The URL can be used to link to this page

Home My WebLink AboutCO 569CONSERVATION ORDER NO. 569 Fiord Oil Pool, Colville River Field 1. November 22, 2005 Request from CPAI for CO and AIO 2. December 01, 2005 Receipt for copies from Guess & Rudd 3. December 13, 2005 Advertising Order 4. December 20, 2005 Operator Questions from AOGCC 5. --------------------- Miscellaneous E-mails 6. January 11, 2006 Supplemental Information from CPAI 7. January 11, 2006 CPAI Well analysis for USDW (recvd' 01/13/06) 8. January 12, 2006 CPA forecast of the Fiord production profile (Confidential) 9. January 25, 2006 CPAI request for contraction of Alpine Oil Pool 10. March 17, 2006 E-mail from potential interest owner 11. July 18, 2006 E-mail from CPAI re: Seawater Compatibility 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 14. November 28, 2007 Public records request from Pioneer Natural Resources 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 569.003) 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 (C0569.004) CONSERVATION ORDER NO. 569 . . STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage Alaska 99501 Re: THE APPLICATION OF CONOCOPHILLIPS ALASKA, INC. for an order for classification of a new oil pool and to prescribe pool rules for development of the Fiord Oil Pool within the Colville River Field, Colville River Unit, Arctic Slope, Alaska IT APPEARING THAT: ) Conservation Order No. 569 ) ) Colville River Field ) Colville River Unit ) Fiord Oil Pool ) ) July 21, 2006 ) 1. By letter and application dated November 22, 2005, and received by the Alaska Oil and Gas Conservation Commission ("Commission") on November 25, 2005, ConocoPhillips Alaska, Inc. ("ConocoPhillips") in its capacity as Unit Operator of the Colville River · Unit ("CRU") requested an order from the Commission to define the proposed Fiord Oil Pool within the CRU, and to prescribe rules governing the development and operation of the pool. 2. Notice of a public hearing was published in the Anchorage Daily News on December 16, 2005. 3. The Commission requested additional information from ConocoPhillips on December 20, 2005. Supplemental information was received from ConocoPhillips on January 11, 12 · and 13,2006. 4. The Commission received no protests, comments or requests for public hearing. 5, The Commission vacated the public hearing on January 13,2006. 6. On January 27,2006, the Commission received a request from ConocoPhillips to contract Sections 13, 14, and 15 of TI2N, R5E, Umiat Meridian ("UM") from the affected areas of Conservation Order 443A (corrected January 17, 2006) and Area Injection Order 18B (October 7, 2004) in order to ensure that there is no overlap between the Alpine Oil Pool · and the proposed Fiord Oil Pool. FINDINGS: 1. Operator: ConocoPhillips is the Operator of the property in the area proposed for development. Conservation Order 569 July 21, 2006 . . Page 2 2. Development Area: The proposed development area lies within the northern portion of CRU, approximately six miles north of the Alpine Central Facility on the Arctic Slope of Alaska. The Fiord Oil Pool will be developed from a single, new drill site named CD3. 3. . Owners and Landowners: All lands within the proposed development area are leased and lie within the CRU. Three companies hold working interest in the proposed Fiord Oil Pool: ConocoPhillips, Anadarko Petroleum Company ("Anadarko"), and Petro-Hunt L.L.C. ("Petro-Hunt"). In Tracts 83, 110, 111, and 114 of state leases ADL 384215 and ADL 389725, Petro-Hunt holds 0.38 percent working interest, ConocoPhillips holds 77.62 percent and Anadarko holds 22 percent. For the remaining leases within the proposed development area, ConocoPhillips holds 78 percent working interest and Anadarko holds 22 percent working interest. These companies have approved the Colville River Unit Agreement and the Colville River Unit Operating Agreement. Affected landowners are Arctic Slope Regional Corporation and the State of Alaska. 4. Delineation History: Arco Alaska Inc., the predecessor of ConocoPhillips, drilled the Fiord No.1 discovery well in Section 2 ofT12N, R5E, UM in 1992. The discovery was confirmed by delineation wells Fiord No.2, Fiord No.4, Fiord No.5, Nigliq No.1, and Nigliq No. lA, drilled between 1994 and 2001. Three-dimensional seismic and well data have been used to determine the geologic structure and reservoir distribution. Production . tests, sidewall cores, well log data, Repeat Formation Tester ("RFT"), and Modular Formation Dynamics Tester data have been used to establish reservoir and fluid properties. 