrographic -- discussed 2 petrographic characteristics of the Nanuq interval. Slide 25 3 was showing time, seismic time structure maps of the Nanuq 4 interval. Slide 26 was a seismic cross section through the 5 showing the Nanuq and the Kuparuk interval over the area. 6 Slide 27 was a seismic amplitude map of the Nanuq 7 interval. Slide 28 was an interpreted Nanuq net pay map. 8 Slide 29 was a porosity versus permeability cross plot from 9 core data within the Nanuq interval. 10 Slide 30 was a title slide leading into the discussion of 11 the Kuparuk interval. Slide 31 was interpreted well log within 12 the Kuparuk interval and petrographic characteristics of the 13 Kuparuk interval. Slide 32 discussed depositional model of the 14 Kuparuk interval in this area. Slide 33 was an interpreted 15 Kuparuk net pay map in this area. Slide 34 were interpreted 16 well logs from preexisting wells within this area. And slide 17 35 was permeability versus porosity cross plot for the Kuparuk 18 interval in this general area. 19 CHAIR NORMAN: Okay. Thank you very much. And it is 20 correct to say that all of these slides were subsurface -- just 21 a moment, ma'am, I'll recognize you. 22 These were all subsurface pictures of the intervals that 23 of these reservoirs that -- they contain the reservoirs? 24 MR. MOOTHART: Yeah, yes, it is, this -- it is all..... 25 CHAIR NORMAN: None of this presentation pertain to the R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 43 . . 1 surface? 2 MR. MOOTHART: No, it was all discussion of the subsurface 3 geology. 4 CHAIR NORMAN: Okay. And the interval -- the subsurface 5 interval in the Nanuq is 7,043 to 7,223 roughly and the Kuparuk 6 7,956 to 7,972 again, so..... 7 MR. MOOTHART: Yes, it is. 8 CHAIR NORMAN: .....these were -- your interpretations, 9 your attempts to construct a picture of what's deep beneath the 10 earth? 11 MR. MOOTHART: Yes. 12 CHAIR NORMAN: All right. Yes, ma'am, I'll recognize you, 13 but I don't -- we do want to try and stay in order and so you 14 will have an opportunity to testify later on. If you have 15 something specifically on this point I will recognize you now? 16 MS. OLSON: Yes, I do. 17 CHAIR NORMAN: All right. Come forward, please. 18 MS. OLSON: My name is Dana Olson and I have two 19 objections. One is the permeability map. I'm not sure what 20 slide that was. Based on the fact that there is already 21 documented permeability maps by the Federal Government and so 22 that wouldn't be privileged. 23 And two, where there has not been any disclosure of the 24 consistency I would have to object to the use of evidence 25 between -- of consistency between the different well logs. R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 44 . . 1 CHAIR NORMAN: All right, thank you. 2 MS. OLSON: Thank you. 3 CHAIR NORMAN: Your objections are noted. 4 We're ready to proceed then. 5 MR. MOOTHART: All right. Next I'll hand it over to Jim 6 Bennett. 7 (Off record discussion on microphones) 8 CHAIR NORMAN: And, again, a reminder to all of us that a 9 record is being created and to the extent that we can help the 10 Court Reporter if there are any unusual terms it is always 11 helpful to her if you could spell them, not necessarily the 12 geologic or engineering terms, but names, anything like that, 13 otherwise she's got quite a challenge to be able to reconstruct 14 this. 15 Also keep in mind that when you are referring to slides if 16 you say this or that it doesn't mean anything to someone 17 reading a transcript years later, so what we try to do is tie 18 it to the slides that will be attached, so if you can look at 19 the numbers in the lower right hand corner. 20 MR. BENNETT: Sure. 21 CHAIR NORMAN: I'll now being by asking you to raise your 22 right hand, please? 23 (Oath Administered) 24 MR. BENNETT: I do. 25 CHAIR NORMAN: will you state your name and who you're R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 45 . . 1 representing? 2 TESTIMONY BY JIM BENNETT 3 MR. BENNETT: I'm Jim Bennett and I'm representing 4 ConocoPhillips. 5 CHAIR NORMAN: And are you appearing here today as an 6 expert witness? 7 MR. BENNETT: Yes. 8 CHAIR NORMAN: All right. Then will you, please, state 9 your educational background and experience? 10 MR. BENNETT: Okay. I've got a Bachelor of Science Degree 11 in Petroleum Engineering from the University of Oklahoma in 12 1996 and begin working for conocoPhillips immediately 13 thereafter. And worked the first four years in Houston, 14 Oklahoma, West Texas fields and the last five years have been 15 in Alaska working North Slope fields. 16 CHAIR NORMAN: And what has been the main focus of your 17 work in Alaska in the North Slope fields, where..... 18 MR. BENNETT: Reservoir engineering on Prudhoe Bay and 19 Alpine fields. 20 CHAIR NORMAN: Prudhoe Bay and Alpine? 21 MR. BENNETT: yes..... 22 CHAIR NORMAN: And as between Prudhoe Bay and Alpine, how 23 much time with Alpine? 24 MR. BENNETT: A year and a half. 25 CHAIR NORMAN: Okay. Commissioner Seamount? R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 46 . . 1 COMMISSIONER SEAMOUNT: No questions. COMMISSIONER FOERSTER: No questions. CHAIR NORMAN: Okay. We accept you as being qualified as an expert witness. MR. BENNETT: Okay. CHAIR NORMAN: You may proceed. MR. BENNETT: Thank you. I'll be going over some of the 2 3 4 5 6 7 8 reservoir engineering aspects of the Nanuq pool rules project. 9 The first slide, it's slide number 37, I'm showing you a 10 so called CD4 spider diagram. It shows you the location of the 11 CD4 development with respect to the CDl and 2 pads that are 12 already in place at Alpine. 13 The legend there you can see the planned well service for 14 each of the wells, whether it's going to be an injector or 15 producer. If you look in the center part of the diagram you 16 can see the Kuparuk development wells. Underneath the -- those 17 Nanuq wells running a little bit different angle there. 18 A key piece of the development, as we've mentioned several 19 times already in the presentation, is the Nanuk number 2 well. 20 It's an exploration well. It's a vertical completion, 21 completed in the Nanuq west fan. It's completed both in the 22 Nanuq and the Kuparuk C intervals. 23 We have core data available. We've conducted special core 24 analysis. We've done fluid samples. PVT analysis and this 25 well was fracture stimulated. We've done a pressure transit R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 47 . . 1 analysis on this well and we've got a, you know, five day 2 production test from this well. You can see there it made 3 1,700 barrels a day and a considerable amount of water and 1.2 4 million cubic feet a day on average. 5 Here are general reservoir properties for both the Nanuq 6 and the Nanuq-Kuparuk intervals. And I'll point out that I 7 have brackets around some of the data here and that identifies 8 the fact that these are estimated values. All the other values 9 are measured. 10 Some of the key points here jump down and contrast the 11 permeability. This -- what I'm showing here on this slide is 12 effective oil permeability as opposed to some of the data 13 that's been presented already is air permeability, okay, so 14 these numbers will be a little bit lower than had been shown in 15 some of the earlier testimony. 16 And highlight the fact that the Nanuq interval is about 17 2.5 millidarcy on average, whereas the Kuparuk is about 100 18 millidarcies, so quite a contrast on that piece. 19 And also I'll point out the fact that the considerable 20 difference in initial reservoir pressure, the Nanuq being 2,740 21 pounds and the Kuparuk being 3,240 pounds. 22 COMMISSIONER SEAMOUNT: Mr. Bennett, does none mean you 23 don't have the information? 24 MR. BENNETT: None means that we have no -- we have no 25 evidence of a gas/oil contact or a water/oil contact. We've R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 48 . . 1 not identified any. 2 All right. Slide number 40 here is entitled Injection 3 Fluid Miscibility. This is a depiction showing it's a 4 simulated slimtube, experimental results and it's based on the 5 2006 Alpine composition and the Nanuk 2 oil composition. And 6 the basis for this plot is that we filed an Area Injection 7 Order and assuming we get an approval for this, this will be a 8 miscible WAG process and one requirement of that is that we 9 have both a miscible injectant and a fluid in place that's 10 capable of being miscible with that solvent. 11 And this plot should -- identifying, you know, based on 12 recovery at 1.24 volumes injected of a slimtube experiment as a 13 function of pressure. You can see that the fluid we plan to 14 use at Nanuq is miscible at pressures greater than 2,400 pounds 15 psi and so that initial pressure is lower than in initial 16 pressure of the reservoir in both cases and we plan to maintain 17 voidage in both of these reservoirs. 18 Okay. Slide number 41 is a description of the reservoir 19 models for each of the reservoirs. We've constructed fully 20 compositional 3D models for both. They have eight component 21 equations of state based on the fluid analysis we've done. The 22 wells description there, basically you have over 6,000 foot 23 horizontal, undulating wells in both reservoirs and 16 wells in 24 Nanuq and three wells in the Kuparuk reservoir. 25 One, kind of, interesting point here is the spacing R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 49 . . 1 difference here based on the contrast and permeability of the 2 two reservoirs. You an see the Nanuq is 1,500 foot interwell 3 spacing, whereas the Kuparuk has 6,000 foot interwell spacing. 4 And then the slug sizes of the WAG processes that we plan to 5 implement, you know, some of the details around that. 6 All of this -- we use these models to optimize the 7 development and, you know, determine how we're going to carry 8 out this. 9 Slide number 42 shows the range of rate and reserves for 10 each of the reservoirs. I'll highlight some of the key points 11 here. The range of oil in place for Nanuq is 84 to 169 million 12 barrels in place and for Kuparuk is 21 to 36 million barrels in 13 place. 14 The total recovery factor and that's based on some of the 15 primary and waterflood and then enhanced recovery mechanisms is 16 26 to 41 percent for the Nanuq and then 54 to 79 percent for 17 the Kuparuk. And then finally the combined total for, you 18 know, summing both reservoirs is 33 to 98 million barrels 19 recoverable and then the peak rate we expect to get out of 20 these reservoirs is 10 to 15,000 barrels a day. 21 Finally I have some selected rules that pertain directly 22 to my part of the project is as far as the well spacing, rule 23 number 3 shown here on slide 43, as we mentioned earlier the 24 wells, you know, will not be completed closer than 500 feet to 25 an external boundary where working interest ownership changes. R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 50 . . 1 Going to rule number 6 with regard to reservoir pressure 2 monitoring and by the way, all three of these rules are 3 intended to be nearly identical to the rules that are in place 4 for Alpine. And so, you know, an initial pressure survey will 5 be taken in each injection well and then a minimum of two 6 bottomhole surveys annually for Nanuq oil pool and then finally 7 for the Nanuq-Kuparuk oil pool we'll have one bottomhole 8 pressure survey. 9 And these are based on, you know, scaling from the Alpine, 10 you know, the number of wells and tests that we have in the 11 Alpine field. And you scale it down for the number of wells we 12 have at Nanuq and then at Kuparuk and you arrive at these 13 numbers. And then the pressure datum for Nanuq and then at 14 Kuparuk are 6,150 and 7,000 respectively. 15 And then I'll jump on down to the GOR exemption. We asked 16 for an exemption from the GOR limits just like at Alpine. This 17 is a miscible WAG process and we'll be able to control the GOR 18 through injection so we ask that that be exempted. 19 And that's all the slides I plan to show at this point. 20 CHAIR NORMAN: Okay, thank you, Mr. Bennett. A short 21 follow up to a question Commissioner Seamount asked, but the 22 patterning of these proposed rules after Alpine is primarily 23 for convenience of the operator, consistency as opposed..... 24 MR. BENNETT: That's correct. 25 CHAIR NORMAN: .....to seeing similar reservoir R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 51 . . 1 characteristics? 2 MR. BENNETT: Correct. Yeah, it's more of an 3 administration ease, urn-hum. 4 CHAIR NORMAN: Commissioner Seamount, questions? 5 COMMISSIONER SEAMOUNT: I have no questions, thank you. 6 CHAIR NORMAN: Commissioner Foerster. 7 COMMISSIONER FOERSTER: No. 8 CHAIR NORMAN: Thank you for your testimony, Mr. Bennett. 9 MR. BENNETT: Okay, thank you. I'll now turn..... 10 CHAIR NORMAN: If all of -- just one moment, ma'am. If 11 all of the witnesses would remain, we'll move along as quickly 12 as we can. It might be that we would want to recall a witness 13 to clarify something so I would appreciate it if you'd remain. 14 And, also, we'd appreciate if you'd keep in mind that if you 15 are recalled you will remain under Oath. We won't readminister 16 the Oath. 17 MR. BENNETT: Okay. 18 CHAIR NORMAN: Thank you. 19 MS. OLSON: I would like to ask some questions on that 20 (simultaneous speech) ..... 21 CHAIR NORMAN: Of this witness? 22 MS. OLSON: Yes. 23 CHAIR NORMAN: Of this particular witness? 24 MS. OLSON: Yes. 25 CHAIR NORMAN: Why don't you -- I do have a series of R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 52 . . 1 questions..... 2 MS. OLSON: That's not -- I didn't have that knowledge so 3 I didn't put it on there (ph). 4 CHAIR NORMAN: Sure. Well, let me suggest..... 5 MS. OLSON: There's (ph) just two brief questions. 6 CHAIR NORMAN: I'm sorry. 7 MS. OLSON: They are real brief. 8 CHAIR NORMAN: They're brief? 9 MS. OLSON: Yes. 10 CHAIR NORMAN: All right. I'm going to hold you to the 11 briefness then. You may come forward. How many questions do 12 you have? 13 MS. OLSON: Two. 14 CHAIR NORMAN: Two. All right. Come forward and you may 15 ask the questions. 16 MS. OLSON: For the record my name is Dana Olson. I 17 wanted to ask what the fracture fluid was because in coal bed 18 methane we learned how that can effect water quality and so I wanted to know because there's different pressure and you stated earlier -- your company stated earlier that fracture was 19 20 21 used. . . . . 22 MR. BENNETT: Dm-hum. (Affirmative) 23 MS. OLSON: .....1 wanted to know what the fracture fluid 24 was and..... 25 CHAIR NORMAN: Let's just have -- let's let the witness R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 53 . . 1 then answer and then..... 2 MS. OLSON: Okay. 3 CHAIR NORMAN: .....you go to the next question. CHAIR NORMAN: So the question is in the course of 4 5 development the question to the operator if you know now, what 6 type of a fracturing fluid was used? 7 MR. BENNETT: It was water, treated water. 8 CHAIR NORMAN: Okay. 9 MR. BENNETT: In the Nanuk 2, that's the well you're 10 referring to I assume, that's the only well that we frac'd (ph) 11 at Nanuq. 12 CHAIR NORMAN: Okay. 13 COMMISSIONER FOERSTER: I think the concern in coal bed 14 methane was diesel and diesel is not used as a carrier fluid in 15 the fracs. 16 MR. BENNETT: No, it was not. And furthermore we don't 17 plan to stimulate these wells in the base plan anyway. 18 CHAIR NORMAN: Okay. So your next question now, Ms..... 19 MS. OLSON: The next question is the relevance of 500 feet 20 because when I came and testified on the drilling proposed 21 regulatory thing it said that the common was up to two miles 22 away and so I'm questioning why the 500 feet is relevant? 23 CHAIR NORMAN: Well, the 500 feet would simply relate to 24 spacing between wells and that is on oil wells. And so I..... 25 MS. OLSON: Well, as far as the cons is- -- I guess we're R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 54 . . 1 addressing consistency and so that's -- my question is if we're 2 addressing consistency how is that consistent with two miles? 3 COMMISSIONER FOERSTER: Ms. Olson,..... 4 MS. OLSON: Yes. 5 COMMISSIONER FOERSTER: .....the reason that there is a 6 spacing rule and our spacing exceptions is because every 7 reservoir has its own producing characteristics and this is an 8 instance where consistency is not relevant. You have to look 9 at the reservoir characteristics to determine an appropriate 10 spacing so that you do not create waste so that you maximize 11 recovery. 12 MS. OLSON: I believe I'd like to object to what you just 13 said because they have provided testimony that consistency 14 between drilling well logs. 15 CHAIR NORMAN: Okay. Your objection is noted..... 16 MS. OLSON: Thank you. 17 CHAIR NORMAN: .....and the 500 feet and the set back from 18 property lines is consistent with what the Commission generally 19 requires, Ms. Olson. And you'll have an opportunity later on 20 now if you wish to once the applicant is finished. 21 Okay. We're ready to proceed. 22 MR. BENNETT: If no other questions I'll introduce Steve 23 Moothart again. 24 TESTIMONY CONTINUED BY MR. MOOTHART 25 MR. MOOTHART: I'm going to at this point show three R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 55 . . 1 slides concerning shal- -- the shallower geologic intervals in 2 the area and as they pertain to annular disposal of cuttings, 3 drill cuttings. 4 The first slide, this is the Bergschund number 1 well log. 5 It's the type well log from the Alpine field. Slide number 53 6 (sic). And at Alpine we currently, and have throughout the 7 development, disposed of our drill cuttings within the annular 8 of existing development wells. And typically that annular 9 disposal takes place below our surface casing. Surface casing 10 is typically set at about 2,350 feet subsea. 11 The annular disposal interval is into a series of 12 interbedded sandstones and shales of the Upper Cretaceous 13 Seabee and Torok Formation. We've got about 1,800 feet of 14 interbedded sandstones and shales. This disposal interval is 15 bounded above by over 1,000 feet of shale and siltstone of the 16 Cretaceous age, Schrader Bluff Formation. And below by over 17 1,000 feet of shale and siltstone of the marine shales and 18 siltstones of the Torok Formation. 19 Next slide. What I wanted to show here and throughout 20 these three slides is the continuity of the stratigraphy, 21 correlateability of the stratigraphy as we expand out from the 22 Alpine field into both the Fiord and Nanuq areas. 23 This cross section, again, shows the annular disposal 24 interval that I showed earlier on the previous section in the 25 Bergschund number 1 well, but here I am showing a cross section R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 56 . . 1 between CD1 and CD2 in the Alpine field, so I've got Bergschund 2 number 1 which is over at the CD1 pad, CDl-22 and the Alpine 1 3 well which is over at the CD2 pad. 4 Again, the annular disposal interval, the upper barrier 5 here of about 1,000 feet of marine mudstones and siltstones and 6 you can see on both those intervals how continuous and 7 correlatable they are across that distance of about three 8 miles. 9 COURT REPORTER: Excuse me, if I could get you to pull 10 those microphones. What happens is your back is, kind of, to 11 the mics so you fade out on me. 12 MR. MOOTHART: Okay. 13 COURT REPORTER: Thanks. 14 MR. MOOTHART: The next slide, this cross section is more 15 north to south and we went from Alpine field in a cross section 16 across Alpine to this north/south field which extends from well 17 up at the Fiord development area, across Alpine and then down 18 through the Nanuq development area. 19 And, again, I'm showing the annular disposal interval 20 about 1,800 feet. And in the well logs you can see how 21 correlatable the interval is even across the distance of about 22 10 miles in the north/south direction and the same goes for the 23 barriers above. These marine mudstones barriers of 1,000 feet 24 or greater than 1,000 feet that we have both above and below us 25 are regionally very widespread and correlatable across the R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 57 . . 1 area. So..... 2 CHAIR NORMAN: If I could ask this, the depth to the top 3 of the disposal interval is roughly what again? 4 MR. MOOTHART: Is about 2,400 feet below sea level or 5 below ground surface. 6 CHAIR NORMAN: And the base of the permafrost in the 7 column is where? 8 MR. MOOTHART: Is about 850 feet below ground level. 9 Brian Noel will be up next and talking about well construction 10 and he'll probably have more to discuss on the annular 11 disposal. That concludes..... 12 MS. OLSON: I have a couple of questions..... 13 MR. MOOTHART: .....my testimony. 14 CHAIR NORMAN: Do you have questions on this particular 15 point, Ms. Olson? 16 MS. OLSON: I do. 17 CHAIR NORMAN: Can you write them out? What I would like 18 to do is allow the witnesses to continue and if you could write 19 them out we will see that they are asked, but what we find is 20 that often the next witness will answer a question that is 21 raised by the one previously. 22 MS. OLSON: Well, the reason I would like to ask it is 23 because you're presuming I'm knowledgeable and I'm not and so 24 I'm gaining knowledge while I'm here and so that's why I'd like 25 to ask the question. R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 58 . . 1 CHAIR NORMAN: You have one question you wish to ask? 2 MS. OLSON: Two. They're briefer than the last even. 3 CHAIR NORMAN: All right. Come forward to the microphone. 4 MS. OLSON: For the record my name is Dana Olson and I 5 wanted to know what was in the drill cuttings because I'm not 6 knowledgeable? 7 MR. MOOTHART: It's the rock that we bring up as we're 8 drilling so it's..... 9 MS. OLSON: And the chemicals with it? 10 MR. MOOTHART: Drilling fluids are water based..... 11 MS. OLSON: Okay. 12 MR. MOOTHART: .....drilling muds. 13 MS. OLSON: All right. And the other thing I wanted to 14 ask what the difference between a shale and siltstone thing was 15 in difference to the mud -- was it mud solids or something? 16 How that -- how they're different? 17 MR. MOOTHART: They're different in the grain grain 18 size. Mudstone is an extremely fine grained..... 19 MS. OLSON: So if there was an..... 20 MR. MOOTHART: .....marine deposit..... 21 MS. OLSON: .....earthquake is there going to make a 22 difference between what would -- might potentially come up? 23 CHAIR NORMAN: In other words,..... 24 MR. MOOTHART: No. 25 CHAIR NORMAN: .....the barrier. If I'm understanding the R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 59 . . 1 the. . . . . 2 MR. MOOTHART: No. No, the -- the mud- --..... 3 CHAIR NORMAN: .....witness wants to know your barrier? 4 MR. MOOTHART: .....the mudstone and siltstone barriers 5 are essentially zero permeability. They're so fine grained 6 that they be- --..... 7 MS. OLSON: No, that's on..... 8 MR. MOOTHART: .....create an imper-..... 9 MS. OLSON: .....permeability. I'm saying on an earth 10 thrust of an earthquake. 11 CHAIR NORMAN: In other words, would the barrier be broken 12 by an earthquake that could allow an upward migration of 13 injected fluids? 14 MS. OLSON: That's what (ph) I wanted to know. 15 MR. MOOTHART: There's always potentiality if you make a 16 big enough one, but in generally (sic) the mudstones will act and deform more ductilly rather than fracturing. CHAIR NORMAN: All right, thank you. 17 18 19 MS. OLSON: It (ph) ..... 20 CHAIR NORMAN: Ms. Olson, we are going to have to move 21 forward now and I'll allowed..... 22 MS. OLSON: I was just going to ask you..... 23 CHAIR NORMAN: .....two questions. 24 MS. OLSON: .....a question. Is..... 25 CHAIR NORMAN: No, you'll -- you'll..... R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 60 . . 