5. Pool Identification: The proposed Fiord Oil Pool is the accumulation of hydrocarbons common to, and correlating with, the interval between the measured depths of 6,876' and 7,172' in the Fiord No.5 exploration well. 6. Geology: a. Stratigraphy: The Fiord Oil Pool encompasses two reservoir sandstone intervals that are in direct contact and in hydraulic communication within the oil column. The deeper reservoir interval, informally termed the "Nechelik zone" is Jurassic-aged (Oxfordian) and lies within the Kingak formation. The shallower reservoir interval, informally named the "Kuparuk zone," lies within the Cretaceous-aged (Hauterivian) Kuparuk formation. The Nechelik zone reservoir is fine-grained, quartz-rich, and was deposited in environments ranging from marine-shelf (at the base of the zone) to middle shoreface (near the top). Detrital matrix constitutes 10 to 30 percent of the sediments at the base of the Nechelik, but decreases in abundance upwards as sand content increases. The best-quality reservoir sandstone occurs near the top of the zone. The detrital matrix is predominantly mixed-layer illite/smectite, discrete illite and kaolinite clays with some localized siderite cement. Clay swelling is not expected to be significant based on core flood studies and experience with similar clays in the Alpine Field. Nechelik porosity averages about 16%, and air permeability averages approximately 8 millidarcies. Average water saturation is about 34% in the Fiord No.4 and Fiord No.5 wells. Conservation Order 569 July 21, 2006 . . Page 3 Between the Nechelik and Kuparuk zones is a wedge of non-reservoir shale and sandstone that thickens to the south. The top of the non-reservoir wedge is the Lower Cretaceous Unconformity ("LCU"), which at one time was a regional erosional surface. In the northern and northwest part of the development area, the LCU dips to the north and cuts down into the Nechelik zone, and the reservoir sand of the Kuparuk zone directly contacts reservoir sandstone of the Nechelik zone. The base of the wedge is the top of the Nechelik zone, which dips southeast within the proposed development area. Along the southeastern edge of the affected area, within portions of Sections 13, 14, and 15 of T 12N, R5E, UM, the wedge of sediments separating the N echelik and Kuparuk zones contains a thin interval of Alpine sandstone. This sandstone is 5' thick in the Fiord No.2 exploration well, where it was described as being fine-to medium-grained, calcareous, and glauconitic with spotty, medium to dark brown oil staining. In this area, which is situated more than 2 miles from the nearest Alpine development well, the Alpine sandstone appears to be of fair to poor reservoir quality. The Kuparuk zone is a transgressive, shallow-marine lag deposit that is situated directly atop the LCU and is typically less than 5' thick. It consists of fine- to medium-grained, quartz-rich sandstone containing varying amounts of glauconite and siderite cement. Initial drilling results indicate the Kuparuk sandstone thickens locally on the western (downthrown) side of northwest-trending normal faults that occur in the development area. Kuparuk zone porosity averages about 22%, and air permeability averages approximately 110 millidarcies. Average water saturation is about 22% in the Fiord No.5 well. b. Structure: Within the Fiord development area, the structure at Kuparuk level dips to the northwest. During early Cretaceous time, faults were active creating accommodation space for accumulation of sediments. The main fault in the development area is termed the "Fiord" fault. Therefore, as stated above the Kuparuk reservoir is thickest on the downthrown, western side of this northwest- trending normal fault, and it thins toward the west. 7. Trap Configuration: Well log and seismic information indicates that the oil in the pool is trapped by both structural and stratigraphic elements. The trapping mechanisms for oil within the Kuparuk reservoir are the Fiord Fault to the east and stratigraphic pinch-outs into very fine-grained, non-reservoir rock in all other directions. The Nechelik reservoir is truncated by the LCU to the north, and it degrades to non-reservoir quality to the south and west. 8. Reservoir Fluid Properties: Geochemical analyses of reservoir fluids recovered from well tests of Fiord No. 5 and RFT tests of Fiord No. 4 indicate that oils trapped within the Nechelik and Kuparuk zones are likely the same oil. Oil viscosity ranges from 0.79 to 0.92 centipoise, solution-gas ratio ranges from 538 to 609 standard cubic feet per stock tank barrel, and the formation volume factor ranges from 1.299 to 1.333 reservoir barrels per stock tank barrel. Crude oil produced during testing measured between 28.6 and 31.3 Conservation Order 569 July 21,2006 . . Page 4 degrees API gravity. Neither gas-oil nor oil-water contacts have been observed within the Nechelik and Kuparuk zones within the proposed pool area. · Original Nechelik zone pressure is approximately 3,200 psi at 6,900' true vertical depth subsea ("TVDSS"). Reservoir temperature is approximately 163°F at 6,850' TVDSS. 