1 MS. OLSON: Could I just ask you a question so that I 2 don't..... 3 CHAIR NORMAN: Sure. 4 MS. OLSON: .....ask -- bother someone else..... 5 CHAIR NORMAN: Certainly. 6 MS. OLSON: .....potentially? I wanted to know is -- are 7 earthquake standards considered in the assessments? 8 CHAIR NORMAN: Yes, ma'am, we consider earthquakes and 9 volcanos and winds..... 10 MS. OLSON: Okay, all right. 11 CHAIR NORMAN: .....in all of our decisions here. 12 MS. OLSON: Thank you. 13 CHAIR NORMAN: The possibilities of them (ph) ..... 14 MS. OLSON: Okay. 15 CHAIR NORMAN: All right. We're ready to proceed then 16 with the next witness. 17 MR. NOEL: Good morning, my name is Brian Noel. I'm 18 a..... 19 CHAIR NORMAN: I'm sorry, let me ask you to raise your 20 right hand, please? 21 (Oath Administered) 22 MR. NOEL: Yes, sir. 23 CHAIR NORMAN: All right. 24 TESTIMONY BY BRIAN NOEL 25 MR. NOEL: My name is Brian Noel. I'm a senior drilling R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 61 . . 1 engineer with ConocoPhillips. 2 CHAIR NORMAN: And will you be testifying as an expert 3 here? 4 MR. NOEL: That's correct. 5 CHAIR NORMAN: Then could you give us your educational 6 background and experience? 7 MR. NOEL: I have a Bachelor of Science from the 8 University of Illinois in Geology in 1977. I spent three years 9 as a mud logger and then eight years as a consulting well site 10 geologist in the Rocky Mountain Region predominately the Big 11 Horn Basin of Wyoming. Returned to school, earned a Bachelor 12 of Science in Petroleum Engineering from the University of 13 Wyoming in 1991. Went to work for ARCO Alaska which is now 14 ConocoPhillips. 15 The job assignments with ARCO here in Alaska were 16 reservoir operational and production engineering assignments in 17 town, on the Slope, Cook Inlet fields, as well as Kuparuk 18 field. And since 1998 I've been in the drilling group working 19 Kuparuk and also western North Slope, Alpine and the 20 satellites. And fall of 2002 I earned my professional 21 engineering license with the State of Alaska in Petroleum 22 Engineering. 23 CHAIR NORMAN: And you've had then roughly, what, about 24 seven years of experience in the Kuparuk areas, did I 25 understand you correctly, working with ConocoPhillips? R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 62 . . 1 MR. NOEL: Kuparuk or Alpine..... 2 CHAIR NORMAN: Kuparuk, Alpine. 3 MR. NOEL: .....and to the west since 1995 in the 4 drilling ..... 5 CHAIR NORMAN: In more than -- more than seven..... 6 MR. NOEL: .....and drilling since 1998. 7 CHAIR NORMAN: Okay. Question, commissioner? 8 COMMISSIONER SEAMOUNT: No questions. 9 CHAIR NORMAN: Commissioner Foerster? 10 COMMISSIONER FOERSTER: No, questions. 11 CHAIR NORMAN: All right. We accept your qualifications 12 as an expert witness, please proceed. 13 MR. NOEL: All right, thank you. What I was going to 14 cover this morning was the drilling operations or the well 15 construction for the C04 development. 16 This is slide number 57 (sic). It's the same spider map 17 you just saw recently showing the Alpine COl and C02 fields and 18 then our CD4 development about four miles to the south. 19 As you also heard the Nanuq reservoir is planned for 16 20 development wells. They're all horizontal. The horizontal 21 lengths are six to 7,000 feet per well. And as mentioned 22 before we plan to undulate through the Nanuq reservoir since 23 there's multiple sand packages. The undulation is essentially 24 a sign wave and we would achieve over that six to 7,000 foot of 25 length up to six passes through the pay interval. R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 63 . . 1 The drilling fluids for the Nanuq reservoir itself is 2 either water or mineral oil based drilling fluid. The 3 injectors currently are planned for mineral oil. We're still 4 studying the producers as to if water or mineral oil is the 5 best fluid. These are the same types of fluids that we use in 6 the Alpine field to date. 7 The one main difference from Alpine to the CD4 development 8 is we are going to run slotted liners and that's due to the 9 undulating nature of the wellbore and we'll have shale and sand 10 exposed and we just want to preserve accessibility to that 11 horizontal interval in the future. 12 We drill one Nanuq well this fourth quarter this year and 13 we do plan an extended flowback to assess the deliverability of 14 this reservoir. And then we take a time out and go to CD3 so 15 we'll have time to evaluate that first Nanuq penetration as a 16 horizonal and look at its deliverability. 17 We also plan to drill two Kuparuk wells this fourth 18 quarter. The Kuparuk development only has three wells total. 19 Here again they're horizontals anywhere from 4,800 up to 7,000 20 foot in length. For the Kuparuk we'll use a water based 21 drilling fluid for the reservoir and we also plan slotted 22 liners. 23 The two Kuparuk wells we're drilling are these two right 24 here to the eastern side of the spider map. After they're 25 completed we plan a pulse test to confirm the reservoir R & R C 0 U R T R E P 0 R T E R 5 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 64 . . 1 continuity for that planned spacing. 2 On the next slide here is just a comparison of the Nanuq 3 well development versus the Alpine. We've been drilling with 4 the same rig in the Colville River on the Alpine field since 5 1999. We've just completed our 100th well in that development 6 with approximately 1.5 million total feet of hole drilled and 7 of that 25 percent was horizonal in the Alpine reservoir. 8 So what we're trying to show here with our bar graph is 9 the first bar is total depth of the well and we've got max, min 10 and we're plotting averages. And so the whole point of the 11 graph is to show that the Nanuq development whether we look at 12 total depth, casing depth of the seven inch casing, our 13 production casing, departures of the well or horizontal length 14 is all within our experience level we've gained at Alpine. 15 The one main difference is for CD4 we've planned much 16 longer horizontal developments of about twice as long as the 17 initial Alpine development. We feel comfortable being able to 18 drill those lengths given the experience at Alpine and Kuparuk 19 and Prudhoe Bay so it just shows the evolution of drilling 20 technologies over the last six or seven years. We can drill 21 longer and longer and pay with lower well count. 22 CHAIR NORMAN: If you had to sum it up in a sentence or 23 two what is it that was learned at Alpine that enables you to 24 reach out that much further? 25 MR. NOEL: It's an evolution in the drilling tools we use, R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 65 . . 1 the motors, rotary steerable assemblies, logging tools to be 2 able to keep the bit in the pay for a longer interval. And 3 it's also the hole cleaning abilities we've learned with higher 4 pump rates. It's just a progression of drilling techniques 5 through the years and we gained much experience. As you go to 6 3,500 feet, you try for 4,000 and you keep moving the bar. 7 Our drilling practices for CD4 are essentially what we're 8 doing at Alpine to date. Since these are directional wells and 9 horizontal wells our surveys are all measured while drilling 10 rather than wireline. We get continuous surveys as we drill 11 the well for proper placement and anti-collision avoidance of 12 adjacent wells. And all of our log data is gathered through 13 instruments in the drill string while we drill, rather than the 14 old fashion way of wireline. 15 We also plan the same horizontal wellhead system which 16 allows us a single rig up of blowout prevention stack on the 17 well. Then everything else is a drill through wellhead. All 18 the subsequent casing runs, tubing runs are all through the BOP 19 stack and hung off the wellhead so we don't have to keep making 20 and breaking the BOPs. It also facilitates workovers where you 21 don't have to remove flow lines if you ever put the rig back on 22 the well. 23 The muds we're using are typical to muds used across the 24 Slope. We have water based mud for our surface hole. Another 25 water based mud, low solids, non-dispersed for the intermediate R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 66 . . 1 hole and then the reservoir is either a water or a mineral oil 2 based fluid and the choices there are designed to prevent or 3 minimize damage to the reservoir itself. 4 CHAIR NORMAN: Could I ask you on this point, because the 5 Commission frequently gets legitimate questions from the 6 average Alaskan about fluids put into the ground. And there is 7 an understandable concern about whether those fluids may be 8 introducing contamination into the subsurface and could you 9 talk a little bit about the water and the mineral oil that is 10 being contemplated as the drilling fluid and also the mud? 11 Just a brief explanation on those. 12 MR. NOEL: Okay. The water base is fresh water. It's 13 drawn from the lakes right there near Alpine. We have a mud 14 plant in the field where the mud is blended. It's water, gel, 15 barite. The drilling fluids are a polymer based. And then 16 there's other certain additives to minimize formation damage 17 and wellbore stability. 18 And the mineral oil is much more environmentally friendly 19 than the old oil based or diesel based systems of old. It has 20 low flashpoints, low flammability and there again we're just 21 using it in the reservoir. Everything above has been cased and 22 cemented and protected so the mineral oil only sees the 23 reservoir rock. There's no way for it to leak out of those 24 zones and move up shallower into shallower strata. 25 CHAIR NORMAN: If someone goes into a drug store you can R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 67 . . 1 buy mineral oil. How does that -- if you know, how does that 2 compare with the term mineral oil used there in the drilling 3 fluids? 4 MR. NOEL: I'm not sure what's in the drug store. The 5 mineral oil we're using is a hydrocarbon product derived from 6 the refining process. 7 CHAIR NORMAN: Thank you. 8 MR. NOEL: And then as steve showed earlier we also 9 proposed annular disposal for this drill site. We have this 10 there's no underground sources of drinking water. That was a 11 finding for the Alpine pool rules for the Colville River Unit. 12 I think it was Area Injection Order 18. The stratigraphy is 13 consistent across the area from Alpine down to CD4. 14 The rig has a ball mill. The surface gravels we do wash 15 those. They are tested for any contaminants and if they pass 16 the test we recycle that gravel and use it for road maintenance 17 or pad maintenance rather than grinding it and disposing of it. 18 The deeper zones we grind our cuttings and the used drill 19 muds form a slurry with some water added to it that we pump 20 down our surface by production casing annulus into that C30 21 horizon. 22 The disposal interval at the top of the Seabee it exists 23 throughout, it's below our surface casing shoe for CD4. At 24 Alpine we have pumped away approximately 1.4 million barrels 25 into that zone. Each well is permitted for up to 35,000 R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 68 . . 1 barrels. And the process is regulated there under 25.080 so 2 each well we do construct we have to show we have integrity, 3 isolation and then apply for the permit to utilize for annular 4 (ph) disposal. 5 COMMISSIONER FOERSTER: Mr. Noel, I may have missed it, 6 did you address the absence of drinking waters? 7 MR. NOEL: Yes, the exploration logs have all been 8 analyzed and shown that there's no portable water or sources of 9 drinking water and that was a finding during the Alpine pool 10 rules for the Colville River unit. 11 COMMISSIONER FOERSTER: Okay. So there are no 12 groundwaters that we're worried about protecting here? 13 MR. NOEL: That's correct. The drilling plan for the 14 wells whether it's the Nanuq or the Kuparuk reservoir, the plan 15 well spacing for CD4 is 20 feet well centers. We do set an 80 16 foot insulated conductor which is cemented back to surface. 17 The insulated conductor and the thermal siphons that are placed 18 after the well is completed prevent shallow thawings so we 19 don't have subsidence problems with the gravel pad in the 20 future. 21 The rig drills from the shoe of the conductor to approximately 2,400 foot TVD where our surface casing is set. That's a good competent shale that allows us to obtain leak off 22 23 24 tests that are required prior to drilling out and so if we 25 would take a kick from the reservoir we could contain it within R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 69 . . 1 the casing shoe and kill the well. That shale is also our 2 containment layer for our disposal horizon which is just below 3 our surface casing shoe. 4 The surface casing is cemented back to surface. It's a 5 single stage job. We haven't had any problems at Alpine except 6 for, I think, two wells out of the 100 where we did have cement 7 to surface and it fell back a little ways and we had to do a 8 top job around the top of the casing. So the top job or a port 9 collar will be a contingency out there, but we haven't seen any 10 issues that would give us any concern that we can't cement the 11 surface casing in a single placement. 12 From there we install our blowout prevention equipment, 13 test it, do a casing test to show we have integrity of that 14 pipe. Then we drill out less than 50 feet of new formation and 15 perform a leak off test of that casing shoe and that provides 16 us the data we would need to submit to the Commission to permit 17 a well (indiscernible) and disposal down the road. 18 After we obtain the acceptable leak off test we 19 directionally drill our intermediate hole section to the 20 reservoir target and then we're turning and building that whole 21 section to land horizontally within the reservoir itself. At that point we set production casing in zone and we cement that casing. We bring cement back above the top of the reservoir. 22 23 24 In the case where we have the Kuparuk wells we will bring 25 cement back high enough to cover the Nanuq sandwiches above us R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 70 . . 1 so we'll isolate both zones from each other. 2 Again we pressure test that casing string, drill out and 3 then perform a formation integrity test to show we have a 4 competent cement shoe. Once that's achieved we drill ahead and 5 drill our horizontal interval. The goal is to stay in the sand 6 in the Kuparuk from start to finish and in Nanuq we'll undulate 7 through the multiple sand packages. 8 The one difference here compared to Alpine which a 9 barefoot completion is once we're TO we'll condition the hole, 10 trip out and then run back in and place a slotted liner through 11 the reservoir section. 12 The injection wells we'll run a cement quality log after 13 that liner is in place to show we have cement where it needs to 14 be and then we'll run a packer and tubing into the wellbore to 15 finish the completion. 16 The next slides are just schematics, slide number 61 (sic) 17 of the proposed producer..... 18 COMMISSIONER FOERSTER: Excuse me. 19 MR. NOEL: .....and injector completions. 20 CHAIR NORMAN: Do you have a question? 21 COMMISSIONER FOERSTER: I do. A couple times I've heard 22 you mention slides that are numbered differently than the 23 numbering that I have. Do you have -- this is slide 69. 24 CHAIR NORMAN: I show this as slide 53. 25 COMMISSIONER FOERSTER: As do I. R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 71 . . 1 MR. NOEL: Does that subtract out the confidential slides? 2 COMMISSIONER FOERSTER: No, 'cause they're numbered as 3 well. 4 CHAIR NORMAN: No, they're all -- yeah, they're all 5 sequentially numbered and so the slides that -- thank you for 6 catching that, Commissioner Foerster, 'cause that's the kind of 7 thing we need to synchronize with our record, but our slides 8 show that this is now slide 53. Do you want to take a moment 9 to check that 'cause if we don't we'll have a confusing record 10 here? 11 While we're doing that, let's take a five minute stretch 12 break and they can -- and then we'll pick up exactly where you 13 are. 14 (Off record - 11:16 a.m.) 15 2700 16 (Tape Change) 17 Tape 3 18 0015 19 (On record - 11:20 a.m.) 20 CHAIR NORMAN: We're back on the record and the time is 21 11:20 a.m. and we will continue to move along as quickly as we 22 can. We want to get all the testimony in. 23 Have you been able to correlate the slides? Can someone 24 give an explanation then so we can tie it to what will be an 25 exhibit to this transcript? R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 72 . . 1 MR. NOEL: Yes, we have some backups that weren't shown on 2 the previous ones so it got us out of sequence, but I can back 3 up and just give you the proper number real quickly..... 4 CHAIR NORMAN: All right. 5 MR. NOEL: .....with the title if you'd like? 6 CHAIR NORMAN: Please, yeah. 7 MR. NOEL: From the start of the well construction slide 8 the number 49 was the Development Drilling Plan that showed the 9 spider map and the planned horizontal lengths of the two 10 reservoirs. 11 Slide 50 was a comparison of the development well lengths 12 at CD4 versus what's already been drilled at Alpine. 13 Slide 51 was just a summary of the drilling practices for 14 CD4. Slide 52 was a summary of the drilling plan for the CD4 15 wells. And then slide 53 was a schematic of the producer and 16 the injector completions for CD4. 17 So continuing there with slide 53 just on the schematics, 18 again, to point out that the only main difference from the 19 Alpine development is the horizontal section has slotted liners 20 that are hung with a hanger at the seven inch casing shoe. 21 Then we have production tubing and a packer that's run second, 22 stings into the top of that liner to give you access to the 23 horizontal. 24 The producers are gas lifted completions so we'll have 25 jewelry in the tubing string for the gas lift. Producers also R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 73 . . 1 have a surface actuated subsurface safety value to prevent 2 uncontrolled flow to surface if there were a problem with the 3 wellhead. 4 On the injector side we have a profile set at the same 5 depth and it's a subsurface, one way injection value. There is 6 no service control line to that, but it also prevents the 7 injector from backflowing to surface if there were a problem 8 with the wellhead or tree. 9 The proposed rule number 4 covers the drilling and 10 completion practices and here, again, these are similar rules 11 that Alpine operates under. The first one was we drill no more 12 than 50 feet before a casing shoe within the reservoir whether 13 it's the Nanuq sand or the Kuparuk sand before we obtain our 14 formation integrity test. 15 The reason we don't want to go to a leak off test in this 16 zone is we don't want to take a chance of breaking down that 17 production casing, cement job and shoe. We're already in zone. 18 We'll go to a pressure required to allow us to drill to TD with 19 the mud weights and equivalent circulation -- circulating 20 densities we expect. 21 The second one is we've shown casing design, sizes, grades 22 and weights on those schematics. That is our base plan, but we 23 just wanted to preserve an option that if we would change hole 24 sizes down the road that we could change casing and/or tubing 25 sizes and designs after we submit them to the Commission with R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 74 . . 1 the proper engineering behind it. 2 The third one addresses the regulation for data on 3 deviated wells that we submit in our Permit to Drill package 4 and it just reflects the additional data that has become 5 customary when we permit these type of wells that's above and 6 beyond what's in the regulations. We plan to continue to do 7 that for CD4 development. 8 And then the last one is a proposal that we'll have one 9 complete log suite (ph) from the conductor shoe into the 10 reservoir for at least one well on the pad. That's been the 11 standard for the new developments out here and then from there 12 we'll just log the reservoir interval (ph) with the -- with the 13 additional logs. 14 CHAIR NORMAN: Let's let the witness finish 15 testifying..... 16 MS. OLSON: Well, I did want to raise a conflict. 17 CHAIR NORMAN: Well, I'll hear from you later, Ms. Olson. 18 MS. OLSON: Okay. 19 CHAIR NORMAN: Let's not interrupt the witness right now. 20 MS. OLSON: Thank you (ph). 21 CHAIR NORMAN: Please continue. 22 MR. NOEL: Okay, so there again that's just the summary of 23 the same type of rules that we have for the Alpine development 24 and we're proposing them again for the CD4 development. And 25 that was the end of the drilling section, the presentation. R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 75 . . 1 CHAIR NORMAN: And that will conclude your testimony? 2 MR. NOEL: That's correct. 3 CHAIR NORMAN: Commissioner Seamount, any questions? 4 COMMISSIONER SEAMOUNT: No questions at this time. 5 CHAIR NORMAN: Commissioner Foerster? 6 COMMISSIONER FOERSTER: I have none written (ph). 7 CHAIR NORMAN: None. Ms. Olson, you have a question? 8 MS. OLSON: Yes, and I'd like to raise an objection. 9 CHAIR NORMAN: All right. Come forward, please. 10 MS. OLSON: First my name is Dana Olson and I'd like to 11 raise an objection. We're being -- we're taking testimony as 12 expert and it seems to conflict because it's going in and 13 asking for permission at the same time it's giving expert 14 testimony. So, in other words, they're being treated as an 15 expert witness for their understanding at the same time they're 16 asking to exempt themselves, so that..... 17 CHAIR NORMAN: Yes, yes. 18 MS. OLSON: .....would be a conflict. 19 CHAIR NORMAN: Yes. Your concern is -- goes to the 20 impartiality of the expert. 21 MS. OLSON: Yes. 22 CHAIR NORMAN: There's no requirement that an expert be 23 impartial. Indeed, in hearings you often have different sides 24 each having their own expert so there's no impropriety here. 25 We simply want to know the educational background and R & Reo U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 76 . . 1 experience we're listening to and the Commission is satisfied 2 with this. There is no impropriety in ..... 3 MS. OLSON: I think I -- there's a misunderstanding..... 4 CHAIR NORMAN: .....in them testifying. 5 MS. OLSON: .....when I said conflict so I'd like to 6 clarify that. When I said you don't go in and ask the 7 Commission to approve something and then also in the same 8 testimony ask them to allow you to not -- to vacate the 9 decision or whatever. 10 CHAIR NORMAN: Okay. Your objection is noted. 11 MS. OLSON: Okay. The questions I had, I'm sorry this may 12 be a really silly question, but I'm not knowledgeable so I'm 13 going to ask whether or not these seem to be rather deep 14 wells. I don't know if that's industry standard or not, but I 15 wanted to know whether there has been any scientific data on 16 whether or not at this depth it could potentially cause an 17 earthquake? 18 CHAIR NORMAN: Well, Ms. Olson, I'm going to rule that out 19 because..... 20 MS. OLSON: Okay. 21 CHAIR NORMAN: .....the focus of these pool rules and 22 these witnesses came prepared to addressed that. 23 The possibility of an earthquake does exists virtually 24 throughout Alaska and, indeed, throughout the Pacific Rim and 25 so in engineering and looking at any subject that is considered R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 77 . . 1 and so I think the answer I gave you before is yes, that's 2 taken into consideration. That's always a possibility as well 3 as other natural disasters, but we're not going to take the 4 time right now because we want to get more into the testimony 5 of additional witnesses. 