9. In-Place and Recoverable Hydrocarbon Volumes: Estimates Kuparuk Zone Nechelik Zone Oil in place, million stock tank 20 to 60 60 to 130 barrels ("MMSTB") Primary Recovery, MMSTB 1 to 6 9 to 26 Waterflood Recovery, MMSTB 7 to 3 1 5 to 16 Miscible Water-Alternating-Gas 3 to 11 7 to 23 Recovery, MMSTB Total Estimated Recovery, MMSTB 11 to 48 21 to 65 · Peak production rates from the proposed Fiord Oil Pool are expected to range between about 14,000 and 41,000 barrels of oil per day. Waterflood injection rates are expected to peak between about 23,000 and 59,000 barrels of water per day, and miscible hydrocarbon gas ("MI") injection rates are expected to peak between 16 and 42 million standard cubic feet of gas per day. 10. Reservoir Development Drilling Plan: Seventeen extended-reach, horizontal wells will be drilled to develop the Fiord Oil Pool. Twelve wells will be drilled to the Nechelik · zone, six producers and six injectors. Five wells, three producers and two injectors, will be drilled to develop the Kuparuk zone. Within each reservoir, alternating development and service well bores will be oriented parallel to one another. Well bore spacing within the Nechelik will be approximately 2,100', and well spacing in the Kuparuk will be approximately 4,500'. At present, ConocoPhillips plans production and injection wells that are each dedicated to a single zone, with no subsurface commingling except where sand-on-sand contact · occurs between the Kuparuk and Nechelik zones, as in the existing injection well CD3- 108. 11. Reservoir Management: ConocoPhillips proposes developing this oil pool as a miscible water-alternating-gas (ltMW AGIt) enhanced oil recovery project. This process involves cyclic injection of water and enriched MI into the pool, and it enhances recovery through: a. water injection, which displaces oil in the reservoir, replaces produced fluids thereby maintaining reservoir pressure, and controls gas channeling; and b. enriched MI injection, which mixes with and mobilizes residual oil in the reservoir and allows it to be displaced by the injected water. Conservation Order 569 July 21, 2006 . e Page 5 Slim tube simulation of Fiord oil and expected MI composition indicate a miscibility pressure of 2,935 psi. Variations in MI composition are expected to yield miscibility pressure variations from 2,400 to 3,200 psi. 12. Reservoir surveillance plans: ConocoPhillips proposes that bottomhole pressure survey requirements be met by conducting stabilized, static pressure measurements at · bottomhole or extrapolated from surface 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 6,850' 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 Fiord Oil Pool have surface casing set at approximately 2,400' true vertical depth and cemented to surface. Leak-off or formation integrity tests are planned after drilling no more than 50' beyond the surface casing and intermediate casing shoes. Significant hydrocarbon zones · encountered in the boreholes outside of the reservoir intervals will be protected with cement. The Kuparuk zone will be developed using horizontal wells with 4-112 inch slotted liner across sandstone and blank liner across shale. Nechelik zone development will utilize openhole completions. Production will be conveyed to surface using either 3-1/2 inch or 4-112 inch tubing. ConocoPhillips proposes that all production wells within the Fiord Oil Pool be equipped · with a fail-safe automatic surface safety valve ("SSV") and a surface-controlled sub- surface safety valve ("SCSSV"). 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. Further, SCSSVs may 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: ConocoPhillips proposes to 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 requests waiver of the requirements of 20 AAC 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 ConocoPhillips is the only operator on the unitized acreage. Conservation Order 569 July 21,2006 . . Page 6 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). Well CD3-108 was logged using a complete petrophysical log suite through the proposed Fiord Oil Pool. c. Well spacing: eliminating restrictions on wellbore spacing to accommodate horizontal, line-drive wells and to maximize ultimate recovery. 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 proposed Fiord Oil Pool are sufficiently similar to those of the nearby Alpine and Nanuq Oil Pools to warrant consistent . operating rules for both pools. 17. Elimination of overlap with Alpine Oil Pool: Conservation Order 443A (corrected January 17, 2006) and Area Injection Order 18B (October 7, 2004) include Sections 13, 14, and 15 of TI2N, R5E, UM within the affected areas of the Alpine Oil Pool. Examination of well logs from exploratory well Fiord No.2 demonstrate that the Alpine sandstone is thin and of fair to poor reservoir quality within these sections. CONCLUSIONS: 1. Pool Rules for the development of the Fiord Oil Pool within the Colville River Field in the Colville River Unit are appropriate at this time. 2. The Nechelik and Kuparuk zones are in direct contact in the northern part of the pool and in hydraulic communication with each other. The two reservoirs contain a common accumulation of oil and therefore constitute a single oil pool. 3. . Sections 13, 14, and 15 ofT12N, R5E, UM should be removed from the affected areas of Conservation Order 443A (corrected January 17,2006) and Area Injection Order 18B (October 7,2004) and included in the affected area ofthis conservation order. 4. Monitoring reservoir performance 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. 5. Proper annular pressure management is necessary to prevent failure of well integrity, uncontrolled release of fluid or pressure, or threat to human safety. 6. The requirements of 20 AAC 25.050 (b)(2)(A) and (B) are unnecessary because ConocoPhillips is the sole operator of the Fiord Oil Pool. Conservation Order 569 July 21, 2006 . . Page 7 7. Waiver of the requirements of20 AAC 25.071(a) will conform to drilling and completion practices approved for the nearby Alpine Oil Pool and reduce administrative burden. However, a mud log and cuttings samples will be required from the base of conductor to total depth from at least one well from the CD3 drill site. 8. 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 development and operation of the Fiord Oil Pool, within the affected area, is subject to the following rules and the statewide requirements under 20 AAC 25 to the extent not superseded by these rules: Affected Area: Umiat Meridian Township, Range T12N, R4E TI2N, R5E T13N, R4E T13N, R5E Sections 1,2, 11 - 14 1 - 18 25, 34 - 36 15 - 22,26 - 36 Rule 1 Field and Pool Name The field is the Colville River Field. Hydrocarbons underlying the affected area and within the herein defined intervals of the Kuparuk and Kingak formations constitute the oil reservoir named the Fiord Oil Pool. Rule 2 Pool Definition The Fiord Oil Pool is the accumulation of hydrocarbons common to, and correlating with, the interval between the measured depths of 6,876' and 7,172' in the Fiord No.5 exploration well. Rule 3 Well Spacing There shall be no restrictions as to well spacing except that no pay shall be opened in a well closer than 500' to an external property line where ownership or landownership changes. Conservation Order 569 July 21, 2006 . . Page 8 Rule 4 Drilline Waivers a. Pehnit(s) to drill deviated wells within the Fiord Oil Pool shall include a plat with a plan view, vertical section, close approach data and a directional program description in lieu of the requirements of20 AAC 25.050(b). b. The suite of well logs acquired in CRU CD3-108 meets the petrophysical logging requirements of 20 AAC 25.071(a) for the CD3 drill site. The Commission may, in its discretion, require additional wells on a pad to be logged using a complete petrophysical log suite. A mud log and cuttings samples must be obtained from the base of conductor to total depth for at least one well from the CD3 drill site. Rule 5 Automatic Shut-in Equipment a. All production wells must be equipped with a fail-safe automatic SSV and a SCSSV. b. Injection wells, including MW AG, gas injection and water injection service wells must be equipped with either a double check valve arrangement or a single check valve and SSV. A subsurface-controlled injection valve or SCSSV 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 6 Common Production Facilities and Surface Commineline a. Production from the Fiord Oil Pool may be commingled with production from other CRU pools 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 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 7 Reservoir Pressure Monitorine a. A bottom-hole pressure survey shall be taken on each well prior to initial production or injection. b. The Operator shall obtain pressure surveys as needed to manage hydrocarbon recovery processes effectively subject to an annual plan outlined in paragraph (e) of this rule. c. The reservoir pressure datum will be 6,850' TVDSS for the Fiord Oil Pool. Conservation Order 569 July 21, 2006 . . Page 9 d. Pressure surveys may consist of stabilized static pressure measurements at bottomhole or extrapolated from surface (single phase fluid conditions), 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 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 8 Gas-Oil Ratio Exemption Wells producing from the Fiord Oil Pool are exempt from the gas-oil-ratio limits of 20 AAC 25.240(a) so long as the provisions of20 AAC 25.240(b) apply. Rule 9 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. By June 1 of each year, the operator shall schedule and conduct a technical review meeting with the Commission to discuss the report contents and to review items that may require action within the coming year by the Commission. The Commission may conduct audits of technical data and analyses used in support of the surveillance conclusions and reservoir depletion plans Rule 10 Annular Pressures a. At the time of installation or replacement, the operator shall conduct and document a pressure test of tubulars and completion equipment in each development well that is Conservation Order 569 July 21, 2006 . . Page 10 sufficient to demonstrate that planned well operations will not result in failure of well integrity, uncontrolled release of fluid or pressure, or threat to human safety. b. The