6 MS. OLSON: Right. And the other thing was there was a 7 word that I couldn't hear when it was talking about the 8 drilling mineral oils. It sounded like baridene (sic) or 9 something? 10 CHAIR NORMAN: Barite. 11 MS. OLSON: Barite or something and..... 12 CHAIR NORMAN: Um-hum. Barite is a heavy mineral that's 13 mixed in, into the drilling mud. We can go over that later. 14 If you -- we will give you an opportunity at the end if you 15 want to jot any questions, if there's anything that you didn't 16 understand we'll do our best to clarify it at the end. 17 MS. OLSON: Yes, it's just that I have a short memory and 18 I'm asking for accommodation. Thank you. 19 CHAIR NORMAN: Sure, you bet. Anything more, Mr. Bennett? 20 MR. BENNETT: No, sir. 21 CHAIR NORMAN: Then thank you very much. 22 MR. BENNETT: Thank you. 23 CHAIR NORMAN: Would you to raise your right hand, please? 24 State your name? 25 MR. WALKER: Jack Walker. R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 78 . . 1 CHAIR NORMAN: And, I'm sorry, let me swear you first. 2 MR. WALKER: Okay. 3 (Oath Administered) 4 MR. WALKER: Yes, sir. 5 CHAIR NORMAN: Will you state your name, please? 6 TESTIMONY BY JACK WALKER 7 MR. WALKER: My name is Jack Walker. I'm the drill site 8 CD4 production engineer for ConocoPhillips Alaska, Incorporated 9 and I plan to testify regrading well operations and facilities 10 for the proposed pools. 11 CHAIR NORMAN: Okay. And your educational background and 12 experience? 13 MR. WALKER: My qualifications include a Bachelors of 14 Science Degree in Mechanical Engineering from the University of 15 Tulsa and a Masters Degree in Petroleum Engineering from the 16 University of Alaska-Fairbanks. 17 I've been employed by ConocoPhillips and predecessor 18 companies in Alaska for 25 years with a variety of engineering 19 and operation assignments on pools including Prudhoe Bay, 20 Lisburne, Point McIntyre, Kuparuk, Tabasco, Meltwater, West Sac 21 and most recently the future pools in the Colville River field. 22 CHAIR NORMAN: All right. Any questions concerning 23 qualifications, Commissioner? 24 COMMISSIONER SEAMOUNT: Mr. Walker, when were you at the 25 University of Tulsa? R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 79 . . 1 MR. WALKER: I graduated from the University of Tulsa 2 1979. 3 COMMISSIONER SEAMOUNT: Thank you. No further questions. 4 CHAIR NORMAN: Commissioner Foerster? 5 COMMISSIONER FOERSTER: I have no questions. 6 CHAIR NORMAN: All right. The Commission accepts your 7 qualifications as an expert witness. 8 MR. WALKER: I will briefly describe the well operations 9 and facilities along with allocation of unitized substances for 10 the development of these proposed pools. And I'll show some 11 rules regarding automatic shut-in equipment, well testing, 12 common production facilities and commingling, as well as 13 sustained casing pressures. 14 Drill site CD4 will serve both reservoirs, Nanuq and 15 Nanuq-Kuparuk. However, we plan dedicated wells for each 16 reservoir with no subsurface commingling. We foresee all the 17 development drilling activity for these two proposed pools to 18 be accomplished from that drill site CD4. And this drill site 19 will be operated, as Jordan mentioned earlier, with year around 20 access via a gravel road that was installed last winter. 21 I'm on slide 59, that describes the well design features 22 for drill site CD4. As Brian Noel mentioned the production 23 wells for both proposed pools will be completed with slotted 24 liner completions with blank pipes (ph) across any non-pay 25 intervals that we may encounter as well as gas lift for R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 80 . . 1 artificial lift. 2 We plan to have fail-safe surface controlled, subsurface 3 safety valves in the producers and they will be controlled 4 along with surface safety valves with hydraulic panels mounted 5 in each individual wellhouse. Producers will be tested via the 6 use of automated divert valves. Gas lift and production chokes 7 will also be automated on the producer. 8 Injection wells will have similar completions to the 9 producers with the exception of the gas lift. Water or 10 miscible gas will be selected via a manually operated system. 11 Subsurface safety valves are planned to be operated with 12 differential pressure in the injection wells. Surface safety 13 valves are planned on the injector wells that would be operated 14 with hydraulic panels mounted at the wellhouse. 15 This next slide, number 60, shows the proposed rule number 16 5 for automatic shut-in equipment and this is virtually 17 identical to the Alpine rule with a few clarifications on the 18 well service. And one of the reasons we would like to have 19 consistency in some of the rules is to provide for efficient 20 operations and this is a good example of that. The testing and 21 the requirements would be virtually identical. 22 COMMISSIONER FOERSTER: Mr. Walker, can I expand on that 23 for clarification? Is part of your motivation for wanting 24 consistency in the operating rules so that the operators aren't 25 confused as they go from pad to pad with oh, we're on this pad R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 81 . . 1 we have to do this, this way, we're on that pad we have -- when 2 at the surface the wells look and behave essentially the same 3 and so the more you get consistency the less likely you are to 4 make a mistake or accidentally violate a rule that might 5 otherwise be in synch with the rest of the fields? I didn't 6 say that very well (ph) ..... 7 MR. WALKER: Generally I agree with what you said and it 8 provides a more efficient operation generally to have these 9 rules consistent, so yes, it makes a simpler operation if the 10 rules are the same from pad to pad. 11 COMMISSIONER FOERSTER: Is there any reason that you can 12 think of that having the rules the same from pad to pad would 13 cause a problem? 14 MR. WALKER: No, there's no reason I can think of that 15 would -- where it would cause a problem to have them consistent 16 from pad to pad. 17 COMMISSIONER FOERSTER: And is there any difference in the 18 equipment or the operation of the equipment from pad to pad 19 that might require a different set of rules? 20 MR. WALKER: The equipment, the subsurface safety valves are very similar and the surface safety valves are very similar. There is different between CD1 and 2 hydraulic 21 22 23 systems and the hydraulic systems that we plan. The 24 fundamental principles are identical. The valves are actuated 25 or held open with hydraulic pressure and they fail-safe with a R & R C 0 U R T R E paR T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 82 . . 1 spring loaded valve -- or spring loaded flapper or gate (ph) in 2 the case of the surface safety valve. 3 COMMISSIONER FOERSTER: So the physics and the operations 4 aren't different? 5 MR. WALKER: The physics are identical. 6 CHAIR NORMAN: Please proceed. MR. WALKER: On slide 61 it outlines some of the well 7 8 surveillance for drill site CD4 and surveillance is a vital 9 part of the planned well operations. Producer and injector 10 wells will be designed with transmitters for remote monitoring 11 of the pressures of the tubing, the inner annulus and the outer 12 annulus. 13 These wells will also have temperature transmitters for 14 remotely monitoring the wellhead temperature. These 15 temperatures and pressures will be recorded and will be 16 remotely accessed via an automation system and this same 17 automation system would be used to manage the well tests that 18 are planned at a minimum of twice per month. 19 The automation system will also be used to monitor and 20 control gas lift for the producers and the water and gas 21 injection into the injection wells. 22 The drill site CD4 was designed to continuously monitor 23 the single phase streams of gas or water, if it's gas lift or 24 if it's injection gas or if it's injection water. 25 Rule 10 requires two slides and I think that we tied this R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 83 . . 1 identically to the existing rule for Alpine. I won't read it, 2 but that was the intent was to make this rule identical to the 3 Alpine rule for managing sustained casing pressures. 4 COMMISSIONER FOERSTER: Mr. Walker, is there anything in 5 this rule that is less regulating than the state-wide rules? 6 Is there anything in your proposal that is less stringent than 7 state-wide rules require? 8 MR. WALKER: Not that I know of. I don't know of anything 9 in this proposed rule that would be less stringent than the 10 state-wide regulations. 11 COMMISSIONER FOERSTER: Okay. So if you did not have 12 proposed rule 10 the operations that you would be held to would 13 be less stringent than these? 14 MR. WALKER: I believe that's correct. 15 On slide 64, the on pad facilities are described again 16 similar to the slide that was shown in the introduction. The 17 facilities will be a trunk and lateral system which provides a 18 lot of flexibility for well service. While the development of 19 the Nanuq and Nanuq-Kuparuk pools is expected to be complete 20 with a combined total of 19 wells, the gravel pad could 21 accommodate as many as 27 wells on 20 foot spacing. 22 The drill site plan view shows the well row in an east to 23 west orientation, approximately east/west with a footprint of 24 the drilling rig on the eastern most well road. Parallel to 25 the well road is a pipe rack that will hold the headers for R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 84 . . 1 production test, gas lift, water injection and miscible 2 injectant. The lateral lines will connect each well to the 3 appropriate header. 4 Most of the other on pad facilities will be located down 5 at the eastern end, down here, and those facilities will 6 include a production heater to provide heat necessary for 7 efficient separation at the Alpine central facility as well as 8 drill site separation, test separation. A chemical injection 9 system is included to provide injection of corrosion inhibitor 10 and other production chemicals as needed. 11 The cross country facilities are outlined on slide 65 and 12 they include a 3.8 mile existing gravel road that was put in 13 last winter from drill site CD4 to CD2. 13.8 kilovolt power 14 line and an eight inch water injection line, six inch gas lift 15 pipeline and a six inch miscible injectant line will be -- will 16 supply those power and injection, you know, gas lift to drill 17 site CD4 from the Alpine central facility. 18 Then we plan a production pipeline from drill site CD4, a 19 multi-phase pipeline to carry a mixture of oil, water and gas 20 produced from the CD4 wells back to the Alpine central facility 21 where it will be commingled on the surface with production from 22 other pools in the Colville River unit. 23 The production and injection for the Colville River unit will be measured at an aggregate level and the aggregate streams are such as oil production or fuel gas, enriching 24 25 R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 85 . . 1 fluids, lean gas and injection produced water, et cetera, 2 similar to other North Slope fuels with surface commingling. 3 Streams measured in aggregate, oil for example, will be 4 allocated to individual wells on a proportionate basis. 5 Individual meters will be the basis for allocating fluids 6 to the injector wells. Well tests and operating conditions 7 form the bases for allocating aggregate volumes to the producer 8 wells. 9 Aggregate production and injection volumes are allocated 10 proportionally via the allocation factor. Allocation factors 11 are defined as the ratio of the aggregate volume to the sum of 12 the theoretical volumes for each well. The allocated volume 13 for a particular well is the product of the allocation factor 14 and the theoretical volume for that particular well. 15 Slide 67 shows proposed rule number 8 that allows -- or 16 provides Commission approval for the commingling on the surface 17 upstream of custody transfer. 18 Proposed rule number 9 covers the well testing 19 requirements with a twice per month minimum frequency. 20 COMMISSIONER FOERSTER: Mr. Walker, are there different 21 royalty ownerships between the two reservoirs? 22 MR. WALKER: We expect that the royalties will be 23 different between Nanuq and the Nanuq-Kuparuk and the Alpine 24 participating area, yes. 25 That summarizes my testimony and -- or to summarize my R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 86 . . 1 testimony, I should say, the well operations and facilities 2 proposed were planned to safely operate within the Colville 3 River Field and as well as accurately allocate the production 4 and injection among the pools. 5 CHAIR NORMAN: All right. Thank you very much, Mr. 6 Walker. Let me ask -- see if there are any questions before we 7 excuse you. Commissioner Seamount. 8 COMMISSIONER SEAMOUNT: No questions. 9 CHAIR NORMAN: commissioner Foerster. 10 COMMISSIONER FOERSTER: No (ph). 11 CHAIR NORMAN: Okay, thank you. 12 MS. OLSON: May I ask a question? 13 CHAIR NORMAN: Yes, ma'am, if it's a specific question of 14 this witness, if it's..... 15 MS. OLSON: Yes. 16 CHAIR NORMAN: All right. 17 MS. OLSON: The first question I wanted to know what an 18 enriching fluid was? 19 MR. WALKER: An enriching fluid is a mixture of 20 hydrocarbon gases in the -- typically in the ethane to hexane 21 range. 22 MS. OLSON: And the second question I wanted to ask was 23 this is a submitted drilling plan, is this correct, is that 24 what your testimony was related to? 25 CHAIR NORMAN: Your question is whether this is an R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 87 . . 1 approved plan? 2 MS. OLSON: No, is that their submittal for a drilling 3 plan? 4 CHAIR NORMAN: Well, it's their -- it's an explanation now 5 of how they plan to operate the wells. 6 MS. OLSON: But it would be a drilling plan, is that 7 correct? 8 CHAIR NORMAN: Well, they're -- no, they will have a 9 drilling plan that they will submit to DNR and DNR will approve 10 it and then as they drill wells they will specifically apply to 11 this Commission and they will get sundry approvals. They'll 12 first get a drilling permit and then for each separate step 13 there will be permits issued. 14 MS. OLSON: And the second thing I wanted to ask is these 15 pipelines, are they not under authority of others? In other 16 words, we're being -- we're addressing pipelines in their 17 drilling thing, but other people are -- make the rules on how 18 the pipelines -- environmental considerations is (sic) a 19 pipeline, is that correct? 20 CHAIR NORMAN: Well, yes, there certainly are to the 21 extent something is present on the surface. Yes, there are 22 other agencies that monitor that including the State Department 23 of Environmental Conservation and as well as the landowner, 24 they're all concerned about the pipeline. 25 MS. OLSON: Has the Commission assessed whether those are R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 88 . . 1 adequate or not? 2 CHAIR NORMAN: Well, that will be done at the time 3 whenever their constructed, but as a part of these proceedings 4 right now, no, we're not looking at that. We're looking mainly 5 at these two specific reservoirs that are 7,000 feet below the 6 surface and that's where we're focusing our attention right 7 now. 8 MS. OLSON: So it is my understanding -- is this correct, 9 I wanted to make sure I understood that the applicant, if -- if 10 he were granted this approval, then he would still be subjected 11 even though he got this approval he could potentially be 12 stopped if the pipeline plans were not adequate, is that 13 correct? 14 CHAIR NORMAN: If the pipeline plans are not in compliance 15 with applicable law then the answer to your question would be 16 yes. This does not constitute approval for any pipeline plans 17 now. MS. OLSON: Yeah. I just wanted the applicant to be on 19 record knowing that if it was granted they still may be 18 20 prohibited from drilling if it were found that the 21 pipeline..... 22 CHAIR NORMAN: Well,..... 23 MS. OLSON: .....assessment was not adequate. 24 CHAIR NORMAN: Yes. 25 MS. OLSON: Okay. R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 89 . . 1 CHAIR NORMAN: Yes. That's question is not even before us 2 now, but that would be..... 3 MS. OLSON: No, I wanted to know their opinion. 4 CHAIR NORMAN: Well, we want to..... 5 MS. OLSON: Or their their position, not..... 6 CHAIR NORMAN: Yeah. 7 MS. OLSON: .....their opinion. 8 CHAIR NORMAN: The Commission, though, can tell you that 9 there are other agencies with jurisdiction over both gathering 10 lines and common carrier lines and there are other agencies 11 also that have jurisdiction over environmental concerns. 12 MS. OLSON: Well, the reason I brought it up is because 13 they got approval as being an expert witness..... 14 CHAIR NORMAN: Um-hum. 15 MS. OLSON: .....and so that's why I wanted to know as an 16 expert witness whether or not that would constitute knowledge 17 acknowledgement that their..... 18 CHAIR NORMAN: All right. 19 MS. OLSON: .....drilling would be prohibited should the 20 law be deficient. 21 CHAIR NORMAN: Okay, thank you for ..... 22 MS. OLSON: Okay, thank you. 23 CHAIR NORMAN: .....thank you for that question. Mr. 24 Wiess. 25 MR. WIESS: Okay. Again my name is Jordan Wiess. I'll be R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 90 . . 1 concluding the testimony today. 2 First I'd like to start with the last rule that we had 3 within the proposed pool rules and this is just a rule to 4 ensure that the Commission has got the administrative authority 5 to change the rules whenever they see fit. 6 Secondly, I just want to follow up a couple things on 7 consistency. 8 The first thing, you know, rule number 3 which is the well 9 spacing, you know, that rule is effectively the spacing -- a 10 minimum spacing distance from a change in underground interest 11 owners to ensure that we do not effect offset owners to the 12 wells that we're drilling. So we want to make sure that we 13 have a minimum of 500 foot distance between the next property 14 if somebody hav- -- may have a differential working interest 15 ownership. 16 The second thing is -- you know, again we've been talking 17 about trying to maintain consistency between these proposed 18 rules and Alpine rules that we have in place as well as other 19 ones across the Slope. We need to keep in mind that, you know, 20 the Nanuq pools will be managed as part of an integrated system 21 within the Alpine area. This is one of several pools within 22 the Alpine field. 23 Now, these pools will be producing into common facilities 24 and we'll be using these common facilities to move fluids 25 around to maximize the recovery from all of these pools within R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 91 . . 1 the field. 2 Now, the consistency that we are asking for is based upon 3 having, you know, these integrated facilities. We have similar 4 well designs. Although the pools, the reservoirs are 5 different, we have similar well designs. 6 We have infrastructure and systems in place to manage the 7 reservoir through the fluids that we put in the ground, how we 8 model it, how we do our pressure monitoring, the tools that 9 we've developed to manage and monitor the wells underground. 10 The testing procedures and the testing equipment that we 11 have is all common to the entire Alpine field, not just one pool. And we use all of that to ensure that we are maximizing recovery from all the pools within the field. 12 13 14 CHAIR NORMAN: Could I get you to clarify one point. This 15 but the references here, we're talking about the Colville 16 River field and the Nanuq oil field, Nanuq-Kuparuk being within 17 the Colville River field? 18 MR. WIESS: That's correct. 19 CHAIR NORMAN: And then the Alpine field that you're 20 referring to is..... 21 MR. WIESS: Yes, they all -- all within the..... 22 UNIDENTIFIED VOICE: Alpine oil pool. 23 MR. WIESS: Alpine oil pool within the Colville River 24 Unit. 25 UNIDENTIFIED VOICE: Colville River field. R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 92 . . 1 MR. WIESS: Field, thank you. 2 CHAIR NORMAN: Okay. Well, when you use Colville River 3 you're using Colville River Unit, is that what you're referring 4 to, Alpine..... 5 MR. WIESS: We have the Alpine pool. We have the Colville 6 River field. 7 CHAIR NORMAN: Field, okay. 8 MR. WIESS: So within the colville River field,..... 9 CHAIR NORMAN: Yes. 10 MR. WIESS: .....we have the Alpine pool,..... 11 CHAIR NORMAN: Okay, yeah. 12 MR. WIESS: .....the two proposed..... 13 CHAIR NORMAN: Yeah, yeah. 14 MR. WIESS: .....pools for Nanuq, Nanuq and Nanuq-Kuparuk, 15 so..... 16 CHAIR NORMAN: Yes. 17 MR. WIESS: .....all of those pools as well as future 18 pools will be part of that field..... 19 CHAIR NORMAN: Yes. 20 MR. WIESS: .....which we're going to manage to maximize recovery within the entire field. CHAIR NORMAN: Yes, I understand, thanks. 21 22 23 MR. WIESS: Okay. And just a couple last comments. Now 24 we the top priority that we have for the Nanuq development 25 is to ensure we protect the health, safety and the human R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 93 . . 1 resources, as well as the environment and while we're 2 conserving the resources of not only the Nanuq, but also the 3 Alpine and the entire colville River field. 4 You know, these proposed pool rules will prevent the waste 5 and promote conservation. They'll allow protection of 6 correlative rights and promote the maximum, ultimate recovery 7 from all of the pools within the field. 8 You know, additionally our drilling program as well as the 9 facility construction designs meet or exceed the standards that 10 are in place nationally as well as in Alaska. 11 You know, another point that we want to make is, you know, 12 from an environmental standpoint, you know, we're trying to 13 ensure that we minimize our overall impact within the Colville 14 River Delta and the Alpine area by utilizing these common 15 infrastructures that we've put in place. So to ensure that we 16 can maintain the common infrastructure we want to ensure we 17 have the commonality of the rules and the way we manage these 18 reservoirs. 19 And lastly, you know, the cornerstone of our development 20 is really to ensure we're employing our tertiary recover 21 mechanism to maximize the amount of oil we can recover from 22 these reservoirs right from the beginning. And Jack discussed 23 we're going -- and Jim discussed we're going to be using this 24 miscible injectant to really try to maximize this recovery 25 right from the beginning of the development. R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 94 . . 1 You know, the pool rules that we've requested don't 2 deviate tremendously from the overall state-wide pool rules. 3 They're very, very, consistent with the Alpine pool rules and 4 in some cases they are actually more stringent then what the 5 state-wide regulations are. We're trying to be consistent with 6 what we have currently in place within Alpine itself. So with that, you know, that's the end of the testimony that we have prepared and we're willing to take any questions that you may have. 7 8 9 10 CHAIR NORMAN: commissioner Seamount. 11 COMMISSIONER SEAMOUNT: I have no questions. I think that 12 was a very complete and informative presentation the team put 13 on today. 14 CHAIR NORMAN: Commissioner Foerster. 15 COMMISSIONER FOERSTER: I have one question. As it 16 relates to protecting correlative rights what are your plans 17 for interfield allocation based on variation in quality? Do 18 you have interfield Quality Bank plans? 19 MR. WIESS: Jack, do you want to talk? 20 MR. WALKER: I can address that (ph). We have the 21 capability of measuring the quality of produced fluids. Our 22 plans right now are to allocate volumes to each particular well 23 and then you would aggregate certain wells in certain 24 participating areas. And the qualify of the produced fluids 25 can be taken into account to -- for any particular party if R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 95 . . 1 they want to have a Quality Bank, although we don't have one at 2 this time. 3 COMMISSIONER FOERSTER: Is there a significant difference 4 in quality of the crudes? 5 MR. WALKER: I can speak to the API gravity if that would 6 serve. The Nanuq and the Nanuq-Kuparuk pools have a gravity of 7 about 40 degrees plus or minus a degree or so. And I believe 8 Alpine is about 38 degrees -- 37, 38 degrees API. 9 Future pools may -- we mentioned the Fiord and that's a 10 pool that we haven't put before you yet. We have discussed it 11 with the Staff and we anticipate proposing some rules for that 12 in the future and that gravity is about 30 degrees API. 13 COMMISSIONER FOERSTER: So if the -- if I understood you 14 correctly, if an interest owner asked for Quality Bank 15 accounting, you guys can and would be prepared to do that for 16 them? 17 MR. WALKER: As I said we have -- we plan to allocate the 18 production based on volume to each producer and we have the 19 capability and the -- you know, to measure the monitor the 20 quality of the production, so the answer would be we can, yeah. 21 COMMISSIONER FOERSTER: You can, okay. And -- but you 22 don't plan to unless you're asked to by a royalty owner? 23 MR. WALKER: I would say the answer to that is yes. 24 COMMISSIONER FOERSTER: Okay. 25 CHAIR NORMAN: Ms. Olson, what we're going to do, we'll R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 96 . . 1 finish with these witnesses and then we'll -- we'll..... 2 MS. OLSON: I'd like to ask a question 'cause he testified 3 further from the ending and so that's why..... 4 CHAIR NORMAN: Why don't -- why don't we do this, we're 5 going to give you an opportunity to speak if you care to do so 6 and in that you can ask a question..... 7 MS. OLSON: Well, I'd like to ask because he's acting as 8 an expert witness. I'm not an expert witness so I'd like ask 9 him questions. 10 CHAIR NORMAN: I'll have you do this, if you would, if you 11 want to write out your questions..... 12 MS. OLSON: I did and you didn't answer it so I'd 13 like..... 14 CHAIR NORMAN: Pardon? 15 MS. OLSON: .....you to ask -- I'd like to ask him to 16 address it (ph). 17 CHAIR NORMAN: Well, we're not finished yet so you'll have 18 a chance to come forward..... 19 MS. OLSON: No, I'd like to ask him as an expert witness. 20 CHAIR NORMAN: No, ma'am. We want to finish right now and 21 we've allowed you to ask a number of questions..... 22 MS. OLSON: But he continued his testimony and that's why 23 I wanted to ask him questions. 24 CHAIR NORMAN: Okay. We'll allow you to speak as soon as 25 we're finished here. Let me see if Commissioner Foerster has R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 97 . . 1 any further questions. 2 COMMISSIONER FOERSTER: I do. 3 MS. OLSON: Sir, would you then note that I did -- would 4 you read off the record what I submitted to you, the question? 5 CHAIR NORMAN: I will do -- I will do so, yes, but let's 6 let..... 7 MS. OLSON: Because right now it's not of record. 8 CHAIR NORMAN: Well, I'm going to make all of your 9 questions part of the record. All of them will be made part of 10 the record and all of them will be provided to the applicant. MS. OLSON: Well, that would give them the opportunity by bringing it forth now it would give them the opportunity to add to their testimony. 11 12 13 14 CHAIR NORMAN: Well, let's let -- let's let this portion 15 of the hearing finish. Let me ask Commissioner Foerster if she 16 has any further questions. 17 MS. OLSON: Okay. 18 COMMISSIONER FOERSTER: I did have one more question that 19 was -- I apologize, it was brought out really, really early and 20 I should have asked it a long time ago. I think Mr. Moothart 21 mentioned that there was a little, bitty, tiny track of land 22 that was not in the colville River unit that was part of 23 the. . . . . 24 MR. WIESS: Right I showed a -- as one of the early slide 25 I showed a picture that the pool rules area would cover a small R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 98 . . 1 track of land that was outside of the unit. 2 COMMISSIONER FOERSTER: And what's..... 3 MR. WIESS: But a portion -- a portion of that section of 4 land is inside and a portion is outside. 5 COMMISSIONER FOERSTER: Are you -- and can you expand the 6 unit or is it different ownership or..... 7 MR. WIESS: It's just consistency for maintaining that 8 entire track of land in there. 9 COMMISSIONER FOERSTER: Okay. 10 CHAIR NORMAN: Okay. Before you leave, Ms. Olson did have 11 a question concerning one of the slides that showed the 12 different casing, where a casing would be set and her question 13 relates to pressure tests on casing. And I'm going to answer 14 and then you can add to it, that different casings have 15 capability for containing different pressures so they are 16 different, but this is very carefully monitored. And it's an 17 excellent question. 18 It's very carefully monitor by the Commission and it's 19 also very carefully monitored by the Staff and the engineers do 20 watch the pressures. That's one of the critical things in 21 proceeding with good oil field management is maintaining well 22 integrity and being able to contain pressures. 23 MS. OLSON: Well, just maybe -- may I clarify. I don't 24 write well, that's one of my accommodations, so let me clarify 25 that. May I clarify that, the question I wrote? R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 99 . . 1 CHAIR NORMAN: You may -- let me let this witnesses now 2 finish..... 3 MS. OLSON: So I want to clarify my questions so they can 4 understand it. 5 CHAIR NORMAN: I'm going to give you an opportunity to 6 make a statement. 7 MS. OLSON: Okay, thank you. 8 ; CHAIR NORMAN: Nothing further from the Commissioners, SO 9 I, too, want to -- I think we all want to thank you. You've 10 made an excellent presentation. It's been very clear and 11 thorough and so I join with commissioners Seamount and Foerster 12 in commending you for a very good presentation. 13 If you'll remain here we'll go ahead and finish up. What 14 I'm going to do now is call upon and see if anyone else has a 15 statement. We'~l then take a recess to see if we have any 16 remaining questions and then we'll finish up. We are going to 17 run into the noon hour a bit, but I think that will be most 18 efficient rather than recessing and coming back after lunch. 19 Now, I'll ask if there are any members of the public or 20 anyone else present here including DNR that wishes to offer any 21 testimony, any statements? Is there anyone else that wishes to 22 offer any testimony? Okay. 23 MS. OLSON: You mean other than me, correct? 24 CHAIR NORMAN: Well, no, I did intend to include you if 25 you would like to have a statement..... R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 100 . . 1 MS. OLSON: Yes, I do. 2 CHAIR NORMAN: Okay. Please come forward, Ms. Olson. 3 MS. OLSON: For the record my name is Dana Olson. And I'm 4 going to ask for accommodation because I do have a short memory 5 and it's hard for me to remember all the things and this is why 6 I ask for the ability to ask questions because I can't 7 remember. Even when I write things, sometimes I can't 8 remember, so this may effect how I participate and that's why I 9 feel it should be of record when I did ask for the right to ask 10 questions, sometimes I was denied and I feel that you have not 11 accommodated my disability. And if you want to know more about 12 that, DNR is very familiar with it. 13 So I wanted to address the pressure thing, because you 14 said that the presentation was well done. Well, it was based 15 on if I looked at the type of presentation and I had to 16 categorize it, it's a comparative standard. And using that 17 type of format and presentation of using consistency then I 18 would have to object where the applicant has gone in and asked 19 for the means to have changes made while using a presentation 20 of a comparitable basis and consistency. That's that 21 violates any sense of logic that I'm aware of. You don't use 22 that type of presentation and then exempt yourself from it. I 23 would really have to object to that. 24 The second thing is this Rule 11 where it's stated that 25 they have the Commission -- that they want the Commission to R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 101 . . 1 ultimately exercise any changes of rules or approvals. While 2 I'm at this public participation I'm going to have to really 3 object to that. 4 The Administration Procedure Act doesn't allow for that 5 sort of thing. If you're going to call this a public process then the public you can't go in after the fact and change the rules of which the public already commented because they 6 7 8 brought them up, so I'm going to have to object 9 administratively to that. 10 I believe that the presentation is bringing forth policy 11 and not simply a regulatory. It's attempting to bring forth a 12 policy of maximum oil production and without an EIS on whether 13 or not the potential for earthquakes could be generated through 14 this theory. They have not presented any scientific evidence, 15 studies. They have not presented any witnesses testifying it 16 wouldn't, so I consider that this is really, kind of, a -- it's 17 a new policy formation that it's not before the public and I'm 18 going to have to raise any objection on that. 19 Obviously if you're maximizing it's not clearly defined 20 what that is, but unless you can tell you know, ultimately 21 prove without a reasonable doubt that it wouldn't cause 22 potentially earthquakes, then I'm going to have to -- you know, 23 I'm going to have to say that it's not properly before this 24 Commission because it wasn't first submitted as a policy 25 consideration. R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 102 . . 1 Let's see, if you'll wait, pardon me just a second. 2 CHAIR NORMAN: You take all the time you need, Ms. Olson. 3 MS. OLSON: I'm sorry, I -- sometimes..... 4 CHAIR NORMAN: That's quite all right. 5 MS. OLSON: .....1 lose track. Let's see, I guess I just 6 wanted to say on the record that, you know, I believe in 7 economy administratively, but there comes a point where it has 8 to be balanced for the pUblic's interest and this new policy 9 that is being brought forth, it's not -- it's not fair to be 10 simply a regulatory policy. This effects other agencies. 11 And I wanted to bring up the Constitution, the Alaska 12 Constitution under Article 8, section 9, Sales and Grants. 13 Obviously when you lease something out that's a grant to use 14 something. And under public policy grants are subject to other 15 provisions of law. And this is the problem I -- I face with 16 this is that under the statutes, statutory law the Commissioner 17 of Commerce and whatever the rest of his title is, is required 18 to confer with other agencies, the Governor for two things that 19 I wish to raise. 20 One is natural resources and this is a natural resources. 21 And two, justice. And I don't feel that the Commission is 22 capable of assessing the Equal Footing Doctrine because they 23 have basically set themselves up as continuously changing the 24 policy administratively during the proceedings themselves. And 25 this violates every civil Rights mandate you have to reasonably R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 103 . . 1 accommodate and you can't accommodate if you're changing the 2 law as you go, so there's no way that I can ask for 3 accommodation under the Equal Footing Doctrine. 4 There's no way I can ask for accommodation to my 5 disability. There's no means to address other civil Rights 6 things as my opportunity in business on the basis of being a 7 woman. There's no means for me to come before you. If there 8 is not others -- some other means in state law than this 9 process fails outright. 10 I mean, that's -- it will go federal because if you don't 11 have a means to address competition, if you don't have a means 12 to -- if these people are saying that you have the right to 13 change their thing administratively, then there can be no 14 competition in this state. There's none. It's a monopoly. 15 If you say that I can't reasonably ask other people -- the 16 process that I would utilize in DNR or by local governments, 17 the problem is -- one of the problems I find is that boroughs 18 don't have consistency under state law so if the..... 19 CHAIR NORMAN: Ms. Olson, you have -- you have about 20 another minute so why don't you summarize. We will carefully 21 consider everything you've said, but why don't you summarize 22 now the most important points of your testimony? 23 MS. OLSON: The inconsistency between boroughs and the 24 requirement of the..... 25 CHAIR NORMAN: Um-hum. R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 104 . . 1 MS. OLSON: .....Commissioner of Commerce to converse with 2 the boroughs and and to address justice and to address 3 natural resources. And I find that your rulemaking utterly 4 fails to do this. Not only did the applicant not seek this out 5 before coming before you, it is well versed in knowledge and 6 knows that it's violating state statutory law. 7 Secondtively (sic), I object to the format to go in and 8 use a consistency determination while at the same time 9 presenting to the Commission a request to alter it. That -- I 10 cannot comment on something that's not presented here today so 11 I'm going to object to that. Administratively I think that's a 12 violation of the procedure act. 13 CHAIR NORMAN: And your final point is what? 14 MS. OLSON: My final point is that until the other things 15 are done, even if you should grant approval it's still subject 16 to a legal review and public disclosure. Article -- like I 17 said, Article 8 under Sales and Grants requires adequate public 18 notice and I'm claiming that there's not adequate public 19 notice. Thank you. 20 CHAIR NORMAN: All right. Thank you very much, Ms. Olson. 21 What we will do now is take about a five minute recess. 22 We'll try to -- let's say 10 minutes, then we'll come back and 23 if there are any final questions of the applicant we'll try to 24 collect them and get them to you. I anticipate we'll probably 25 be able to wrap this up within the next 15 minutes or so. R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 105 . . 1 (Off record - 12:12 p.m.) 2 (On record - 12:18 p.m.) 3 CHAIR NORMAN: We're back in session. The time is 4 approximately 12:15 p.m. We have reviewed the information 5 submitted and it's our belief that we've, in the course of 6 these proceedings, had most of our, if not all of our questions 7 answered including what you submitted. 8 A member of the public has provided some written questions 9 and what I have indicated is these will be attached to the 10 official transcript of this meeting. And additionally we will 11 provide a copy of the questions to the Applicant and if you 12 wish to respond to any of them you may do so. 13 We're not going to make it a requirement that you respond, 14 but if you would care to do so you may respond, otherwise the 15 Commission will consider them made part of the record and we 16 will certainly consider them in the course of our 17 deliberations. 18 Do you have anything final, commissioner Seamount? 19 COMMISSIONER SEAMOUNT: No, I don't, Mr. Chairman. 20 CHAIR NORMAN: Commissioner Foerster? 21 COMMISSIONER FOERSTER: No. 22 CHAIR NORMAN: Okay. Again, well, I think it was an 23 excellent presentation, very well done, very well articulated 24 and laid out and so we thank you all. And we will issue our 25 order in due course. R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 106 . . 1 We're in recess -- or we're adjourned. 2 (Recessed - 12:20 a.m.) 3 1830 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 107 . . 1 C E R T I F I CAT E 2 UNITED STATES OF AMERICA ) ) ss. 3 STATE OF ALASKA ) 4 I, Rebecca Nelms, Notary Public in and for the State of Alaska, residing at Anchorage, Alaska, and Reporter for R & R Court Reporters, Inc., do hereby certify: 5 6 THAT the annexed and foregoing Public Hearing In the Matter of the Application of CONOCOPHILLIPS ALASKA for Pool Rules for Colville River Field, Proposed Nanuq Oil Pool and Proposed Nanuq-Kuparuk oil Pool was taken by Suzan Olson on the 4th day of October, 2005, commencing at the hour of 9:00 a.m., at the Alaska Oil and Gas Conservation Commission, Anchorage, Alaska; 7 8 9 10 THAT this Hearing Transcript, as heretofore annexed, is a true and correct transcription of the proceedings taken and transcribed by Suzan Olson; 11 12 IN WITNESS WHEREOF, I have hereunto set my hand and affixed my seal this 17th day of October, 2005. ~t.Q~~ Notary Public in and for Alaska My Commission Expires: 10/10/06 13 14 15 16 17 18 19 20 21 22 23 24 25 R & R C 0 U R T R E P 0 R T E R S 810 N STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 . ¿J.P ¿ø 6¿s- '. //c~- 35 ~.. . 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' . . lJo ~ ~ ~~-- "4~ //1-<- '. ..' ~~ ~~ we Ov- ~ Jtu;, r k- rY/I ~ . . Nanuq Pool Rules Hearing Agenda Introduction - Wiess L.ocation Pool Rules Request Backgr.ound Plan .of Development Geology - Moothart Reservoir - Bennett Annular Disposal- Moothart Well Construction - Noel Well Operations - Walker Facilities - Walker Wrap-up - Wiess .october 4, 2005 Oct 4, 2005 ~/ ConocoPhillips Page 1 .",./ ConocoPhillips Nanuq Pool Rules Hearing Page 2 1 . . ,.../ Co no coP hill ips Introduction October 4, 2005 Nanuq Pool Rules Hearing Page 3 October 4,2005 Nanuq Pool Rules Hearing Page 4 2 . . ..../ ConocoPhillips .october 4, 2005 Nanuq Pool Rules Hearing Page 5 Proposed Affected Area of Pool Rules COO iii ~ Colville River Unit .-J Q / ~ .. .J AlPine PA J r-. - - , ~-\ !II CD2 CO! " ., L .' I ... . - Page 6 3 . . Requested Pool Rules Conoc;Phillips 1. Field and pool name; 2. The pool definition; 3. Well spacing; 4. Drilling and completion practices; 5. Automatic shut-in equipment; 6. Reservoir pressure monitoring; 7. Gas-oil-ratio exemption; 8. Common production facilities and surface commingling; 9. Well testing; lO.Sustained case pressure; 11. Allowing for administrative action. October 4, 2005 Nanuq Pool Rules Hearing Page 7 Basis for Proposed Rules .... ConocoPhillips · Prevent Waste and Promote Conservation · Promote Correlative Rights · Promote Maximum Recovery · Consistency with Alpine and other North Slope Pools October 4,2005 Nanuq Pool Rules Hearing Page 8 4 . . WNS Key Events Conoc6Phillips October 4, 2005 Nanuq Pool Rules Hearing Page 9 Drill Site CD4 POD Overview ""." ConocoPhillips October 4, 2005 Nanuq Pool Rules Hearing Page 10 5 . . Drill Site CD4 Facilities Overview .".../ ConocoPhillips Standardized Drillsite Design · Application of experience from Kuparuk satellites · Trunk and lateral design, flexible well service tie-in, gravel for 27 wells · Test separator, production heater, chem injection, ESD, etc. · Pipelines: 14" production. 8" water injection, 6" gas lift and 6" MI · 3.8-mile road to C02 October 4, 2005 Nanuq Pool Rules Hearing Page 11 Gravel and On Pad Work · All Gravel Laid - High quality gravel · All On-pad VSMs installed · Mine site - (D1/2 cell reclaimed Gravel mine CD 1/2 cell CD4 pad and road October 4, 2005 Gravel mine CD 3/4 cell CD4 VSM/PiJes Nanuq Pool Rules Hearing Page 12 6 . . Alpine & Satellite Rig Schedule &f!,:}£.......' "'!!IIf't ConocoPhillips Jan 2004 Jan 2005 Jan 2006 Jan 2007 Jan 2008 Jan 2009 Early ice roads planned from CD2 to CD3 for drilling commencement in Dec/Jan 05/06-07/08 October 4, 2005 Nanuq Pool Rules Hearing Page 13 Nanuq Pool Rules Hearing Oct 4, 2005 Page 14 7 . . ^ "J~Y!~l~~^"fi~ld and.~Ç>QI,NªIn~§ '10-/ ConocoPhillips '··__T··'·,""'h_··~~"·,,,""""" Field Name: Colville River Field Two Defined Pools: N anuq Oil Pool Nanuq-Kuparuk Oil Pool October 4, 2005 Nanuq Pool Rules Hearing Page 15 North Slope Stratigraphic Column ....^^ ConocoPhillips SW NE .. Õ N o Z w u North stope Field. ÇQI]!JlLe River Field z_w cU sæ:ãi 0'::1 U/ /. /f·m!" /Ir z :I Ii ~ 1\ ~ \, IL \~~ ~ ~ .. :> o w u ~ '" .. West Sa k Tarn I Meltwater Nanuq Oil Pool "-...-.-.--"".-..,.-., , Kuparuk River Nanuq·Kuparuk Oil Pool .. ¡;; ~ :> ... Alpine TRIASSIC Z:ïu :5u -=:z I~ CiDer ';..1":&&1 id:.. Prudhoe Bay .--~""'...-".'.-'--"'-." PERMIAN 2 PENNSYLVANIAN ^^....................^ 32 lisburne En dicott MISSISSIPPIAN October 4, 2005 Nanuq Pool Rules Hearing Page 16 8 . . /:;:};', ''1jr'" Rule 2. Colville River Field Pool Definitions~ ConocoPhillips · Nanuq Oil Pool: - Accumulation of oil and gas common to and correlating to the interval found in the Nanuk No. 2 well between the depths of 7043 and 7223 feet measured depth. · Nanuq-Kuparuk Oil Pool: - Accumulation of oil and gas common to and corresponding to the interval found in the Nanuk No.2 well between the depths of 7956 and 7972 feet measured depth. October 4,2005 Nanuq Pool Rules Hearing Page 17 'i!'JanHCJI¥p~JQg{~aQlJq !,n,t~JY,êD . ....' ConocoPhillips _'_'__.w"c'''", ""'~'_'.'",M.'=^"_P"··"W Nanuk 2 October 4. 2005 GR Depth Resistivìty GAPf 150 MD 1 OHMM 100 7020 7040 7060 Õ 7080 C .2 0 7100 iã 0.. E Õ 7120 ... 0 CT u.. :J ~ C 7140 0 ftI ... Z 7160 0 ~ 71BO 7200 7220 7240 7260 Nanuq Pool Rules Hearing Top Nanuq 70..43· \,!çtbured Depth Base Nanuq 71'3' i\1easureJ Dep!h Page 18 9 . . Top Nanuq Depth Structure ConoccrPhillips October 4, 2005 Page 19 M .'..~Ãl}lIq~K,LJeªftl~Typ~u~2£l.."... 11> " ConocoPhillips _,_____^··__·,,·__·c-r-.~,.,~_ n ".~.".~,,~,_, 'MO= '-"',-."'-'=-"'-'-' n"'Ü'_"n_""'~ Nanuk 2 GR GAPI 150 Resistivity OHMM 100 Kuparuk C Interval 7940 Top Kuparuk C }q 56' "rC"sured Dcpth E u.. Kuparuk D . 3 Interval "- III Co ::I ~ 7960 Base Kuparuk C :9c2' Measm'('d !.)ept11 E u.. ..c: u III QI > ::I == 7980 8000 8020 October 4, 2005 Nanuq Pool Rules Hearing Page 20 10 e e Page 21-36 Confidential Of ConocoPhillips (Alaska), Inc. Testimony . . Conoc;Phillips CD4 Spider Diagram '\Ç,,~\.,\:~,:;-\\;,~.:m<' ,~_ , . ' ! ~-'~ C02 Pad ,e\.\ \;-~t~l~~~,.,90 ,,I}.!' \ -\ '; \\'~ " \ i-/\\. \\~,\\ " \ /-.~~, \\\\ \:/\ ~M~~~~"""<:":~ Pad \~$~t ~ Nanuq #5/ ,~ C:7::~C K; ~ L 5 Future Nanuq-Kuparuk Injector Future Nanuq-Kuparuk Producer Future Nanuq Injector Future NanuQ Producer Existing Alpine Well Existing Nanuq Well -~__:_c,,!,!,.~- .m......_. October 4, 2005 Nanuq Pool Rules Hearing Page 37 Production History ....... ConocoPhillips Nanuk No.2: April 2000 Exploration test; Vertical well completion in Nanuq West Fan and Kuparuk C intervals; Nanuq interval core retrieved; Special core analysis completed; Nanuq fluid samples with comprehensive PVT analysis; Nanuq interval was fracture stimulated; Pressure buildup test with complete PTA of Nanuq interval completed. 