operator shall monitor each development well daily to check for sustained pressure, except if prevented by extreme weather conditions, emergency situations, or similar unavoidable circumstances. Monitoring results shall be made available for Commission inspection. c. The operator shall notify the AOGCC within three working days after the operator · identifies a well as having (1) sustained inner annulus pressure that exceeds 2,000 psig, or (2) sustained outer annulus pressure that exceeds 1,000 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 notify the Commission within three working days 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 Commission under (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 (1) that the inner annulus pressure at operating temperature will be below 2000 psig, and (2) that the outer annulus pressure at operating temperature will be below 1000 psig. However, a well that is subject to (c) but not (e) of this rule may reach an annulus pressure at operating temperature that is described in the operator's notification to the Commission under (c) of this rule, unless the Commission prescribes a different limit. g. For purposes ofthis rule, · (1) "inner annulus" means the space in a well between tubing and production casing; (2) "outer annulus" means the space in a well between production casing and surface casmg; (3) "sustained pressure" means pressure that (A) is measurable at the casing head of an annulus, (B) is not caused solely by temperature fluctuations, and (C) is not pressure that has been applied intentionally. Conservation Order 569 July 21,2006 . . Page 11 Rule 11 Use of Multiphase Flowmeters in Well Testin~ For purposes of satisfying well test measurement requirements of 20 AAC 25.230, the use of multiphase meters will be approved only in accordance with the provisions of the Commission's document, "Guidelines for Qualification of Multiphase Meters for Well Testing" dated November 30, 2004. The Commission may administratively waive a requirement of these Guidelines or administratively amend the Guidelines as long as the change does not promote waste or jeopardize correlative rights, and is based on sound engineering and geoscience principles. This rule shall expire on December 31, 2007. 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. DONE at Anchorage, Alaska and dated July 21,2006. Daniel T. Seamount, r., Commissioner Alaska Oil and Gas Conservation Commission /~ Cathy P. oerster, Commissioner Alaska 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 23rd 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 o.f the Commission, to appeal the decision to Superior Court. Where a request for rehearing is denied by nonaction of the Commission, the 23day period for appeal to Superior Court runs from the date on which the request is deemed denied (i.e., 10th day after the application for rehearing was filed). CO 569, Colville River Field, Fiord Oil Pool (I Rules) . Subject: CO 569, Colville River Field, Fiord Oil Pool (Pool Rules) From: Jo~y Colombie <jody_colombie@admin.state.ak.us> Date: Fri, 21 Jul2006 14:18:16 -0800 To:undisc . . s>, Ken ews@radiokenai.com>, 10f2 7/21/20062:19 PM CO 569, Colville Rive~ Field, Fiord Oil Pool (I Rules) . Jody Colombie <iody colombie(lì?admin.state.ak.us> Special Staff Assistant 907-793-1221 Alaska Oil and Gas Conservation Commission Department of Administration 20f2 7/21/20062:19 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, 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 Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 -\IU~ ~\O œ' I\~f\ ID • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7 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 ary 11, 2011 Adive Daniel T. Se. .' ou , r., Commissioner, Chair • i1 . • :. s Conservation Commission f, ilirlf �• i�man, Coer IF a Oi • . . a Conserva ion Commission 0, ifil ' • / i _ , // or 4...... N th Cat y P. oerst- r, Commissioner � " `'' � ' Alaska •it 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)'; 'AKDCWelllntegrityCoordinator; 'Alan Dennis'; 'alaska @petrocalc.com'; 'Anna Rafe; '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'; '; 'Lara Coates'; 'Marc Kuck'; 'Mary Aschoff; 'Matt GIII'; 'Maurizio Grandi'; 'Joe Longo'; Lara Coates , Marc Kuck , Mary Ascho att , 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); Pasqua!, Maria (DOA) (maria.pasqual @alaska.gov); Regg, James B (DOA) (jim.regg @alaska.gov); Roby, David S (DOA) (dave.roby @alaska.gov); Saitmarsh, Arthur C (DOA) (art.saitmarsh @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 Scmwt F+%ahex Alcuska cm& ow/ Co-► t on'Co-w n iow (907)793 -1223 (907)276 -7542 (fa4v) • • • 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 President 408 18 Street 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 a. Anchorage, AK 99515 -4295 Fairbanks, AK 99711 Anchorage, AK 99503 Jill Schneider North Slope Borough Gordo n S everson US Geological Surve y P.O. Box 69 4 00 Uniersity Drive 3201 Westmar Circle Barrow, AK 99723 