5 day production test: Nanuq + Kuparuk 1750 BOPD, 1000 BWPD, 1.2 MMCFD October 4,2005 Nanuq Pool Ruies Hearing Page 38 19 . General Reservoir Properties . ""'"/ ConocoPhillips October 4, 2005 Reservoir Top Structure (SSTVD ft) GOC (SSTVD ft) wac (SSTVD ft) Average Porosity (fraction) Average Oil Permeability (md) Average Net Pay (ft) API Gravity (degrees) Solution GaR (SCF/STB) Oil Viscosity (cp) Initial Pressure (psia) Items in nonnal text are measured values. Items shown in [brackets] are estimated. Nanuq Pool Rules Hearing Injection Fluid Miscibility 0.9 0.8 :5' 0.7 > ~ 0.6 @ 05 ~ ~ O.4-H o ~ 03 0.2 0.1 - October 4, 2005 Nanuq 6090 [ 6100 ] 6207 0.17 2.5 35 39 990 0.5 2740 Kuparuk 7100 None None 0.18 100 6 40 990 [ 0.5 3240 Page 39 'V" ConocoPhillips Simulated slimtube experiment results based on post- 2006 Alpine MI and Nanuk #2 oil composition. o ""1""1 000 o 0 LO 0 o o LO ~ o o o N o o LO N o o o '" Pressure, psia Nanuq Pool Rules Hearing o o LO '" " " i o 0 o 0 o LO '<t '<t , " , 1 ' " , 1 000 000 o LO 0 LO LO <0 Page 40 20 · . Reservoir Model Description Conoc;-Phillips Fully Compositional 3D Field Models Depth at Top of Structure 8-Component EOS 6000+ ft average horizontal well length Nanuq- 16 Well Horizontal Miscible WAG 7 Producers, 9 Injectors 1500' interwell spacing 30'10 HCPV MI Injection Six 5'10 Cycles WAG Ratio 0,5 Kuparuk- 3 Well Horizontal Miscible WAG 2 Producers, 1 injector 6000' interwell spacing 25% HCPV MI Injection Ten 2.5'10 Cycles WAG Ratio 1.0 October 4, 2005 Nanuq Pool Rules Hearing Page 41 CD4 Nanuq Rate and Reserves ..../ ConocoPhillips Reservoir Range of Original-Oil-In-Place (MMBO): Range of Original Gascap-Gas-In-Place (BCF): Range of Incremental Recovery %: Primary: Waterflood: Enhanced Recovery (MWAG): Total Recovery Fraction % Range of Ultimate Recovery (MMBO): Combined Ultimate Recovery Range: Combined Peak Rate Range Nanuq 84-169 0-40 Kuparuk 21-36 o 7-12 % 10-15% 9-14% 26-41 % 12-17% 25-37% 17-25% 54-79% 22-69 11-28 33-98 MMBO 10-15 MBOPD October 4, 2005 Nanuq Pool Rules Hearing Page 42 21 . . ConocJ"Phillips Proposed Conservation Order Pool Rules Selected rules pertaining to reservoir engineering: Rule 3. Well Spacing The requirements of 20 AAC 25.055 are waived for development wells in the Nanuq and Nanuq- Kuparuk Oil Pools. Without prior notification, development wells may not be completed closer than 500 feet to an external boundary where workinq interest ownership chanqes. Rule 6, Reservoir Pressure Monitoring (a.) Prior to regular injection, an initial pressure survev shall be taken in each injection well. (b.) A minimum of two bottom hole pressure surveys shall be measured annually in the Nanuq Oil Pool. A minimum of one bottom hole pressure survey shall be measured annuallv in the Nanuq- Kuparuk Oil Pool. (c.) The reservoir pressure datums shall be 6150 feet subsea for the Nanuq Oil Pool and 7000 feet subsea for the Nanuq-Kuparuk Oil Pool. (d.) Pressure surveys may consist of stabilized static pressure measurements at bottom-hole or extrapolated from surface pressure fall-off, pressure build-up, multi-rate tests, drill stem tests, and formation tests. (e.) Data and results from pressure surveys shall be reported annually on Form 10-412, Reservoir Pressure Report. All data necessary for the analysis of each survey need not be submitted with the Form 10-412 but shall be made available to the Commission upon request. Rule 7. Gas-Oil Ratio Exemption Wells producinq from the Nanuq Oil Pool and the Nanuq-Kuparuk Oil Pool are exempt from the qas-oil ratio limits of 20 AAC 25.240(b) so long as the provisions of 20 AAC 25.240(c) apply. October 4, 2005 Nanuq Pool Rules Hearing Page 43 ",/ ConocoPhillips Annular Disposal October 4, 2005 Nanuq Pool Rules Hearing Page 44 22 . . Annular ,>-,- ConocoPhillips · Upper Barrier . Upper Cretaceous Schrader Bluff Formation . 1000 feet of shale and siltstone · Surface casing set at -2350 ft sstvd · Annu!ar disposa! interva! .. Upper ('¡-cTal.'COUs Seabee (í.)¿ 'rofuk F(Hillalion .. 1800 fed of i¡rterhedded sandstone und sh:de .. Disp()sa! intefv8¡ is continuous {)ver s(;"veraj :r¡iics . Lower Barrier . > 1000 feet of shale & siltstone October 4, 2005 Nanuq Pool Rules Hearing Page 45 Annular )v" ConocoPhillips October 4, 2005 Nanuq Pool Rules Hearing Page 46 23 . CD3 CD3-108 Annular Disposal Interval: CD3-CD4 Cross-section ~ ~f';::?H ~"!!.'";L.:. Surface ' Casing . . October 4, 2005 CD1 CD1,22 ~ .". i··· C'" .... . ....... ConocoPhillips ~\~'4~:'· CD2 ALPINE 1 '"' ,...,.,." . ,( ....:j'.. j~ ~ .~ ~ ~."."_,,.w_ --- II '.. 5.3 Miles Nanuq Pool Rules Hearing CD4 NANUK 1 C-20 Page 47 Nanuq Pool Rules Hearing Well Construction Oct 4, 2005 Page 48 24 . . o:::Bj;¡\... .~ Nanuq - CD4 Development Drilling Plan ~ ConocoPhillips .~·.'"w~,,,-,,.··-,,,,·.·_·. _.y...,.,_"....._,_,,'M_·..·.,·.·.·.·····.··.·H''',' ". _mµp ,W ..._'._~ w,.Wo,-·,,--_'_'_''_,_.__,__'c .' _..,..._..._..._......__ ".oN",,,·" ..~- ,.__..~,'_..."........,....-._.._. .'_'.".,o,·.~··_, _k,···. M', ""=~, _,_.' ··~.w,._~_·,·._·.·._"._.-.._.y"c.,~c·~w, _r--r ~o~w"'",.·.·.-..w_·._.__·__·"WN".·..P"..~ ·._~W ~UM__..wû,,~,,",,·",^ 'n....". -.,'_'C,'k. -''0'' "..." '"'W.,.." Nanuq - 9 producers / 7 injectors · 6000' to 7000' horizontals . Undulating (up to 6 passes through pay) · Water/mineral oil drill-in fluids · Slotted liner - Flowback/production test first well to evaluate completion Kuparuk - 2 producers / 1 injector · 4800' to 7000' horizontals · Water based drill-in fluid · Slotted liner - Pulse test early 2006 October 4, 2005 Nanuq Pool Rules Hearing Page 49 Nanuq - CD4 Development Well Comparison with Alpine ...., ConocoPhillips 22 Average Depth wI Min-Max Bars 20 ' 18 ' 16, 14 ' Qj Q - ~ 12 c: '" en '" 10, o ~ I- 8 - 6 ' 4 ' 2 ' Nanuq October 4, 2005 Nanuq Pool Rules Hearing ElTotal Depth IØ 7" Csg Depth o Departure Cl Horjz Length Alpine Page 50 25 . . Nanuq .. CD4 Drilling Practices y' ConocoPhillips · Directional surveys with MWD · Open hole logging by LWD · Horizontal wellhead system - single BOP rig up · Typical North Slope muds - Water based spud mud (surface hole) - Low solids non-dispersed (intermediate hole) - Water or mineral oil base drill-in fluid (horizontal hole) · Annular disposal - No USDW's - Ball mill: wash surface gravels, grind cuttings for slurry - Disposal interval (top Seabee Formation) exists below surface casing shoe - Wells permitted and approved under 20 MC 25.080 for annular disposal October 4, 2005 Nanuq Pool Rules Hearing Page 51 Nanuq .. CD4 Drilling Plan )-;iib,. 1,¡r',- ~:ft. ConocoPhillips · 20' Well centers · 80' Insulated conductor, cemented in place and thermo-siphons · Surface casing at +/-2400' tvd and cemented back to surface · Single stage cement job, port collar or top job as contingency · Install & test BOPE before drilling out casing shoe · Drill ahead <50' and perform LOT · Directional drill intermediate hole to land horizontal in reservoir · Set production casing in zone and cement · Drill out <50' and perform FIT · Drill horizontal section · Run slotted liner · Run cement quality log on injectors · Run tubing/packer completion October 4, 2005 Nanuq Pool Rules Hearing Page 52 26 . . Nanuq - CD4 Well Completion Schematics·~, Conoc;Phillips CD4 . NanuqlKuparuk Sand Producer Completion CD4 . Nanuq/Kuparuk Sand Injector Completion I I l'l 1,1 I 4-V, DB Nipþlfl wi A-1 ¡nj..dicn va"'" at.I-2OOQ'rvO 9-5iS"40ppfL·80STCMSurfacøC"s;ng ¡¡t.¡·2400'TvD,cemenledtosllrf<tœ 9-51!-40PpfL-80BTCMSurfKIICasing iil.¡.24OO'TVD,œ"",ntedlcsurfa<:.e :Þ~ GlM's a! '1'3400', 5700' rve aM abOve 0""".., ~ 111 '''n'''''.''~U'''MOO.",,", 4·Y'126ppfL·80IIHM<>d.tllb'''!I I \ \ 4-W12,6pprL·80IBTMod,M)'ttg October 4, 2005 r"26 ppfc.-ao BTC Mad ProdlldionCasing@.i. '" J.- YO 9.3l..ao ppr SLHT ~..... 4.:..-\2.6ppll-<JOSll-lTliner wI~~~':,;::,.=,:ar<l Nanuq Pool Rules Hearing Liner!opnanger llner\op.~an9"" TopR.........oital.¡· 6200'rvO Nan"'! 7'OO'TVO KuparuK iJ11iummuu:¡¡ ! iDJIDß1'D:U SOQ( _1DOO' MO Horimntlll TopR..."",oir..I-¡· 62OO'-rVD Nanuq 7'OO'TVD KUPIINk ¡u ¡¡¡O" lOb u. I ~JjUUUD:iJl 5000·7000' MD Horizgntal r"ZSppfL·8QBTCMod ProducticnCa.ing@+i. ,.. 4.:,- :~~~~~$~~:;:r $~l$_"ená Page 53 Nanuq - CD4 Proposed Rule 4 Drilling and Cqº"R~~tjp,g,J~r~~lc~~ .~. ~.'.'. ,... .."".... d. ..... ConocoPhillips ,·"..··_··_·,·_·,_·.,·.·"'·w·_··,.···..··"_,·,·^· .'·~·~,·_·.·_·__·_·M'··.' _..n__n"'""_....., a) After drilling no more than 50 feet below a casing shoe in the Nanuq Oil Pool or the Nanuq-Kuparuk Oil Pool, a formation integrity test must be conducted. The test pressure need not exceed a pre-determined pressure. b) Casing and completion designs may be approved by the Commission upon application and presentation of data that demonstrate the designs are appropriate and based on sound engineering principles. c) Permits to drill deviated wells shall include a plat with a plan view, vertical section, close approach data and a directional program description in lieu of the requirements on 20 AAC 25.050 (b). d) A complete petrophysical log suite acceptable to the Commission is required from below the conductor to TD for at least one well in lieu of the requirements of 20 AAC 25.071 (a). October 4, 2005 Nanuq Pool Rules Hearing Page 54 27 . . Nanuq .. CD4 Backup Information ~.. Conoc;Phillips P" 1 Nanuq Pool Rules Hearing Page 55 October 4, 2005 Nanuq CD4..208 Well Plan ...... ConocoPhillips 00:;0 C2:;O CD4-208 Well Plan .. October 4, 2005 6900 Ft Nanuq Pool Rules Hearing .. Page 56 28 . . WNS Drilling Schedule .../ ConocoPhillips Jan 2004 Jan 2005 Jan 2006 Jan 2007 Jan 2008 Jan 2009 Early ice roads planned from CD2I4 to CD3 for drilling commencement in Jan each year October 4, 2005 Nanuq Pool Rules Hearing Page 57 Nanuq Pool Rules Hearing Oct 4, 2005 Well Operations & Facilities Page 58 29 . . Drillsite CD4 Well Design features ..../ ConocoPhillips · Production wells - Slotted liner completion with blanks across non-pay - Gas lift - Surface-controlled subsurface safety valves - Surface safety valves - Wellhead hydraulic panels - Automated divert valves for testing, production chokes & gas lift chokes · Injection wells - Slotted liner completion with blanks across non-pay - Inject water or miscible injectant via manual isolation - Differential pressure-operated, subsurface-controlled safety valve - Surface safety valves - Wellhead hydraulic panels October 4, 2005 Nanuq Pool Rules Hearing Page 59 Proposed Rule 5 Automatic Shut-in ~./ ConocoPhillips (a.) All production wells must be equipped with a fail-safe automatic surface safety valve (SSV) and a surface- controlled subsurface safety valve (SSSV). Injection wells, including WAG, GINJ, and WINJ service wells per Form 10-407 well completion report must be equipped with either a double check valve arrangement or a single check valve and SSV. A subsurface-controlled injection valve satisfies the requirement of a single check valve. Safety valve systems must be tested on a six-month frequency. Sufficient notice must be given so that a representative of the Commission can witness the tests. Subsurface safety valves may only be removed after demonstrating to the Commission that the well is not capable of unassisted flow of hydrocarbons. Sufficient notice must be given so that a representative of the Commission can witness the tests. (b.) (c.) (d.) October 4, 2005 Nanuq Pool Rules Hearing Page 60 30 . . Drillsite CD4 Well Surveillance "....' ConocoPhillips · Wellhead (tubing) pressure and temperature · Inner and outer annuli pressures · Producer tests twice per month · Continuous measurement of single phase streams - Gas lift for producers - Water and gas injection for injectors October 4, 2005 Nanuq Pool Rules Hearing Page 61 Proposed Rule 10 Sustained Casing Pressure '" " ConocoPhillips (a) The operator shall conduct and document a pressure test of tubulars and completion equipment in each development well at the time of installation or rep'lacement that is sufficient to demonstrate that planned well operations will not result in failure of well integrity, uncontrolled release of fluid or pressure, or threat to human safety. The operator shall monitor each develop.ment well daily to check for sustained pressure, except if prevented by extreme weather conditions, emergency situations, or similar unavoidable circumstances. Monitoring results shall be made available for Commission inspection. The operator must notify the Commission within three working days after the operator identifies a well as havingJi) sustained inner annulus p'ressure that exceeds 20QO psig, or (ii) sustaine outer annulus pressure that exceeds 1000 pSlg. The Commission may require the operator to submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action or increased surveillance for any development well having sustained pressure that exceeds a limit set out in part (C) of this rule. The Commission may approve the oJ;!erator's prop'osal or may require other corrective action or surveillance. The Commission may require that corrective action be verified by mechanical integrity testing or other Commission approved diagnostic tests. The operator shall give Commission sufficient notice of the testing sChedule to allow Commission to witness the tests. (b) (c) (d) October 4, 2005 Nanuq Pool Rules Hearing Page 62 31 October 4, 2005 . . Rule 10 Sustained ''\0'/ ConocoPhillips con (e) If the operator identifies sustained pressure in the inner annulus of a development well that exceeds 45% of the burst pressure rating of the well's production casing for inner annulus pressure, or sustained pressure in the outer annulus that exceeds 45% of the burst pressure of ttie well's surface casing for outer annulus pressure, the operator shall notify the Commission within three working days and take corrective action. Unless well conditions s require the operafor to take emergency, corrective action the Commission approval can be obtainedl the o¡;>erãtor shall submit in an Application for Sundry Approvals (Form 0-403) a proposal for corrective action. The Commission may approve the operator's proposal or may require other corrective action The Commission may also require that corrective action be verified by mechanical integrity testing or other Commission approved diagnostic tests. The operator shall gIve Commission sufficient notice of the testing schedule to allow Commission to witness the tests. (f) Except as otherwise approved by the Commission under part (d) and (e) of this rule before a shut-In well is placed in service, any annulus pressure must be relieved to a sufficient degree (j) that the inner annulus pressure at operating temperature will be below 2000 psig and (jj) that the outer annulus pressure at operating temperature will be Delow 1000 psig. However, a well that is subject to pan: (c), but not part (e), of this order may reach an annulus pressure at operating temperature that is described in the operator's notification to the Commission under part (c), unless the Commission prescribes a different limit. For purposes of these rules, '"inner annulus" means the space in a well between tubing and production casing; "outer annuls" means the space in a well between the production casing and surface casing; "sustained pressure" means pressure ttiat (i) is measuralJle at the casing head of an annulus, (jj) is not caused solely by temperature fluctuations, and (Iii) is not pressure tHat has been applied intentionally. (f) (g) Nanuq Pool Rules Hearing Page 63 .... ConocoPhillips Drillsite CD4 On-Pad Facilities · Trunk and lateral design, flexible well service, gravel for 27 wells · Headers for production & test, lift gas, water injection, miscible injectant · Test separator · Production heater · Chem injection system · Emergency shutdown skid October 4. 2005 Drillsite Plan View Nanuq Pool Rules Hearing Page 64 32 . . Drillsite CD4 Cross-Country Facilities "'/ ConocoPhillips · 3.8-mile gravel road to Drillsite CD2 · 13.8 kV power line from ACF · 8" water injection pipeline from ACF · 6" gas lift pipeline from ACF · 6" miscible injectant pipeline from ACF · 14" production pipeline to Alpine Central Facility (ACF) October 4, 2005 Nanuq Pool Rules Hearing Page 65 CRU Production Allocation Overview ....' ConocoPhillips · Aggregate volumes based on continuously metered streams: - Oil production - Fuel gas - Enriching fluids - Lean gas injection - Produced water, etc. · Aggregate volumes are allocated to individual wells: - Injector allocations based on metered single phase - Producer allocations based on well tests & operating conditions · Allocation Factor generally defined: Vti = Theoretical volume for well i VtCRU = 'i.Vti Vaggregate = aggregate volume transferred, injected, etc. AF = Vaggregate / V tCRU Allocated volume for well i, V Ai = AF Vti October 4, 2005 Nanuq Pool Rules Hearing Page 66 33 . . Proposed Rule 8 Common Production Facilities and Surface ..../ ConocoPhillips Production from the Nanuq Oil Pool, Nanuq- Kuparuk Oil Pool, and Alpine Oil Pool may be commingled on the surface prior to custody transfer. Production shall be allocated to each pool on the basis of well testing and producing conditions for each well. October 4, 2005 Nanuq Pool Rules Hearing Page 67 ~~~I!~!~,~"!!!!,~~"~,~~I~""I~!~i~g ....-- ConocoPhillips yT'·,··'·,·_···,,,_..·,,··.....,..,_ ',·^""",,".,m,~...'_·r_T_'· ,·_~ww,',_"_.·.w.,,·.,,·_·_·m (a.) All producing wells must be tested at least twice per month. (b.) Stabilization and test duration times will be managed to obtain representative tests. (c.) Operating conditions shall be recorded appropriate for maintaining accurate field production history. (d.) Records to allow verification of production allocation methodologies shall be maintained and be made available to the Commission upon request. October 4, 2005 Nanuq Pool Rules Hearing Page 68 34 . . October 4, 2005 Nanuq Pool Rules Hearing Page 69 Requested Pool Rules ConocJ"Phillips Rule 11. Administrative Action Upon proper application of its own motion, the Commission may administratively waive the requirements of any rule stated above or administratively amend this order. October 4, 2005 Nanuq Pool Rules Hearing Page 70 35 . Requested Pool Rules 1. Field and pool name; 2. The pool definition; 3. Well spacing; 4. Drilling and completion practices; 5. Automatic shut-in equipment; 6. Reservoir pressure monitoring; 7. Gas-oil-ratio exemption; 8. Common production facilities and surface commingling; 9. Well testing; 10.Sustained case pressure; 11. Allowing for administrative action. October 4, 2005 Nanuq Pool Rules Hearing . ..../ ConocoPhillips Page 71 36 ~. . ConocoPhillips . Chris Alonzo Development Supervisor, WNS ConocoPhiUips Alaska 700 G Street Anchorage, AK 99501 Phone: 907.276.1215 September 28, 2005 RECEIVED Sr:p I) f'l "!- ..41 ,1 Mr. John Norman, Chair Alaska Oil and Gas Conservation Commission 333 West ih Avenue, Suite 100 ~chorage,AJ( 99501 Ala~ka Oil &. Gas CDí!!L Commi3siof; Anchorage Re: Additional Commission Questions and Comments and Affected Area for Proposed Nanuq and Nanuq-Kuparuk Oil Pools Colville River Field Dear Mr. Norman: On August 11, 2005, ConocoPhillips Alaska, Inc. as operator of the Colville River Unit provided information to the commission relating to the classification of Nanuq and Nanuq-Kuparuk reservoirs as oil pools. Mr. Steve Davies communicated public hearing expectations as well as additional commission questions and comments regarding Nanuq pool rules. Attached to this letter are our responses to the additional questions and comments. We ask the commission to keep confidential the material marked "confidential" because it includes interpretations beyond the unit boundary. After consideration of commission comment, we would like to revise our proposal for rule 3 to: Rule 3. Development wells may not be completed closer than 500 feet from the exterior boundary where working interest ownership changes. In the August 11, 2005 information, we included a proposed area to be affected by conservation order(s) for the proposed oil pools. We would like to make a downward revision the proposed area as shown on the attached map and listed below: Meat Meridian T1lN R4E Sections 1,2,3,4,9, 10, 11, 12, 13, 14, 15, 16,21,22,23,24,25,26,27, 28,33,34,35,36 T11NR5E Sections 3, 4, 5,6, 7,8,9,10,15,16,17,18,19,20,21,22,27,28,29,30, 31,32,33,34 T10N R4E Sections 1~ 2 . T10N R5E Sections 3; 4; 5,'6 ' We would be happy to answer any questions you may have. Please call me at 265-6268 or Jack Walker at 265-6268. Very truly yours, ~~ Chris Alonzo Development Supervisor, Western North Slope ConocoPhillips Alaska, Inc. Attachments . . Additional Commission Questions and Comments and Affected Area for Proposed Nanuq and Nanuq-Kuparuk Oil Pools Colville River Field September 28, 2005 Page 2 cc Anadarko Petroleum Corporation Mr. William Shackelford 1201 Lake Robbins Dr. The Woodlands, TX 77380 Arctic Slope Regional Corporation Ms. Teresa Imm 3900 C Street, Suite 801 Anchorage, Alaska 99503-5963 Kuukpik Corporation Mr. Isaac Nukapigak, President P. O. Box 187 Nuiqsut, AK 99789-0187 Department of Natural Resources Division of Oil and Gas Mr. Mike Kotowski 550 West 7th Ave, Suite 800 Anchorage,AK 99501 Colville River Unit .-11 Proposed Area for Nanuq and Nanuq-Kuparuk Oil Pools fJ I r q Alpine PA r---, J r-" J CD1 ,- III C02 , L 1'1 CD3 . .... I ~ ., L III' I ... .. r" - Proposed Affected Area For Nanuq Area Injection Order(s) Preliminary Nanuq Participating Area . . · e j.. Supplemental Information filed by ConocoPhillips (Alaska), Inc. held Confidential #7 [rwd: Kl:.: Nanuq Kecovenesj e e Subject: [Fwd: RE: Nanuq Recoveries] From: Jane Williamson <jane_williamson@admin.state.ak.us> Date: Tue, 14 Feb 2006 10:02:32 -0900 To: Jody J Colombie <jody_colombie@admin.state.ak.us> CC: Stephen F Davies <steve~davies@admin.state.ak.us> Please put this in the Nanuq and Nanuq-Kuparuk files. -------- Original Message -------- RE: Nanuq Recoveries Tue, 10 Jan 2006 13:23:51 -0900 Walker, Jack A <Jack.A.Walker@conocophillips.com> Jane Williamson <jane williamson@admin.state.ak.us> Subject: Date: From: To: No downhole coœmingling planned on injection or production. Injection will have a common source on the surface and production will be coœmingled in the surface manifold. Jack -----Original Message----- *From:* Jane Williamson [ma~lto:Jane williamson@admin.s~ate.ak.us] *Sent:* Tuesday, January 10, 2006 12:57 PM *To:* Walker, Jack A *Subject:* Re: Nanuq Recoveries One other ques~ion. Is your plan to have separate injectors for Nanuq and Kuparuk reservoirs, or do you plan to co~~ingle injection? I may have missed it but I didn't see anything in your applica~ion on this. Walker, Jack A wrote: When I first heard the projected recoveries for Nanuq-Kuparuk, they seemed high to me, too. The reservoir is described as thin with high permeability and relatively homogeneous. The waterflood mobility and the response to miscible injectant are favorable. The reservoir description and fluid characterization lead to prediction of the recovery factors we cited. Would be nice to find more OOIP... Jack PS: The MWAG recovery is incremental to waterflood as you assumed. -----Original Message----- *From:* Jane Williamson [mailto:jane williamson@admlD.stace.ak.us] *Sent:* Tuesday, January 10, 2006 9:39 AM *To:* Walker, Jack A *Subject:* Re: Nanuq Recoveries OK. I was just wondering about the Nanuq-Kuparuk recoveries . Assuming 10-15% primary, incremental waterflood recovery of 25-37% and incremental MWAG recovery of 17-25% (I assume incremental to waterflood), I calculate between 52% and 77% recovery. This seems really high to me. It's not that important for the order. r was just curious and wanted to make sure I didn't report incorrect values within the findings. Walker, Jack A wrote: Jane, r looked at the Nanuq & Nanuq-Kuparuk recoveries in the AIO application. The recovery factors on p. 18 were what we intended. The ranges reported was based on judgement of the reservoir engineer after running many, many sensitivities. -,- J. of2 2!l7/2006 1:06 PM [Fwd: RE: Nanuq Recoveries] e e believe they are consistent with the testimony offered in the public hearing of October 4 (po 42 of the ppt file). I'll touch base tomorrow. Jack Jane Williamson, PE <jane williamson((V,admin.state.ak.us> Reservoir Engineer Alaska Oil and Gas Conservation Commission :of2 2/17/2006 1:06PM ..."--"-'. .... '~"""""'"1 ~ ..........~ .......J..................,...... .......,... ............. .. .................I...Vl.U.....I. '..