Anchorage, AK 99508 Anchorage, AK 99508 -4336 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 O 'M \`\ 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 4 Addressing Repts from Order Revised Rule - "Well safety valve systems" (2) Comment fail -safe auto SSV and SCSSV; injection wells (except disposal) require "I wells (excluding disposal injectors) must be equipped with(i) a double check valve Colville River Unit Qannik 605 5 no le check valve and SSV; injection 25.265(a); 25.265(b); 25 Check valve requirements for injectors are not covered by 25265 h () double check valve, or ii () single 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 ( )( 5 ) SCSSV satisfies the requirements of a single check valve." fail -safe auto SSV and SCSSV; injection wells (except disposal) require 265(d)(1); 25.2659(b); 25.265(x); 25. 25.265(a); "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve . Oooguruk Oooguruk Nuiqsut 597 6 no (i) double check valve, or (ii) single check valve and SSV; injection arrangement or (ii) a single check valve and a SSV. Asubsurtace- controlled injection valve or Check valve requirements for injectors are not covered by valve satisfies single check valve requirement; test every 6 months 25.265(h)(5 SCSSV satisfies the requirements of a single check valve" readopted regulation 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 Oooguruk Oooguruk Kuparuk 596 6 no (i double check valve, or ii sin le check valve and SSV; injection 25.265(a); 25.265(6 }; 25.265(d)(1) Check valve requirements for injectors are not covered by () single injection arrangement or (ii) a single check valve and a SSV. A subsurface- controlled injection valve or valve satisfies single check valve requirement; test every 6 months readopted regulation q Y SCSSV satisfies the requirements o a single c valve." Prudhoe Bay Unit Raven 570 5 yes fail -safe auto SSV and SCSSV; maintain list of wells w/ removed or 25.265(a); 25.265(b); 25.265(d)(2)(F); Requirement to maintain a wellhead sign and list of wells with deactivated SVS; sign on wellhead 25.265(m) N/A deactivated SVS was replaced with requirement to maintain a tag on well when not manned fail -safe auto SSV and SCSSV; injection wells (except disposal) require r "I wells (excluding disposal injectors) must be equipped with(i) a double check valve Colville River Unit Fiord 569 5 no (i) double check valve, or single check valve and SSV; injection 25.265(a); 25.265(b); 25 Check valve requirements for injectors are not covered by ii () sin g injection 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; 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 Colville River Unit Nanuq - Kuparuk 563 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 Check valve requirements for injectors are not covered by valve satisfies single check valve requirement; test every 6 months 25.265(h)(5 SCSSV satisfies the requirements of a single check valve." readopted regulation 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 valv 1 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 Check valve requirements for injectors are not covered by valve satisfies single check valve requirement; test every 6 months 25.265(h)(5 SCSSV satisfies the requirements of a single check valve." readopted regulation Prudhoe Bay Unit Put River 559 3 yes 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; 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 s 25.265(a) N/A Prudhoe Bay Unit Orion 505B 3 yes fail -sate aut 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; prescribed by Commission 25.265(h)(5) replaces SSSV nipple requirement for all wells Prudhoe Bay Unit Polaris 484A 3 yes fail -safe auto SSV; SSSV landing nipple below permafrost; test a s 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; prescribed by Commission 25.265(h)(5) replaces SSSV nipple requirement for all wells Milne Point - fail -safe auto SSV; SSSV landing nipple below permafrost; gas /M 25.265(a); 25.265(b); 25.265(d); Milne Point Unit 477 5 yes injection well require SSSV or injection valve below permafrost; test N/A Readopted 25.265(d) dictates which wells require SSSV; Schrader Sluff every 6 months 25.265(h)(5) replaces SSSV nipple requirement for all wells Prudhoe Bay Unit Borealis 471 3 yes 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; injection well require SSSV below permafrost; test every 6 months 25.265(h)(5) replaces SSSV nipple requirement for all wells Northstar Northstar 458A 4 no fail -safe auto SSV and SCSSV; test as prescribed by Commission; 500. Existin ft minimum setting depth for SSSV 25.265(a); 25.265(b); 25.265(d)(1) "The minimum setting depth for a tubing conveyed subsurface safety valve is 500 feet." 9 pool rule established a minimum setting depth for the SSSV Prudhoe Bay Unit Aurora 457B 3 yes fail -safe auto SSV; SSSV landing nipple below permafrost; test every 6 25.265(a); 25.265(b); 25.265(d); Readopted 25.265(d) dictates which wells require SSSV; y y N/A months 25.265(h)(5) replaces SSSV nipple requirement for all wells fail -safe auto SSV; gas /MI injectors require SSV and single check 25.265(a); 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 Meltwater 456A 5 no valve and SSSV landing nipple; water injection wells require (1) 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 25.265(h)(5 SCSSV satisfies the requirements of a single check valve." � 9 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); Prudhoe Bay Unit Midnight Sun 452 6 yes flow to surface); test every 6 months N/A - Readopted 25.265(d) dictates which wells require SSSV; 25.265(h)(5) replaces SSSV nipple requirement for all wells fail -safe auto SSV and SCSSV; SSSV may be installed above or below 25.265(a); 25.265(b); 25.265(d)(1); The setting depth of a required subsurface safety valve must be located in the tubing either Existing pool rule established alternate SSSV setting depth; 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 pressure; test every 6 months 25.265(h)(5 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 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 Check valve requirements for injectors are not covered by 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(a); 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 25.26.5(h) SCSSV satisfies the requirements of a single check valve." 4 9 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 Kuparuk River Unit; deactivated; maintain list of wells w /deactivated SVS; test as deactivated SVS was replaced q requirement to maintain a Kuparuk 432D 5 yes prescribed by Commission; CO 432D.009 modifies Rule 5(b) - LPP 25.265(a); 25.265(b); 25.265(h)(5); N/A placed with re Milne Point Unit 25.265(m) tag on well when not manned; administrative approval CO may be defeated on W. Sak injectors w /surface pressure <500psi w! 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 w ells ( excluding disposal injectors) must be equipped with(i) a requirements by Kuparuk River Unit Tarn 430A 6 no valve and SSSV landing nipple; water injection wells require (i) double 25.265(a); 25.265(b); 25.265(d); h() double check valve Check valve re uirements for injectors are not covered b 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 ) 9 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 ! q 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 /MI injectors require SSV and single check valve and SSSV landing nipple; water injection wells require (i) double Check valve requirements for iare not covered by n9 check readopted regulation readopted 25.265(d)(5) 1 q () "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve ; injectors rs does not include are 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 a a SSV. A subsurface-controlled injection valve or CO 406B.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 w/ notice when defeated and defeated on West Sak water injectors with surface injection pressure less than 500psi." 4068.001 remains effective [re:defeating the LPS when surface placed back in service injection pressure for West Sak water injector is <500psi] fail -safe auto SSV and SCSSV; LPS trip pressure; readily accessible Badami Badami 402B 6 yes control unit SSSV below permafrost; NTE 210days between tests; 25.265(a); 25.265(b); 25.265(h); submit test results electronically within 14days; SVS defeated /removed 25.265(m) N/A only if well SI or pad continuously manned fail -safe auto SSV (S /D well and artificial lift); sign on well if SVS Prudhoe Bay Unit North Prudhoe 345 4 yes deactivated; maintain list of wells w /deactivated SVS; test as 25.265(a); 25.265(b); 25 Requirement to maintain a wellhead sign and list of wells with 25.265(m) N/A deactivated SVS was replaced with requirement to maintain a prescribed by Commission tag on well when not manned fail -safe auto SSV (S /D 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 SVS 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 N/A deactivated SVS was replaced w /deactivated SVS; test as prescribed by Commission 25.265(m) with requirement to maintain a valve installed below base of tag on wet when not manned suitable automatic safety Bay Unit Prudhoe - Kuparuk 98A 5 yes y permafrost to 25.265(d) N/A Readopted 25.265(d) dictates which wells require SSSV; prevent uncontrolled flow replaces SSSV nipple requirement for at 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 I Page 2 of 2 • • Public Hearing Record And Backup Information available in Other 66 . . SARAH PALIN, GOVERNOR AI,ASIiA. OIL A5D 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 I 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 I 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)(l)(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 fresh 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 fresh water. Therefore, the Commission hereby approves ConocoPhillips requested gas off take rate with the following conditions: 1. The cumulative gas offtake rate from the CRF must not exceed 1 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 2300 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 aio 18b-003 CRU CD2-48 . . Subject: aio 18b-003 CRU CD2-48 From: Jody Colombie <jody _ colombie@admin.state.ak.us> 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.ok.us>, Terrie Hubble <hubblet1@bp.com>, Sondra Stewman <StewmaSD@BP.com>, stanekj <stanekj@unocal.com>, ecolaw <ecolaw@trustees.org>, trmjrl <trmjr 1 @aol.com>, jdarlington <jdarlington@forestoil.com>, nelson <knelson@petroleumnews.com>, cboddy <cboddy@usibelli.com>, Mark Dalton <mark.da1ton@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.