(1.A.......o.Jl.lV.J...J ...v. ........t-'V.l. ........V.l. e e Steve, Responses to Nanuq AIO questions: 1. The Nanuq sandstone is a very fine to fine-grained, lithic sandstone (litharenite). The average composition of the framework grains is 45% quartz,8% feldspar and 45% lithic rock fragments and detrital minerals. Detrital matrix within the sand ranges from 1-10%. The detrital matrix consists predominantly of clay minerals with local patches replaced by siderite cement. The clays present consist of illite/mica (11%), chlorite (7%), kaolinite (2%). Mixed layer illite/smectite clays only account for 1-2% and are mostly illite with 20-30% smectite layers. Clay swelling is not expected to be significant based on experience with similar clays in other Brookian reservoirs and Nanuq core flood studies. Secondary sandstone cementation is generally localized and patchy based on control from core and existing wells. Various core and log analyses indicate the Nanuq-Kuparuk interval is a Kuparuk C Sand very similar to Kuparuk C Sand found in the Kuparuk River Unit (KRU). Based on extensive experience with Kuparuk C Sand injection operations at the KRU and the similarity of Nanuq-Kuparuk, clay or fines are not expected to influence reservoir performance of the Nanuq-Kuparuk pool. 2. There is no Rvidence that treated seawater or treated produced waters will be incompatible among any of existing and proposed pools in the Colville River Field. Please call or reply with any further questions. Jack Walker ConocoPhillips Alaska, Inc. North Slope Development -----Original Message----- From: Stephen Davies [~ailto:stev2 davies@admin..state.ak. Sent: Wednesday, January 11, 2006 9:01 AM To: Walker, Jack A Cc: Tom Maunder¡ Jane Williamson Subject: Re: Nanuq Area Injection Order: Additional Questions for Operator Jack, A couple of final questions concerning the Nanuq and Nanuq-Kuparuk AIO's: 1. Is there any evidence of clay or other fine materials that may swell or mobilize and influence reservoir performance in either the Nanuq or Nanuq-Kuparuk Oil Pool? If they are present, could you please provide descriptions and percentages? 2. Do you have any evidence that produced or blended, produced water from the Nanuq, Nanuq-Kuparuk, Alpine, or even Fiord would be incompatible with the Nanuq or Nanuq-Kuparuk reservoirs? Thanks for your help, lof2 1119/20068:45 AM Á'-.L.J. J. ~.......u.......'1. ¿ ......""u. ......J.J""""I.J.VU. '-JJ.u....J.. J.. .l..u'"-'J.....¡vJ.J.U,¡ '-.,,(U."-'...>1.1V¡J.J i.Vl Vp.....¡ULV1. e e Steve Davies Petroleum Geologist Alaska Oil & Gas Conservation Commission 907-793-1224 Walker, Jack A wrote: Steve, Enclosed is a draft response. to the Chairman. We'll follow up with a paper transmittal Jack -----Original Message----- From: Stephen Davies es©admin.s~ate.ak,~s Sent: Friday, October To: Walker, Jack A Cc: Tom Maunder; John Hartz Subject: Nanuq Area Injection Order: Additional Questions for Operator Jack, Attached are a few more questions from AOGCC concerning the Nanuq Area Injection Order, I apologize for the delay in getting them to you. These are the last few questions we have prior to completing the order. The public hearing scheduled for Tuesday, Nov. 1 has been vacated. Please call me at 793-1224 if you have any questions. Sincerely, Steve Davies Petroleum Geologist Alaska Oil & Gas Conservation Commission 20f2 1I19/2006 8:45 AM e e Subject: Re: Nanuq Area Injection Order: Additional Questions for Operator From: Stephen Davies <steve _ davies@admin.state.ak.us> Date: Wed, 11 Jan 2006 09:00:51 -0900 To: "Walker, Jack A" <Jack.A.Walker@conocophillips.com> CC: Tom Maunder <tom_maunder@admin.state.ak.us>, Jane Williamson <Jane_ Williamson@admin.state.ak.us> Jack, A couple of final questions concerning the Nanuq and Nanuq-Kuparuk Ala's: 1. Is there any evidence of clay or other fine materials that may swell or mobilize and influence reservoir performance in either the Nanuq or Nanuq-Kuparuk Oil Pool? If they are present, could you please provide descriptions and percentages? 2. Do you have any evidence that produced or blended, produced water from the Nanuq, Nanuq-Kuparuk, Alpine, or even Fiord would be incompatible with the Nanuq or Nanuq-Kuparuk reservoirs? Thanks for your help, Steve Davies Petroleum Geologist Alaska Oil & Gas Conservation Commission 907-793-1224 Walker, Jack A wrote: Steve, Enclosed is a draft response. We'll follow up with a paper transmittal to the Chairman. Jack -----Original Message----- From: Stephen Davies [mailto:steve davies@admin.state.ak.us] Sent: Friday, October 28, 2005 2:43 PM To: Walker, Jack A Cc: Tom Maunder; John Hartz Subject: Nanuq Area Injection Order: Additional Questions for Operator Jack, Attached are a few more questions from AOGCC concerning the Nanuq Area Injection Order. I apologize for the delay in getting them to you. These are the last few questions we have prior to completing the order. The public hearing scheduled for Tuesday, Nov. 1 has been vacated. Please call me at 793-1224 if you have any questions. Sincerely, Steve Davies Petroleum Geologist Alaska Oil & Gas Conservation Commission l of 1 1/1112006 11 :27 AM l" ",-. ...~. ... ._a.._-.. ......--....... _....-~j e e Subject: [Fwd: RE: Nanuq Recoveries} From: Jane Williamson <jane _ williamson@admin.state.ak.us> Date: Tue, 10 Jan 2006 13:32:05 -0900 To: Thomas E Maunder <tom_maunder@admin.state.ak.us>, Stephen F Davies <steve_davies@admin.state.ak.us> I think we should take out the rule on injection commingling. They can come to us later if they wish to do it, with justification. -------- Original Message -------- RE: Nanuq Recoveries Tue, 10 Jan 2006 13:23:51 -0900 Walker, Jack A <Jack.A.Walker@conocophillips.com> Jane Williamson <jane williamson@admin.state.ak.us> Subject: Date: From: To: No downhole commingling planned on injection or production. Injection will have a common source on the surface and production will be commingled in the surface manifold. Jack -----Original Message----- *From:* Jane Williamson [mailto:jane williamson@aQ~in.state.ak.usJ *Sent:* Tuesday, January 10, 2006 12:57 PM *To:* Walker, Jack A *Subject:* Re: Nanuq Recoveries One other question. Is your plan to have separate injectors for Nanuq and Kuparuk reservoirs, or do you plan to commingle injection? I may have missed it but I didn't see anything in your application on this. Walker, Jack A wrote: When I first heard the projected recoveries for Nanuq-Kuparuk, they seemed high to me, too. The reservoir is described as thin with high permeability and relatively homogeneous. The waterflood mobility and the response to miscible injectant are favorable. The reservoir description and fluid characterization lead to prediction of the recovery factors we cited. Would be nice to find more OOIP... Jack PS: The MWAG recovery is incremental to waterflood as you assumed. -----Original Message----- *From:* Jane Williamson [mailto:jane williamson@aQ~in.state.ak.us] *Sent:* Tuesday, January 10, 2006 9:39 AM *To:* Walker, Jack A *Subject:* Re: Nanuq Recoveries OK. I was just wondering about the Nanuq-Kuparuk recoveries . Assuming 10-15% primary, incremental waterflood recovery of 25-37% and incremental MWAG recovery of 17-25% (1 assume incremental to waterflood), I calculate between 52% and 77% recovery. This seems really high to me. It's not that important for the order. I was just curious and wanted to make sure I didn't report incorrect values within the findings. Walker, Jack A wrote: Jane, I looked at the Nanuq & Nanuq-Kuparuk recoveries in the AIO application. The recovery factors on p. 18 were what we intended. The ranges reported was based on judgement of the reservoir engineer after running many, many sensitivities. I believe they are consistent with the testimony offered in the public hearing of October 4 (p. 42 of the ppt file). I'll touch base tomorrow. Jack 10f2 1/11120067:48 AM 1'1\.4.1..'"'....'1.1. VVI. J,.'-\.,U.""'J. ... ...,.IJ.I.."'" ......""U.....5 J.....¡^-f-'''''''LUL!V...> U.l.lU ,C1.UU.L.V..U.! '-.¿\J.\";.:t... e e Jack, The Alaska Oil and Gas Conservation Commission's ("Commission") order process establishes rules and exceptions to statewide regulations in 20 AAC 25 to govern efficient, safe production practices for maximizing ultimate resource recovery. The Commission is required to perform its duties to the protect public interest in a public forum. A public hearing has been requested concerning the Nanuq pool rules. This hearing will be held on October 4, 2005 at 9 AM. The Commission will shortly publish on our web site a set of expectations for pool rules hearings. The following rough draft of those expectations will help ConocoPhillips prepare for the hearing. Public Hearing Expectations In order to ensure that adequate information is provided to the Commission and the public during a hearing, the applicant must prepare and present testimony of sufficient detail to allow the Commission to establish governing rules. This testimony must be prepared and presented by representatives capable of addressing detailed Commission questions and comments concerning the following topics: 1. Ownership and lease issues 2. Confidentiality issues: identify specific exhibits and testimony, justify each request 3. Geology and geophysics 4. Reservoir description, rock and fluid properties, reservoir modeling 5. Hydrocarbon-in-place, recovery factors, reserves 6. Production mechanisms 7. Production: historical and projected 8. Well construction 9. Development Plans 10. Facilities, including metering 11. Specialized waivers: request and justify In addition to displays used to illustrate technical discussions, the applicant must also supply a legible base map that will be used during the hearing to identify key geographic features and key elements of the proposed project. Additional Commission Questions and Comments Upon further review of ConocoPhillips' application and supplemental information, the Commission has identified several questions and comments that should be addressed, either in writing before the public hearing or within the oral testimony at the hearing. 1. Will the proposed development include wells that encroach within 500' of existing unit boundaries, PA boundaries, or property lines where ownership or landownership changes? If so, why is this? 2. Have all affected working interest ownership, landownership, surface ownership issues been successfully addressed and resolved? Have all issues with the Alaska DNR been successfully addressed and resolved? 3. In ConocoPhillips' application, Proposed Conservation Order Rule 3, well spacing, requests a 300' set back from external boundaries where working interest ownership changes. Every other order issued by the Commission specifies at least a 500' set back from such boundaries. Please provide technical justification for this request. lof2 9/26/2005 11 :55 AM L ............_~.... .............. ..........-<-....U. ... .......,-<-.J..... .................J.J...&..J.5 .'-J.t\.p.....""...""'...J.vJ.J.o..J UJ.J.U 1. 1.UU.J.L-J.VJ.J.UJ: ~u""~... e e 4. If the nature of the Nanuq is stratigraphic, wouldn't more pressure surveys be required to determine reservoir compartmentalization? The reservoirs appear to cover 6 to 10 sections (between 3800 and 6400 acres). The proposed reservoir pressure surveillance program calls for 2 surveys per year. In light of the apparent influence of stratigraphy over this pool, a minimum of 4 or 5 would seem more appropriate, especially during the early years of development. 5. CPAI is proposing to obtain initial pressures in only injection wells. Why are pressure surveys not planned in production wells? An initial static survey in wells drilled after production start up will document early pressure performance. 6. Why not develop the portion of the reservoir to the southwest at this time? 7. Proposed Conservation Order Rule 7 is a re-statement of existing regulations. 8. Proposed Conservation Order Rule lOb does not specify monitoring frequency. Please contact me if you need additional information. Sincerely, Steve Davies Alaska Oil and Gas Conservation Commission (907) 793-1224 20f2 9/26/2005 11 :55 AM J. '''4.1.1......'1 J. "PPJ.H",",U.J.VJ..1J e e Jack, After reviewing the pool rules draft application, we have the following questions: 1. Could you please describe, in language that can be made part of the public record, the overall structure and trap configuration of the Nanuq and Nanuq-Kuparuk reservoirs? 2. Could you please provide separate estimates of OOIP and an approximate recovery factor for each reservoir for the public record? 3. Is there a rough magnitude of difference in recovery factor between vertical development versus horizontal well development? (ref sec 1.3) 4. There should be a brief description of the allocation process and or basic equations that will be used for allocating total production back to the pool then the wells. This will help us understand any sensitivities with respect to correlative rights and tax or royalty issues prior to production start up. (ref sec 3.0) 5. Please provide compositional assays of the oil and gas from each pool as exhibits. 6. A shallow zone identified as the "K-2" is shown on the exploration well drawings. It is stated that this zone is hydrocarbon-bearing, but there is no mention of this zone in the draft document. Could you address this? The course of action from here is to update the draft pool rules application answering the questions above, then formally submit that application and the AIO application to the Commission as soon as you can. The order process should take about 6 weeks. AOGCC will publish the public notice (which takes about 2 to 3 days) and set a tentative hearing date at least 30 days from the date of publication. After the hearing, the order should be published in 5 or so business days (assuming there are no problems). In the meantime, if we have additional questions AOGCC will request supplemental information in writing from you. If you have questions, I will be out of the office on Monday, but Tom and Jack Hartz will be in. Thanks, Steve Davies Petroleum Geologist Alaska Oil and Gas Conservation Commission Telephone: (907) 793-1224 1 of 1 9/26/2005 11 :55 AM l'1i:UlU4 e e Steve, Tom, & Jack, "ve been getting some questions from management/partners on the timing of the Nanuq & Nanuq-Kuparuk pool rules and area injection orders. Could you give me an estimate of the rough date or a timeframe when orders will be made? Thanks, Jack Walker ConocoPhillips Alaska, Inc. Western North Slope Development 907-265-6268 1 of 1 9/26/2005 11 :56 AM Ke: Nanuq AIU & CU lJratts - CorrectIOns e e Thanks Jack. Call when you come over. I haven't looked at the documents yet, but based on what you relate in your message will the injectors have cemented liners or will they be slotted as well?? Tom Walker, Jack A wrote: Tom, I came across some errors in the drafts I dropped off Friday. The most glaring error was that the "production/injection holes will be cemented" - we're NOT planning to cement linerslcasing in the production holes. We are planning slotted liners. I'll drop off corrected versions of those sheets today (cementing error on p. 13 of the AID app & p. 4 of the non-Confidential C.O. app). Please accept my apology for any confusion this may have caused. Jack 265-6268 1 of 1 9/26/2005 11 :56 AM #6 . . Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501-3539 Phone: (907) 279-1433 Fax: (907) 276-7542 Fax Transmission The information contained in this fax is confidential and/or privileged. This fax is intended to be reviewed initially by only the individual named below. If the reader of this transmittal page is not the intended recipient or a representative of the intended recipient, you are hereby notified that any review, dissemination or copying of this fax or the information contained herein is prohibited. 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Subject: Nanuq Conservation Order From: Thomas Maunder <tom _ maunder@admin.state.ak.us> Date: Fri, 19 Aug 200508:16:22 -0800 To: Jody J Colombie <jody_colombie@admin.state.ak.us> Jody, As you suggested, here is a note for this file's record. On Wednesday morning, August 17 Kristin Nelson called on the office to review the public file on CPAI's application for Nanuq pool rules. Dan referred her to me and after clearing it with John I gave her a copy of the non-confidential portion of the application. I made this copy from my work copy and I specifically removed the portion of the file labeled confidential. Let me know if you need anything further. Tom Maunder, PE Sr. Petroleum Engineer 1 of 1 8/22/2005 11:13 AM #2 STATE OF ALASKA NOTICE TO PUBLISHER INVOICE.T BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO..1FIED AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE ADVERTISING ORDER NO. ADVERTISING ORDER SEE BOTTOM FORINVOICEADDRESS AO-02614006 F AOGCC R 333 W 7th Ave, Ste 100 o Anchorage, AK 99501 M AGENCY CONTACT DATE OF A.O. Jody Colombie PHONE August 17, 2005 PCN (907) 793 -12? 1 DATES ADVERTISEMENT REQUIRED: ¿ Anchorage Daily News PO Box 149001 Anchorage, AK 99514 August 18, 2005 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Type of Advertisement X Legal o Display Advertisement to be published was e-mailed o Classified DOther (Specify) SEE A TT ACHED SENDINVOICEINTRIPLICATE AOGCC, 333 W. 7th Ave., Suite 100 TO . Anchora!!e. AK 99101 REF TYPE NUMBER AMOUNT DATE 1 VEN I I TOTAL OF I PAGE 1 OF ALL PAGES$ 2 PAGES COMMENTS 2 ARD 3 4 02910 ¡:IN 4MnllNT ~v rr Pr.M Ir 4rrT ¡:v NMR DIST LlQ 05 02140100 73451 2 3 4 REQUISITIONED BY ?~AÁß! DIVISION APPROVAL: . . Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Colville River Field Proposed Nanuq Oil Pool Proposed Nanuq-Kuparuk Oil Pool Application for Pool Rules By application dated August 11, 2005, and received by the Alaska Oil and Gas Conservation Commission ("Commission") that same day, ConocoPhillips Alaska in its capacity as Unit Operator of the G.:olville River Unit ("CRU") requested an order from the Commission to define two new oil pools within the CRU and to prescribe rules governing development and operation of those pools. The Commission has tentatively scheduled a public hearing on this application for October 4, 2005 at 9:00 am at the offices of the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. A person may request that the tentatively scheduled hearing be held by filing a written request with the Commission no later than 4:30 pm on September 6,2005. If a request for a hearing is not timely filed, the Commission may consider the issuance of an order without a hearing. To learn if the Commission will hold the public hearing, please call 793-1221. In addition, a person may submit written comments regarding this application to the Alaska Oil and Gas Conservation Commission at 333 West ih Avenue, Suite 100, Anchorage, Alaska 99501. Written comments must be received no later than 4:30 pm on September 20, 2005 except that if the Commission decides to hold a public hearing, written protests or comments must be received no later than the conclusion of the October 4, 2005 hearing. o may need special accommodations in ng, please contact Jody Colombie at 793- Published Date: August 18, 2005 AO# 02614006 echo rage Daily News Affidavit of Publication 1001 Northway Drive. Anchorage, AK 99508 e PRICE OTHER OTHER OTHER OTHER OTHER GRAND AD# DATE PO ACCOUNT PER DAY CHARGES CHARGES #2 CHARGES #3 CHARGES #4 CHARGES #5 TOTAL 578693 08/18/2005 02614006 STOF0330 ' $161.12 $161.12 $0.00 $0.00 $0.00 $0.00 $0.00 $161.12 STATE OF ALASKA THIRD JUDICIAL DISTRICT Teresita Peralta, being first duly sworn on oath deposes and says that she is an advertising representative of the Anchorage Daily 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 the above dates 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 ~Jcv Subscribed and sworn to me before this date: /1U(j!lt/h j, , fl )fr ;,7 !')n 5"~- ()\ f. L ,t,. Notary Public in and for the State of Alaska. Third Division. Anchorage, Alaska MY COMMISSIO~ EXPIRES, tJ 01ólf'07 ;¿ ¡. VI /j J? ~/ \\II(C({((frr .' J ' '. .' . ,\\ ~.LV 4. . ....¡"',r /' U/YY )cL( Vii ¿. -.". L~~lt*~!-:· :.:.:." .t~;~ (/'... ./ C_"~~: ~\O '1 A~.y .? ~ ' '>: ...... . \. ~'I\,!t<þ"'" - ,/ ::: : Pu"" ,.. : ;; - ~~,~~ . ~ ~ 2": : . 0-.1",,· . . f;;; ~ :-:.'::: . ~ 1M 1* O\'J .. f1? "" -0·,,-'1>. ..;:.. ..... 1:.1- . ,....... \. f\¡'~' ~;".:·Qh: . ': (?f P: .' x--:"'\' "'",1 ··i't'v ',.. .,.¿.¡ \' ",:,.)~';\,; ¡;:-j{p~tl,', :F\ '\ . //,i)})J)Jlj)\ Notice qf Public' Hearing STATE OF ALASKA , Alaska Oil ,and Gas Conservatlon'Commisslon' Re: Colville River Field PropOséd NanÙq Oil Pool Proposed Nanuq·Kuparuk Oil Pool Application for Pool Rules BY application dated August 11. 2005, and received by the Alaska Oil ,and Gas Conservation Comnîfs.· siòn (" mmissiòn") that sameaa C\>nocoPHil· lips A a in its capacity as ra'tor'of the Colvi iver UQit ("CRU") don'order from rhrhission to !lefine w oil pools' withi U ,and'tó)rescribeniríg devel and operation of those po 'The lie' hèa 9:oò'b Conser Suite,,1 requ held by ng..a..written request with.. sion noilater than 4: 30 pm on Sep .' )f'o rêquesHo "'''Cónîmissión m "der'Without á hear will hold the public' ,ic:,.":,::·'<>.;·f:__'\...i!<::..c:·''-.'.:·.::-." ins is not timely filed, the idér the issuance of ·an or, To learn if ,the Commission ing, please call 793·1221.. ,-,..-:.',', ....:- .' In'additlon, a person may submit"writtenicom- ments regarding this application to.the Alaska Oil ond ßas Conservation Commission át 333 West 7th 'Avenue; Suite lOO; Anchorage, Alaska 995'01. Writ- ten comments must be received no iater than 4:30 pm on September 20, 2005 except that. if the Com, mission decides to hold a public hearing, written protests or comments must be recelvec no later than the conclusion of the October 4, 2005 hearing. . If YOU are a person with a disabi/'¡ty'who maY need special accommodations irr order 'to commenfor to attend the public hearing, pleose contoct Jody èo, lombie at 793·1221.. . John K. Norman Chairman AO#02614006 Publish: August 18,2005 ,- " 02-902 (Rev. 3/94) NOTICE TO PUBLISHER Copies: Department Fiscal, Department, r . ;ving Ao.FRM STATE OF ALASKA ADVERTISING ORDER SEE BOTTOM FOR INVOICE ADDRESS Publisher/Or' . ADVERTISING ORDER NO. INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COpy OF ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE AO-02614006 F AOGCC 333 West ih Avenue. Suite 100 A nl'hnr¡:up A K QQ,\O 1 907-793-1221 AGENCY CONTACT DATE OF A.O. R o M .Todv Colombie Awmst 17. ?005 PHONE PCN (907) 793 -12? 1 DATES ADVERTISEMENT REQUIRED: T o Anchorage Daily News PO Box 149001 Anchorage, AK 99514 August 18, 2005 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: United states of America AFFIDAVIT OF PUBLICATION REMINDER State of ss INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER. A CERTIFIED COPY OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMITTED WITH THE INVOICE. ATTACH PROOF OF PUBLICATION HERE. division. Before me, the undersigned, a notary public this day personally appeared who, being first duly sworn, according to law, says that helshe is the of Published at in said division and state of and that the advertisement, of which the annexed is a true copy, was published in said publication on the day of 2005, and thereafter for _ consecutive days, the last publication appearing on the _ day of , 2005, and that the rate charged thereon is not in excess of the rate charged private individuals. Subscribed and sworn to before me This _ day of 2005, Notary public for state of My commission expires 02-901 (Rev. 3/94) AO.FRM .Cit90 Petroleum Corporatìon PO Box 3758 Tulsa, OK 74136 ~ary Jones XTO Energy, Inc. Cartography 810 Houston Street, Ste 2000 Ft. Worth, TX 76102-6298 David McCaleb IHS Energy Group GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 Mona Dickens Tesoro Refining and Marketing Co. Supply & Distribution 300 Concord Plaza Drive San Antonio, TX 78216 Robert Gravely 7681 South Kit Carson Drive Littleton, CO 80122 George Vaught, Jr. PO Box 13557 Denver, CO 80201·3557 Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 Richard Neahring NRG Associates President PO Box 1655 Colorado Springs, CO 80901 John Levorsen 200 North 3rd Street, #1202 Boise, 10 83702 Kay Munger Munger Oil Information Service, Inc PO Box 45738 Los Angeles, CA 90045-0738 Samuel Van Vactor Economic Insight Inc. 3004 SW First Ave. Portland, OR 97201 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle, WA 98119-3960 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Baker Oil Tools 4730 Business Park Blvd., #44 Anchorage, AK 99503 Schlumberger Drilling and Measurements 2525 Gambell Street #400 Anchorage, AK 99503 David Cusato 200 West 34th PMB 411 Anchorage, AK 99503 Ciri Land Department PO Box 93330 Anchorage, AK 99503 Ivan Gillian 9649 Musket Bell Cr.#5 Anchorage, AK 99507 Jill Schneider US Geological Survey 4200 University Dr. Anchorage, AK 99508 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 Jack Hakkila PO Box 190083 Anchorage, AK 99519 Darwin Waldsmith PO Box 39309 Ninilchick, AK 99639 James Gibbs PO Box 1597 Soldotna, AK 99669 Kenai National Wildlife Refuge Refuge Manager PO Box 2139 Soldotna, AK 99669-2139 Penny Vadla 399 West Riverview Avenue Soldotna, AK 99669-7714 Richard Wagner PO Box 60868 Fairbanks, AK 99706 Cliff Burglin PO Box 70131 Fairbanks, AK 99707 Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 Williams Thomas Arctìc Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 Ifß / ~;cÇ¡; ~ 5 North Slope Borough PO Box 69 Barrow, AK 99723 . . . . Subject: Public Notice Colville River Field Nanuq Oil Pool From: Jody Colombie <jody _ colombie@admin.state.ak.us> Date: Wed, 17 Aug 200506:40:08 -0800 To: undisclosed-recipients:; BCC: Robert E Mintz <robert_mintz@law.state.ak.us>, Christine Hansen <c.hansen@iogcc.state.ok.us>, Terrie Hubble <hubblet1@bp.com>, Sondra Stewman <StewmaSD@BP.com>, Scott & Cammy Taylor <staylor@alaska.net>, stanekj <stanekj@unocal.com>, ecolaw <ecolaw@trustees.org>, roseragsdale <roseragsdale@gci.net>, trmjr 1 <trmjr 1 @aol.com>, jbriddle <jbriddle@marathonoil.com>, shaneg <shaneg@evergreengas.com>, jdarlington <jdarlington@forestoil.com>, nelson <knelson@petroleumnews.com>, cboddy <cboddy@usibelli.com>, Mark Dalton <mark.dalton@hdrinc.com>, Shannon Donnelly <shannon.donnelly@conocophillips.com>, "Mark P . Worcester" <mark.p.worcester@conocophillips.com>, Bob <bob@inletkeeper.org>, wdv <wdv@dnr.state.ak.us>, tjr <tjr@dnr.state.ak.us>, bbritch <bbritch@alaska.net>, mjnelson <mjnelson@purvingertz.com>, Charles O'Donnell <charles.o'donnell@veco.com>, "Randy L. Skillern" <SkilleRL@BP.com>, "Deborah 1. Jones" <JonesD6@BP.com>, "Steven R. Rossberg" <RossbeRS@BP.com>, Lois <lois@inletkeeper.org>, Dan Bross <kuacnews@kuac.org>, Gordon Pospisil <PospisG@BP.com>, "Francis S. Sommer" <SommerFS@BP.com>, Mikel Schultz <Mikel.Schultz@BP.com>, "Nick W. Glover" <GloverNW@BP.com>, "Daryl J. Kleppin" <KleppiDE@BP.com>, "Janet D. Platt" <PlattJD@BP.com>, "Rosanne M. Jacobsen" <JacobsRM@BP.com>, ddonkel <ddonkel@cfl.rr.com>, mckay <mckay@gci.net>, Barbara F Fullmer <barbara.f.fullmer@conocophillips.com>, bocastwf <bocastwf@bp.com>, Charles Barker <barker@usgs.gov> , doug_schultze <doug_schultze@xtoenergy.com>, Hank Alford <hank.alford@exxonmobil.com>, Mark Kovac <yesno l@gci.net>, gspfoff <gspfoff@aurorapower.com>, Gregg Nady <gregg.nady@shell.com>, Fred Steece <fred.steece@state.sd.us>, rcrotty <rcrotty@ch2m.com>, jejones <jejones@aurorapower.com>, d.apa <dapa@alaska.net>,jroderick <jroderick@gci.net>, eyancy <eyancy@seal-tite.net>, "James M. Ruud" <james.m.ruud@conocophillips.com>, Brit Lively <mapalaska@ak.net>, jah <jah@dnr.state.ak.us>, Kurt E Olson <kurt_olson@legis.state.ak.us>, buonoje <buonoje@bp.com>, Mark Hanley <mark_hanley@anadarko.com>, 10ren_Ieman <loren_Ieman@gov.state.ak.us>, Julie Houle <julie_houle@dnr.state.ak.us>, John W Katz <jwkatz@sso.org>, Suzan J Hill <suzan _ hill@dec.state.ak.us>, tablerk <tablerk@unocal.com>, Brady <brady@aoga.org>, Brian Havelock <beh@dnr.state.ak.us>, bpopp <bpopp@borough.kenai.ak.us>, Jim White <jimwhite@satx.rr.com>, "John S. Haworth" <john.s.haworth@exxonmobil.com>, marty <marty@rkindustrial.com>, ghammons <ghammons@aol.com>, rmclean <rmclean@pobox.alaska.net>, mkm7200 <mkm7200@aol.com>, Brian Gillespie <itbmg@uaa.alaska.edu>, David L Boelens <dboelens@aurorapower.com>, Todd Durkee <TDURKEE@KMG.com>, Gary Schultz <gary_schultz@dnr.state.ak.us>, Wayne Rancier <RANCIER@petro-canada.ca>, Bill Miller <Bill_ Miller@xtoalaska.com>, Brandon Gagnon <bgagnon@brenalaw.com>, Paul Winslow <pmwinslow@forestoil.com>, Garry Catron <catrongr@bp.com>, Sharmaine Copeland <copelasv@bp.com>, Kristin Dirks <kristin_dirks@dnr.state.ak.us>, Kaynell Zeman <kjzeman@marathonoil.com>, John Tower <John.Tower@eia.doe.gov>, Bill Fowler <Bill_Fowler@anadarko.COM>, Vaughn Swartz <vaughn.swartz@rbccm.com>, Scott Cranswick <scott.cranswick@mms.gov>, Brad McKim <mckimbs@BP.com>, Steve Lambe <lambes@unocal.com>,jack newell <jack.newell@acsalaska.net>, James Scherr <james_scherr@yahoo.com>, david roby <David.Roby@mms.gov>, Tim Lawlor 10f2 8/17/20056:40 AM . . <Tim_Lawlor@ak.blm.gov>, Lynnda Kahn <Lynnda_Kahn@fws.gov>, Jerry Dethlefs <Jerry.C.Dethlefs@conocophillips.com>, Jerry Dethlefs <nI617@conocophillips.com>, crockett@aoga.org, Tamera Sheffield <sheffield@aoga.org>, Jon Goltz <Jon.Goltz@conocophillips.com>, Roger Belman <roger.belman@conocophillips.com>, Mindy Lewis <mlewis@brenalaw.com>, Harry Lampert <harry .1ampert@honeywell.com>, Kari Moriarty <moriarty@aoga.org>, Patty Alfaro <palfaro@yahoo.com>, Jeff <smetankaj@unoca1.com>, Todd Kratz <ToddKratz@chevron.com>, Gary Rogers <gary_rogers@revenue.state.ak.us>, Cynthia B Mciver <bren _ mciver@admin.state.ak.us> Content-Type: application/pdf Nanuq Public Notice.pdf C E d' b 64 ontent- nco mg: ase 20f2 8/17/20056:40 AM 1 UVll\'; .l"V\.1\,;\,; . . Subject: Public Notice From: Jody Colombie <jody _ colombie@admin.state.ak.us> Date: Wed, 17 Aug 2005 06:39: 11 -0800 To: Legal Ads Anchorage Daily News <legalads@adn.com> Please publish on 8/18/05. Jody Colombie Content- Type: application/msword Ad Order form.doc Content-Encoding: base64 Content- Type: application/pdf Nanuq Public Notice.pdf C d· b 64 ontent-Enco mg: ase 1 of 1 8/17/2005 6:43 AM . . Subject: Re: Public Notice From: "Ads, Legal" <legalads@adn.com> Date: Wed, 17 Aug 2005 15:40:51 -0800 To: Jody Colombie <jody_colombie@admin.state.ak.us> Hello Jody: BE SURE TO CHECK OUT THE LEGAL NOTICES ON-LINE. WE RECENTLY CREATED NEW LEGAL SECTIONS ON-LINE ESPECIALLY FOR THE STATE OF ALASKA. WE ARE OFFERING A 90 DAY FREE TRIAL ON ALL LEGAL ADVERTISING AS OF MAY 9TH TO PROMOTE OUR NEW ON-LINE, USER FRIENDLY CATEGORY'S. PLEASE TAKE THIS TIME TO TRACK YOUR CUSTOMERS AND SEE IF ON-LINE ADVERTISING IS RIGHT FOR YOU. Following is the confirmation information on your legal notice. Please review and let me know if you have any questions or need additional information. Account Number: STOF 0330 Legal Ad Number: 578693 Publication Date(s): August 18, 2005 Your Reference or PO#: 02614006 Cost of Legal Notice: $161.12 Additional Charges: Web Link: E-Mail Link: Bolding: Total Cost To Place Legal Notice: $161.12 Your Legal Notice Will Appear On The Web: ~,~-"'_~ adI2.:.i.':S?!!',:,. XXXX Your Legal Notice Will Not Appear On The Web www.adn.com: Thank You, Kim Kirby Anchorage Daily News Legal Classified Representative E-Mail: }.egalads@3:~~__º-()_I1l Phone: (907) 257-4296 Fax: (907) 279-8170 On 8/17/05 6:39 AM, "Jody Colombie" <jody cülombie@admin.state.ak.us> wrote: Please publish on 8/18/05. Jody Colombie 1 of 1 8/18/2005 9:21 AM #1 . . ~ ConocoPhillips Chris Alonzo Development Supervisor, WNS ConocoPhillips Alaska 700 G Street Anchorage, AK 99501 Phone: 907.276.1215 August 11,2005 J\' tll:' 1" .' . ) ,] . 1 ;~[J(]5 Mr. John Norman, Chair Alaska Oil and Gas Conservation Commission Alaska Department of Revenue 333 West 7th Avenue, Suite 100 l\nchorage,AJe 99501 Re: Hearing for Proposed Nanuq and Nanuq-Kuparuk Oil Pools Colville River Field Dear Mr. Norman: In accordance with 20 AAC 25.520, ConocoPhillips Alaska, Inc. (CPAI) as operator of the Colville River Unit and on behalf of the Working Interest Owners, requests the commission to hold a hearing regarding the classification of the Nanuq and Nanuq-Kuparuk reservoirs as oil pools and prescription of rules to govern the proposed development and operation of the pools. Two attached documents include information for the commission regarding the proposed pools. In accordance with Sec. 3l.05.035(d) and 20 AAC 25.537, CPAI requests thaUh~ commission keep confidential all information in the attached docum~nt entitled, "CONFIDENTIAL MATERIAL for the Alaska Oil and Gas Conservation Commission for the Classification and Rules for the Proposed Nanuq and Nanuq-Kuparuk Oil Pools Colville River Field". Construction of infrastructure to support development of the proposed oil pools from Drill Site CD4 started last winter, and development drilling is scheduled in October, 2005. First production from the proposed Nanuq and Nanuq-Kuparuk Oil Pools is scheduled for the fourth quarter of 2006 after facilities are completed and additional development wells are drilled. I hope that this information meets your needs and I am available to 'discuss it with you and your staff if needed. Please call me at 265-6822 or Jack Walker at 265-6268 if you have questions. ~~ Development Supervisor, Western North Slope ConocoPhillips Alaska, Inc. Attachments cc: Anadarko Petroleum Company Arctic Slope Regional Corporation w/o attachments Department of Natural Resources, Division of Oil and Gas w/o attachments . . AUG 1 1 200:) I nformation for the Alaska Oil and Gas Conservation Commission for the Classification and Rules for the Proposed Nanuq and Nanuq-Kuparuk Oil Pools Colville River Field ConocoPhillips Alaska, Inc Anadarko Petroleum Corporation August, 2005 Information for proposeeuq and Nanuq-Kuparuk Oil Pools Colville River Field . August, 2005 Table of Contents Introduction 1 1.0 Reservoir Structure and Trap 2.0 Fluid Descriptions 3 4 5 5 8 8 8 3.0 Drilling, Completion, and Well Operations 3.1 DRILLING PLAN 3.2 DRILLING AND LOGGING 3.3 WELL SPACING 3.4 WELL WORK PLAN 4.0 Facilities Scope and Design 4.1 INFRASTRUCTURE REQUIREMENT DEFINITION 4.2 SITE SELECTION AND EVALUATION 9 9 10 5.0 Operating Agreements and Production Allocation 11 Proposed Conservation Order 12 List of Fiaures Figure 1 Proposed Area for Nanuq and Nanuq-Kuparuk Pool Rules .........................2 Figure 2 Spider Map of Horizontal Well Program (15, ODD-foot Departure Circle)........ 5 Figure 3 Comparison of Nanuq and Alpine Depths ..................................................... 6 Figure 4 Proposed Nanuq and Kuparuk Producing Well Schematic ........................... 7 pagei Information for propose.uq and Nanuq-Kuparuk Oil Pools Colville River Field . August, 2005 INTRODUCTION This document includes information for the Alaska Oil and Gas Conservation Commission to classify two reservoirs in the Colville River Field as oil pools, and to prescribe rules to govern development of the proposed Nanuq Oil Pool and Nanuq-Kuparuk Oil Pool in accordance with 20 AAC 25.520. The proposed Nanuq CD4 Miscible Water Alternating Gas Project is an enhanced oil recovery project. employing the cyclic injection of miscible gas and water, to be implemented for the development of the proposed Nanuq and Nanuq-Kuparuk Oil Pools. The proposed Nanuq Oil Pool includes the Nanuq reservoir within the Torok Formation. The proposed Nanuq-Kuparuk Oil Pool is the deeper reservoir in the Kuparuk River Formation. The proposed Nanuq Oil Pool directly overlies the proposed Nanuq-Kuparuk Oil Pool. Concurrent with this application for a Conservation Order. ConocoPhillips Alaska, Inc., as operator of the Colville River Unit and on behalf of the working interest owners (WIO·s). is seeking an Area Injection Order by the Commission to endorse and authorize the proposed Nanuq CD4 Miscible Water Alternating Gas Project for the proposed Nanuq and Nanuq- Kuparuk Oil Pools. For each proposed oil pool. the WIO's plan to form a corresponding separate participating area within the Colville River Unit. Preliminary boundaries for the future participating areas are shown on Figure 1 with the present Colville River Unit boundary. ConocoPhillips Alaska, Inc. as operator and on behalf of the WIO's, plans to apply to the State of Alaska and Arctic Slope Regional Corporation for the formation a Nanuq Participating Area and a Nanuq- Kuparuk Participating Area in late 2005. Development drilling is scheduled to commence in October, 2005 at Drill Site CD4, creating the need to establish pool rules and area injection order(s) for the proposed oil pools. The project is located in the Colville Delta area approximately 4 miles south of the Alpine Central Facility. The working interest partners in the Nanuq CD4 project are the same as in the Alpine Oil Pool and Participating Area: ConocoPhillips Alaska, Inc. and Anadarko Petroleum Company. The project will be connected to the existing Alpine road system by a gravel road and connected to the existing Alpine Central Facility (ACF) by pipelines and powerlines. Nineteen horizontal wells are planned to develop the two reservoirs: 3 wells for Nanuq- Kuparuk and 16 wells for Nanuq. Implementation of miscible water alternating gas operations from field start-up is also planned. Downhole commingling of production from the two reservoirs is not planned. Commingling of production on the surface is proposed. A horizontal pattern miscible water~alternating-gas (MWAG) flood is proposed for both reservoirs. Implementation of enhanced oil recovery (EOR) is integral and necessary to the Nanuq CD4 project. Modeling and laboratory work to date has shown the MW AG will result in significant EOR from both the Nanuq and the Nanuq-Kuparuk reservoirs. Some key milestones are: Conservation Orders Development Drilling Operations Starts Begin Facilities Installation First Oil Drilling Operations Ends September 2005 October 2005 March 2006 November 2006 November 2007 Page 1 Information for propose.uq and Nanuq-Kuparuk Oil Pools Colville River Field . August, 2005 Four sections follow this introduction: 1) Drilling, Completion, and Well Operations, 2) Facilities Scope and Design, 3) Operating Agreements and Production Allocation, and 4) Proposed Conservation Order. Confidential information for this appliction was provided separately. JS 36 AA081817 CPAl7B '""'''' 2 , "O~ >-3¡¡<18 , " ~4 "ti"-<J9 17 '6 'fJ81797 CPAlis 1o,PC'22 23 2' ,",,,,, 3S 36 ~796 b~ ~4// / ~I~[~a é6/ 2 4 '" ~ <t' KLIDMET~S .- 2S NJo C 26 '7 4 '6 LU 29 13 \,,1":"(8 M>C . 22 IS 17 CÞJI18 I'; CP',.-.t78 '} \~,,~ APe 22 1.3\":-::;~~. 1B fí~ ;~~:f1/ __ ," ~1~ '.\\-,,&f~~ ¡~ ", If" l~j,":)~ 20 ~!,:V8)Q]O ;;. " '0.,.'h8 ¡ 'j)~:~~~9 \~ CPAl78 APe 22 12-4'Pc4; IIDL3I!8IiØ2 36 J, OPAl'" APe '" 2 12...."'1-<14 14 'èlW78 ,';>c.22 ProRosed Pool and Participating Areas Colville River Unit 04061501E01 Figure 1 Proposed Area for Nanuq and Nanuq-Kuparuk Pool Rules Page 2 Information for propose.uq and Nanuq-Kuparuk Oil Pools Colville River Field . August, 2005 1.0 RESERVOIR STRUCTURE AND TRAP The Nanuq CD4 project will develop two reservoirs. The principal reservoir is the Nanuq sandstone, an Albian submarine fan system, and the secondary reservoir is the Nanuq- Kuparuk sandstone. The proposed Nanuq CD4 development area is well defined by four discovery and appraisal wells (Nanuq #1, #2, #3, and #5). Two wells (Nanuq #3 and #5) will be used in the development. Production tests, conventional cores, sidewall cores, log data, and RFT/MDT data were used to determine the reservoir properties. Additionally, a horizontal well (CD1-229) was completed from the Alpine CD1 pad and production tested for several weeks in 2001. The Nanuq CD4 development area is covered by two merged 3D seismic datasets (Alpine 3D seismic acquired in 1996 and a recent Nanuq 3D dataset acquired in 2003). The Nanuq reservoir is a basin floor submarine fan system dominated by lobe-sheet deposits. The trap is stratigraphically created southwest of the Colville High. There are no major faults cutting the Nanuq reservoir. The Nanuk #1 and #2 and Nanuq #3 and #5 wells define the core of the development area for the Nanuq reservoir. Log and core data confirm an oil-water contact at 6,207 subsea true vertical depth (TVD). The CD1-229 test indicated a possible gas cap outside of the CD4 development area. The highest known oil in the CD4 area is 6,104 subsea TVD in Nanuk #1. Original oil in place and orginal gas cap gas in place were estimated to be range of 84 to 169 MMSTB and 0 to 40 BSCF, respectively, in the development area. The Nanuq-Kuparuk reservoir is a shallow marine transgressive sandstone that lies below the Kalubik shales and just above the Lower Cretaceous Unconformity (LCU). Trap is stratigraphic in nature with sand encased above and below by shales. The northern edge of the reservoir has one mapped fault which not expected to affect recovery. The reservoir interval is fine- to medium-grained, quartz-rich sandstone that contains varying amounts of glauconite. The sandstone has very good porosity and permeability with thin zones cemented by siderite cement. The Nanuk #1 and #2 and Nanuq #3 wells contain from 6 to 11 feet of Kuparuk net pay. Nanuq #5, to the south, has no Kuparuk net pay. Original oil in place is estimated at 21 to 36 MMSTB in the development area. Page 3 Information for proposeauq and Nanuq-Kuparuk Oil Pools Colville River Field . August, 2005 2.0 FLUID DESCRIPTIONS Nanuq CD4 project fluids were characterized with samples from the Nanuk #2 production test, augmented with subsurface samples acquired in Nanuk #1 gathered via a RFT and surface samples from CD1-229. PVT relationships were determined for the Nanuq interval with recombined samples of gas and oil sampled at the Nanuk #2 test separator. Formation brine composition for the Nanuq interval was also determined from samples acquired from Nanuk #2 production test. After the Nanuk #2 test of the Nanuq interval, the Kuparuk interval was opened in the Nanuk #2 well, and the Kuparuk and Nanuq intervals were production tested with commingled flow. The combined stream was sampled and tested for American Petroleum Institute (API) gravity and geochemical analysis. API gravity analyses were also conducted on RFT samples from Nanuk #1. API gravities are summarized in Table. An equation of state study for the Nanuq interval reservoir fluids was also completed. Table 1: Fluid Analyses Results Interval Nanuq Nanuq Nanuq Nanuq/Kuparuk commingled Kuparuk Well CD1-229 Nanuk #1* Nanuk #2 Nanuk #2 Nanuk #1 SamDle Production Test RFT Production Test Production Test RFT API Gravity 42°API 33° API 39° API 41 ° API 40° API *Chromatographic and pressure information indicate light ends were depleted from the Nanuk #1 sample. The Nanuq Interval PVT Summary Temperature: 135°F Saturation Pressure: 2821 psig Single Phase Compressibility: 11.85 x 10-6 v/vlpsi (average 5000 to 2821 psig) Thermal Expansion: 1.04733 v at 135°F I v at 59°F Reservoir Fluid Viscosity: 0.473 cp at 2821 psig and 135°F Density of Reservoir Fluid: 0.678 glee Differential Vaporization Solution Gas-Oil Ratio: 990 scf/bbl residual oil at 59°F Differential Vaporization Relative Oil Volume: 1.512 bbll bbl of residual oil at 59°F Analysis of the reservoir fluid from the Nanuq interval is shown in the attached report on Composition of Recombined Reservoir Fluid for the Nanuk No.2 Well. Geochemical analysis indicated that the oil from the Kuparuk reservoir is closely related to the oil from the Nanuq reservoir. Page 4 Information for propose.uq and Nanuq-Kuparuk Oil Pools Colville River Field . August, 2005 3.0 DRilLING, COMPLETION, AND WEll OPERATIONS Nineteen horizontal wells are planned at the Nanuq CD4 development. The Nanuq reservoir development is planned with 16 wells (nine producers and seven injectors), and the Kuparuk reservoir development is planned with three wells (two producers and one injector). Nearly identical well designs are planned for the Nanuq and Nanuq-Kuparuk Oil Pools, except for the target formation and subsea depth of intermediate casing. the surface and intermediate sections will be directionally drilled with water based mud systems and cased. The horizontal intervals will be drilled with a reservoir drill-in-fluid (DIF) and completed with slotted liners. With the exception of the production/injection hole liners and target formations, the well plans for the Nanuq and Nanuq-Kuparuk pools is almost identical to the standard development well design used in the Alpine Oil Pool. For both Nanuq and Nanuq- Kuparuk, Producers are planned with surface-controlled subsurface safety valves and injectors are planned with a double check valve arrangement, and surface safety valves are planned for all wells. 3.1 DRilLING PLAN Drilling began at Alpine in 1999 and 97 horizontal wells have be completed as of June 1, 2005. A similar well design is planned for Nanuq CD4. Hole and casing sizes, mud systems, directional profile and departure, drilling techniques. and geologic section drilled to reach the sand targets are similar. The wells will be drilled from 20-foot centers with the Nanuq laterals oriented along northwest - southeast azimuth (maximum horizontal stress direction) for waterflood performance and stimulation option of the Nanuq (Figure 2). ,,~~ I I / ~ø / øfø;, ," \/" I ~'" ~..::~~\ '\ ) ,,,,, """"" ", '\ \ '.' \ ~~~-,~ \ ~, \ \ ,\ æ I \ \ \ \\,\ ,..~~ / \ ~-<)~ .\~'§; /// \<vøþ¿;p,.,.,._ ",~'v// ',,';. ..<-,-'.>"'- ~ // ", .~- ~- ---------- ......., "', LINE CD4 Pad 0- , I I , . , I ' . , , I ' . . . , . I I , I ' . . . I ' , . , I . , , . I . , .;;f..~ -H";;; ·'¡RQ -r.r..: "'¡':'" 0 HI"/.- ¡.:çr. . . I . , , . I I . . . I . 1~tv. '~v. ~v Wf:H¡-;.';'U!\+) [HQO 1"~'ì Figure 2 Spider Map of Horizontal Well Program (15,OOo-foot Departure Circle) Primary, secondary, and general well control for drilling and completion operations will be performed in accordance with 20 AAC 25 Articles 01 and 06. Disposal of drilling wastes will be proposed for Drill Site CD4 in accordance with 20 AAC 25.080 in annulii of wells with Page 5 · Information for propos4uq and Nanuq-Kuparuk Oil Pools Colville River Field August, 2005 surface casing set below the permafrost. No underground sources of driking water exist beneath the permafrost in the Colville River Unit area (AOGCC Area Injection Order No. 18B, October 7,2004.) Casing and cementing will be performed in accordance with 20 AAC 25.030. Surface casing, cemented to surface, is planned at approximately 2500 feet true vertical depth. Intermediate hole will be drilled to the target formation and intermediate casing will be cemented with the shoe in the target formation. Production casing will be cemented with such a volume to protect any significant hydrocarbon zones. Nanuq-Kuparuk wells will be cemented such that the Nanuq reservoir is protected. Zones above Nanuq will also be evaluated on a well-by-well basis. If a significant hydrocarbon zone(s) are indicated by logging discussed in the following section 3.2, the cementing progam will be designed for that well to protect that zone(s). Leak-off tests are planned after drilling 20 to 50 feet beyond the surface casing shoe and the intermediate casing shoe. The development plan for the proposed Nanuq Oil Pool is based on undulating horizontal wells with lengths up to 7,000 feet. The horizontal section would be drilled with a reservoir DIF and completed with a 4Y2-inch slotted liner across from sands and blank liner across from shales. The liner will be tied back to surface with 3Y2- or 4-Y2 inch tubing. The development plan for the proposed Kuparuk Oil Pool is based on horizontal wells with lengths of 4,500 to 6000 feet. The horizontal section would be drilled with a drill in fluid and completed with 4Y2-inch slotted liner and tied back with 4Y2-inch tubing for a monobore completion. A comparison of Nanuq and Alpine depths is shown in Figure 3 and a proposed producing well schematic is shown in Figure 4. ã) 12 w ~ : ... : ; 10, .. ' '" o ~ 8, Average Depth wI Min·Max Bars 20 18, I!ITotal Depth .7" Csg Deplh DDeparture CHoriz Length 16 - 14 ' + 6, 4 ' 2 ' Nanuq Alpine Figure 3 Comparison of Nanuq and Alpine Depths Page 6 Information for propose.uq and Nanuq-Kuparuk Oil Pools Colville River Field . August, 2005 CD4 - Nanuq Completion II. 16" Insulated Conductor to 114' -. SSSV or Nipple at 2000' TVD 9-5/8" 36 or 40 ppf L -80 BTCM Surface Casing at 2500'TVD, cemented to surface GL J ~ GLM s at +1-3400', 5700' TVD and above Packer A 3-1/2" 9.3 ppf L-80 EUE 8rd Mod, tubing or 4_%" 12,6 ppf L-80 IBT Mod. tubing GL J Sliding sleeve X Profile set 2 joints above XN nipple Liner top packer and hanger wi PBR ~---- --~----I 1_-- --------1) -------~----- ----------- ::E=:::E=3=::::E=::=t::E=::=3:t= ~~~~~~~~~~§= Top Reservoir at +1- 6200' TVD Nanuq 7100' TVD Kuparuk 3000 . 7000' MD Horizontal 7" 26 ppf L-80 BTC Mod Production Casing @ +1· 85° 4-X," 12,6#/ft L·80 IBT Mod liner wi blank across shale and slots across sand Figure 4 Proposed Nanuq and Kuparuk Producing Well Schematic Injection wells will have similar completions, except the upper two gas lift mandrels and the sliding sleeve will be omitted from the tubing string. Differential pressure-controlled subsurface safety valves (SSSV's) are planned for injectors, and surface-controlled SSSV's are planned for producers. Page 7 Information for propose.uq and Nanuq-Kuparuk Oil Pools Colville River Field . August, 2005 3.2 DRILLING AND LOGGING Preliminary slot assignments and directional plans for the 19 wells have been generated. Drilling from 20-foot centers alleviates shallow close approaches and anti-collision scans show no major proximity issues. Assuming conservative build and turn rates of no more than 4 degrees/100 feet all targets are reached with intermediate hole tangent angles of 20 - 65 degrees, thus providing wireline access down to the liner top packer in all wells. The undulating horizontals are also planned at 4 degrees/100 feet with aOO-foot to 1,000-foot displacement between peak and valley of the curves. The directional profiles were then used to spot check torque & drag, hydraulics and horizontal liner running. Well modeling (torque, drag, casing running, hydraulics, hole cleaning) results showed no major risks to drilling the wells that have not already been identified and overcome at Alpine. Drilling and completing the Nanuq CD4 wells can be accomplished with current designs and drilling practices. The requirements described in 20 AAC 25.050(b) should be waived for the proposed Nanuq and Nanuq-Kuparuk Oil Pools to relieve administrative burden. In lieu of requirements under 20 AAC 25.050(b), it is proposed that permit(s) to drill deviated wells shall include a plat with a plan view, vertical section, close approach data and a directional program description. The minimum log suite includes resistivity and gamma ray (GR) logs from surface casing to total depth (TD). These logs will be obtained from measure-while-drilling tools in the drill string bottom hole assembly. Two wells on the Drill Site CD4 pad (Nanuq #3 and Nanuq #5) have been logged from the conductor to TD with GRlResistivity, and density/neutron logs from surface casing to TD. 3.3 WELL SPACING Well spacing requirements under 20 AAC 25.055 should be waived because the horizontal well development of the proposed Nanuq and Nanuq-Kuparuk Oil Pools will yield greater recovery than a conventional well development with a minimum spacing rule. Vertical well simulation indicated production capacity for individual wells in the Nanuq reservoir would range from 50 to 400 BOPD, and Kuparuk vertical wells would average 350 BOPD. Wells with this capacity would be prone to extreme wax deposition in production tubing, such that average production rates would be much lower than the well capacity estimated from simulation of a wax-free well. Imposing a limit on the minimum interwell spacing, either heel to toe distance between horizontal wells, or lateral spacing between horizontal wells will not achieve conservation objectives. Very small heel to toe distance in the planned horizontal line drive flood would be similar to longer horizontal production or injection holes. Very small heel to toe distance or longer production/injection holes will not promote waste. Reservoir simulation indicates that longer horizontal wells will recover more oil, therefore a minimum distance between development wells should not be imposed. 3.4 WELL WORK PLAN Well service operations are planned in accordance with 20 AAC 25 Article 03. Drillsite CD4 is planned with year-round road access to the ACF. Routine reservoir surveillance activities including pressure measurement and production and injection profiles will be accomplished with instruments deployed either with electric-line, slickline or coiled tubing. Subsurface safety valve maintenance, gas lift valve change out, and tubing caliper surveys are planned with slickline. Remedial wax management is planned with a combination of slickline and hot oil treatments. Insulated tubing is being considered as a wax prevention measure. Page 8 Information for propose.uq and Nanuq-Kuparuk Oil Pools Colville River Field . August, 2005 4.0 FACILITIES SCOPE AND DESIGN The Nanuq C04 scope includes a 3.8-mile gravel road to a proposed 9.3-acre gravel pad located south of the ACF. The Nanuq C04 drillsite is a conventional drillsite similar to projects that have recently been successfully implemented by CPAI. The project utilizes little new technology and has few non-routine challenges. The on-pad facilities. pipelines and power lines will be constructed and installed using standard oilfield materials and equipment, and the work will be undertaken by experienced North Slope contractors. The design chosen for the Nanuq C04 OS on-pad facilities has been engineered based upon the design successfully utilized at OS 3S (2002). The project includes produced oil. water injection. MI. and gas lift pipelines from the Alpine production facility to the Nanuq C04 drillsite. The Nanuq C04 pipelines would be supported by new VSMs installed adjacent to the Alpine oil sales and seawater import pipelines. Orillsite facilities include the following: ~ Production. test. artificial lift, gas injection, and water injection headers; ~ Tie-in slots for 24 wells (including spares) with wellhead shelters; ~ Electrical and instrumentation module with transformers, switch gear. and telecommunications; ~ Test separator; ~ Emergency shut down (ESO) skid; ~ Water injection line pig receiver; ~ Chemical injection and storage; ~ Wellhead hydraulic panels (in well house); and ~ Lighting, surveillance. and communication equipment. Four cross-country pipelines will be constructed to connect the Nanuq C04 drillsite to the ACF. Additionally. tie-ins at the ACF will include a manifold module and associated piping. Powerlines (13.8 kV) will be suspended by messenger cable below the pipeline. Microwave system and fiber optics also are included in the plan. 4.1 INFRASTRUCTURE REQUIREMENT DEFINITION CPAI constructed a gravel road from the existing C01 Airstrip I C02 access road to the new Nanuq CD4 gravel pad drillsite located approximately 4 miles south of the existing ACF. Four new pipelines from the ACF at CD 1 to the new Nanuq C04 drillsite will follow the same route as the existing Alpine Sales Line. Approximately 0.5 mile southwest of the Central Processing Facility (CD1), the C02 pipelines run parallel to the Sales Line and the proposed Nanuq C04 pipelines. The approximate length of pipelines from Nanuq C04 to CD1 is 4.6 miles. Power and fiber optic cables will be suspended by messenger cable below the pipeline VSMs. The following pipelines from Nanuq C04 are planned: ~ 14-inch diameter production pipeline ~ 8-inch diameter water injection pipeline ~ 6-inch diameter MI pipeline ~ 6-inch diameter gas-lift pipeline Page 9 Information for propose.uq and Nanuq-Kuparuk Oil Pools Colville River Field . August, 2005 The bottom of the existing Alpine Sales Line is at least 7 feet above existing grade and at least 3 feet above the 200-year flood elevation. To meet both criteria, the actual pipeline height varies from 7 to 14 feet above tundra grade. The CD4 pipelines will meet the same criteria as the Alpine Sales Line. The CD4 pipelines will be supported on 12- to 40-inch diameter VSMs depending on location and load conditions. The CD4 pipeline VSM spacing will be 65 feet where the CD4 pipeline parallels only the Alpine Sales Line. The CD4 VSM spacing will be 55 feet when the CD4 pipeline parallels both the CD2 pipeline and Alpine Sales Line. The VSMs will be placed adjacent to existing VSM to prevent a "picket fence" effect. The Alpine Sales Line VSMs and CD4 pipeline VSMs will be approximately 30 feet apart. 4.2 SITE SELECTION AND EVALUATION The Nanuq CD4 pad location was selected for the following reasons: ~ Centrally located in the accumulation so that both reservoirs can be developed using Alpine-based drilling practices and well lengths ~ On the same side of the Nigliq Channel as CD1 and CD2, thus simplifying road access to the new drillsite ~ Close enough to CD1 (Le., far enough north) to make road construction feasible, but far enough away to minimize overlap between areas that can be developed by each pad ~ Far enough south to reach the southern limits of the reservoirs ~ Near the existing Alpine Sales Pipeline ~ On higher ground, thus minimizing the gravel needed to prevent flooding of the site Page 10 Information for propose.uq and Nanuq-Kuparuk 011 Pools Colville River Field . August, 2005 5.0 OPERATING AGREEMENTS AND PRODUCTION ALLOCATION All lands within the anticipated Nanuq CD4 project area are leased within the Colville River Unit (CRU). All Nanuq CD4 leases have the same working interest as the Alpine Field (78 percent CPAI I 22 percent Anadarko Petroleum Company). The equity re-determination schedule is defined by the Colville River Unit Agreement (CRUA). The entirety of the Nanuq CD4 project area became subject to the CRUA in November 2002 when the State and ASRC approved the Second Unit Expansion to the CRU to include all of the Nanuq CD4 project area. As per the CRUA, separate participating areas are anticipated for the Nanuq and Kuparuk reservoirs in the Nanuq CD4 project. The Nanuq CD4 project area is also subject to the Colville River Unit Operating Agreement (CRUOA). The provisions of the CRUOA will control the development of the Nanuq CD4 project. Development of the proposed Nanuq and Nanuq-Kuparuk Oil Pools are planned with development wells solely dedicated to a single pool with no subsurface commingling. Unitized substances produced from the proposed Nanuq and the Nanuq-Kuparuk Oil Pools will be commingled on the surface with each other and with substances from the existing Alpine Oil Pool. Production will be allocated to each producing well using the same process regardless of the pool. The allocation method presently used for the Alpine Oil Pool will be used for the new pools. A description of this system follows. Production and injection allocation is a daily process used to balance production from wells and injection into wells that have commingled production streams and injection streams, respectively. The information used in the allocation procedure is derived from pressure and flow measurements on individual production and injection wells along with measurements on aggregate commingled streams. Discrete production well tests provide the information to quantify performance of individual producers. Injectors are typically in single phase service, either gas or water, which allows continuous monitoring of injection rate. In both cases, the well test or injection meter volumes are balanced to an aggregate volume for allocation purposes. An automated allocation system used for the CRU is very similar to system used at the Kuparuk River Unit (KRU). Differences in allocation systems between the KRU and CRU are primarily driven by differences in the process facilities and reservoir characteristics. The CRU allocation system determines a "theoretical volume" for all well streams: oil, formation gas, produced water, injection water, and injection gas for each well each day. The "theoretical volume" for each well is summed to calculate a total theoretical volume for all CRU wells. The aggregate volume is determined at the CRU level from measurements made on the commingled stream processed in the Alpine Central Facility. The allocation factor is the ratio of aggregate volume to total theoretical volume. The allocated volume for each well is the product of the allocation factor and the well-specific theoretical volume. A mathematical description applicable to all well streams follows: Vii = Theoretical volume for well i VtCRu = Total theoretical volume for CRU VtCRU = Vu + Vt2 + ... Vtn Vaggregate = Aggregate volume transferred (or used for injection, fuel, etc.) for the CRU AF = Allocation factor AF = Vaggregate I V tCRU V Ai = Allocated volume for well i VAl = AF Vti Page 11 Information for propose.uq and Nanuq-Kuparuk Oil Pools Colville River Field . August, 2005 PROPOSED CONSERVATION ORDER It is ordered that the rules hereinafter set forth, in addition to the statewide requirements under 20 AAC 25, apply to the following affected area referred to in this order. Umiat Meridian T11N R4E all sections T 11 N R5E all sections T 1 ON R4E Sections 1-12 T1 ON R5E Sections 1-12 Rule 1. Field and Pool Names The field is the Colville River Field and two pools are defined as the Nanuq Oil Pool and the Nanuq-Kuparuk Oil Pool. Rule 2. Pool Definitions The Nanuq Oil Pool is defined as the accumulation of oil and gas common to and correlating to the interval found in the Nanuk No.2 well between the depths of 7043 and 7223 feet measured depth. The Nanuq-Kuparuk Oil Pool is defined as the accumulation of oil and gas common to and correlating to the interval found in the Nanuk No.2 well between the depths of 7956 and 7972 feet measured depth. Rule 3. Well Spacing The requirements of 20 AAC 25.055 are waived for development wells in the Nanuq and Nanuq-Kuparuk Oil Pools. Without prior notification, development wells may not be completed closer than 300 feet to an external boundary where working interest ownership changes. Rule 4. Drilling and Completion Practices (a.) After drilling no more than 50 feet below a casing shoe set in the Nanuq Oil Pool or the Nanuq-Kuparuk Oil Pool, a formation integrity test must be conducted. The test pressure need not exceed a predetermined pressure. (b.) Casing and completion designs may be approved by the Commission upon application and presentation of data that demonstrate the designs are appropriate and based on sound engineering principles. (c.) Permit(s) to drill deviated wells shall include a plat with a plan view, vertical section, close approach data and a directional program description in lieu of the requirements of 20 AAC 25.050(b). (d.) A complete petrophysical log suite acceptable to the Commission is required from below the conductor to TD for at least one well in lieu of the requirements of 20 AAC 25.071 (a). Rule 5. Automatic Shut-in Equipment (a.) All production wells must be equipped with a fail-safe automatic surface safety valve (SSV) and a surface-controlled subsurface safety valve (SSSV). (b.) Injection wells, including WAG, GINJ, and WINJ service wells per Form 10-407 well completion report, mus be equipped with either a double check valve arragnement or a single check valve and SSV. A subsurface-controlled injection valve satisfies the requirement of a single check valve. (c.) Safety valve systems must be tested on a six-month frequency. Sufficient notice must be given so that a representative of the Commission can witness the tests. (d.) Subsurface safety valves may only be removed after demonstrating to the Commission that the well is not capable of unassisted flow of hydrocarbons. Sufficient notice must be given so that a representative of the Commission can witness the tests. Page 12 Information for propose.uq and Nanuq-Kuparuk Oil Pools Colville River Field . August, 2005 Well tubulars and completion equipment shall be tested in each development well to demonstrate that planned well operations will not result in failure of well integrity, uncontrolled release of fluid or pressure, or threat to human safety. Rule 6. Reservoir Pressure Monitoring (a.) Prior to regular injection, an initial pressure survey shall be taken in each injection well. (b.) A minimum of two bottom hole pressure surveys shall be measured annually in the Nanuq Oil Pool. A minimum of one bottom hole pressure survey shall be measured annually in the Nanuq-Kuparuk Oil Pool. (c.) The reservoir pressure datums shall be 6150 feet subsea for the Nanuq Oil Pool and 7000 feet subsea for the Nanuq-Kuparuk Oil Pool. (d.) Pressure surveys may consist of stabilized static pressure measurements at bottom- hole or extrapolated from surface pressure fall-off, pressure build-up, multi-rate tests, drill stem tests, and formation tests. (e.) Data and results from pressure surveys shall be reported annually on Form 10-412, Reservoir Pressure Report. All data necessary for the analysis of each survey need not be submitted with the Form 10-412 but shall be made available to the Commission upon request. Rule 7. Gas-Oil Ratio Exemption Wells producing from the Nanuq Oil Pool and the Nanuq-Kuparuk Oil Pool are exempt from the gas-oil ratio limits of 20 AAC 25.240(b) so long as the provisions of 20 AAC 25.240(c) apply. Rule 8. Common Production Facilities and Surface Commingling Production from the Nanuq Oil Pool, Nanuq-Kuparuk Oil Pool, and Alpine Oil Pool may be commingled on the surface prior to custody transfer. Production shall be allocated to each pool on the basis of well testing and producing conditions for each well. Rule 9. Well Testing (a) All producing wells must be tested at least twice per month. (b) Stabilization and test duration times will be managed to obtain representative tests. (c) Operating conditions shall be recorded appropriate for maintaining accurate field production history. (d) Records to allow verification of production allocation methodologies shall be maintained and be made available to the Commission upon request. Rule 10. Sustained Case Pressure (a) The operator shall conduct and document a pressure test of tublars and completion equipment in each development well at the time of installation or replacement that is sufficient to demonstrate that planned well operations will not result in failure of well integrity, uncontrolled release of fluid or pressure, or threat to human safety. (b) The operator shall monitor each devleopment well to check for sustained pressure, except if prevented by extreme weather conditions, emergency situations, or similar unavoidable circumstances. Monitoring results shall be made available for Commission inspection. (c) The operator must notify the Commission within three working days after the operator identifies a well as having (i) sustained inner annulus pressure that exceeds 2000 psig, or (ii) sustained outer annulus pressure that exceeds 1000 psig. (d) The Commission may require the operator to submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action or increased surveillance for any development well having sustained pressure that exceeds a limit set out in part (c) of this rule. The Commission may approve the operator's proposal or may require other corrective Page 13 Information for propose.uq and Nanuq-Kuparuk Oil Pools Colville River Field . August, 2005 action or surveillance. The Commission may require that corrective action be verified by mechanical integrity testing or other Commission approved diagnostic tests. The operator shall give Commission sufficient notice of the testing schedule to allow Commission to witness the tests. (e) If the operator identifies sustained pressure in the inner annulus of a development well that exceeds 45% of the burst pressure rating of the well's production casing for inner annulus pressure, or sustained pressure in the outer annulus that exceeds 45% of the burst pressure of the well's surface casing for outer annulus pressure, the operator shall notify the Commission within three working days and take corrective action. Unless well conditions s require the operator to take emergency corrective action the Commission approval can be obtained, the operator shall submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action. The Commission may approve the operator's proposal or may require other corrective action The Commission may also require that corrective action be verified by mechanical integrity testing or other Commission approved diagnostic tests. The operator shall give Commission sufficient notice of the teting schedule to allow Commission to witness the tests. (f) Except as otherwise approved by the Commission under part (d) and (e) of this rule, before a shut-in well is placed in service, any annulus pressure must be relieved to a sufficient degree (i) that the inner annulus pressure at operating temperature will be below 2000 psig and (ii) that the outer annulus pressure at operating temperature will be below 1000 psig. However, a well that is subject to part (c), but not part (e), of this order may reach an annulus pressure at operating temperature that is described in the operator's notification to the Commission under part (c), unless the Commission prescribes a different limit. (g) For purposes of these rules, "inner annulus" means the space in a well between tubing and production casing; "outer annuls" means the space in a well between the production casing and surface casing; "sustained pressure" means pressure that (i) is measurable at the casing head of an annulus, (ii) is not caused solely by temperature fluctuations, and (iii) is not pressure that has been applied intentionally. Rule 11. Administrative Action Upon proper application of its own motion, the Commission may administratively waive the requirements of any rule stated above or administratively amend this order. Page 14 Information for Proposed Nanuq and Na.parUk Oil Pools Colville River Field . August. 2005 Phillips Alaska Inc. Nanuk No.2 Well 52134-2000-4073-2 COMPOSITION OF RECOMBINED RESERVOIR FLUID (by Programmed-Temperature. Capillary Chromatography) Date Sampled: 2000/04/21 Time Sampled: 22:55 to 23:30 Date Analyzed: 2000/08/03 Liquid Mol % Wt% Density MW (gmlee) Hydrogen Sulfide 0.00 0.00 SAMPLING CONDITIONS Carbon Dioxide 0.18 0.09 0.8172 44.010 Nitrogen 0.31 0.10 N/A psig Methane 43.40 7.88 0.2997 16.043 N/A OF Ethane 6.78 2.31 0.3562 30.070 Propane 7.05 3.52 0.5070 44.097 iso-Butane 1.27 0.84 0.5629 58.123 n-Butane 3.70 2.43 0.5840 58.123 iso-Pentane 1.35 1.10 0.6244 72.150 n-Pentane 1.87 1.53 0.6311 72.150 Hexanes 2.56 2.40 0.6850 84.0 Heptanes 4.77 4.99 0.7220 96.0 Octanes 4.18 5.00 0.7450 107 Liquid Cylinder Nonanes 3.00 4.08 0.7640 121 80020 Decanes 2.19 3.40 0.7780 134 Undecanes 1.70 2.97 0.7890 147 Dodecanes 1.48 2.82 0.8000 161 Average Sample Properties Tridecanes 1.37 2.82 0.8110 175 Tetradecanes 1.20 2.65 0.8220 190 Average Molecular Weight = 88.34 Pentadecanes 1.09 2.59 0.8320 206 Calculated Density at 0 psig and 60 of 0.6880 Hexadecanes 0.93 2.36 0.8390 222 Heptadecanes 0.79 2.13 0.8470 237 Octadecanes 0.80 2.26 0.8520 251 Nonadecanes 0.69 2.05 0.8570 263 Properties of Pius Fractions Eicosanes 0.58 1.81 0.8620 275 Liquid Liquid Heneicosanes 0.50 1.67 0.8670 291 Plus Fraction Mol% Wt% Density API MW Docosanes 0.46 1.58 0.8720 305 (gm/ee) Gravity Tricosanes 0.42 1.52 0.8770 318 Tetracosanes 0.37 1.42 0.8810 331 Hexanes plus 34.09 80.20 0.8385 37.2 208 Pentacosanes 0.39 1.52 0.8850 345 Heptanes plus 31.53 77.80 0.8450 35.8 218 Hexacosanes 0.32 1.31 0.8890 359 Heptacosanes 0.26 1.09 0.8930 374 Octacosanes 0.28 1.23 0.8960 388 Nonacosanes 0.23 1.04 0.8990 402 Triacontanes Plus 3.53 23.49 Totals 100.00 I 100.00 I