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@cflrr.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 <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 <rmclean@pobox.alaska.net>, mkm7200 <mkm7200@ao1.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>, 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>, 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>, Karl Moriarty <moriarty@aoga.org>, Patty Alfaro <palfaro@yahoo.com>, Jeff <smetankaj@unocal.com>, Gary Rogers <gary_rogers@revenue.state.ak.us>, Arthur Copoulos <Arthur_Copoulos@dnr.state.ak.us>, Ken <klyons@otsint1.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 aiol8b-003 CRU CD2-48 . . <admin@aleutianseast.org>, Marquerite kremer <marguerite_kremer@dnr.state.ak.us>, Mike Mason <mike@kbbLorg>, 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@kakivik.com>, James B Regg <jim_regg@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@exxonmobi1.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@m1.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 <matt_rader@dnr.state.ak.us>, carol smyth <carol.smyth@shell.com>, Arthur C Saltmarsh <art _saltmarsh@admin.state.ak.us>, Chris Gay <cdgay@marathonoi1.com>, foms@mtaonline.net, Rudy Brueggeman <rudy.brueggemann@intemationa1.gc.ca> Jody Colombie "> Special Staff Assistant Alaska Oil and Gas Conservation Commission Department of Administration Content~ Type: application/pdf aio18b~003.pdf Content~Encoding: base64 20f2 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, 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 Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 ~~~\\~~\ \V\ y\ \\ \ • • suul ALAs[KKA SEAN PARNELL, GOVERNOR ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMMISSION 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 2 of 3 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, C0443 B -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. slc� ott 409111N it... at Anchorage, Alaska and dated June 2 11 co 4. 7 At/ ._,. I ", �� Daniel T. Seamount, Jr. ' ► rm Cathy P. Foers er Chair, Commissioner • r lsslo 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 @conocophiliips.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) (Iinda.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); Pasqua!, 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 I I 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 Associates 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 -4 e c3.‘. , t .. , . _ ,, 'I`HF, STA`I i LA5K GOVERNOR BILL WALKER Ms. Misty Alexa Afaska, 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 Seventn 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. Se ount, 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 Home; 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, lames 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 I1 Alaska Oil and Gas Conservation Commission 333 West Th Avenue Anchorage, AK 99501 (907) 793-1223 (phone) (907) 276-7542 (fax) CONFIDENTMUTYNOTICE: 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 a -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. Ca Aisle@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 Angela K. Singh THl' STATE "ALASKA GOVERNOR BILL WALKER Alaska Oil and Gas Conservatian Commis Gn ADMINISTRATIVE APPROVAL CONSERVATION ORDER NO. 562.004 CONSERVATION ORDER NO.569.003 CONSERVATION ORDER NO. 605.002 (Corrected) Ms. Misty Alexa Manager, WNS Development ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 333 west Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Re: Docket Number: CO-15-007 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 (Corrected) 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 �~ i47. Cath P. Foerster Daniel T. Se ount, Jr. Chair, Commissioner Commissioner4sM RECONSIDERATION AND APPEAL NOTICE \; i ; 1 t;S 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, 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, Angela K (DOA); Wallace, Chris D (DOA); AKDCWellIntegrityCoordinator; Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew Vanderlack, Anna Raff; Barbara F Fullmer, bbritch; Becca Hulme; bbohrer@ap.org; Bob Shavelson; Brian Havelock, Bruce Webb; Burdick, John D (DNR); Carrie Wong; Cliff Posey; Colleen Miller, Crandall, Krissell; D Lawrence; Dave Harbour, David Boelens; David Duffy, David House; David McCaleb; David Steingreaber, David Tetta; Davide Simeone; ddonkel@cfl.rr.com; Dean Gallegos; Delbridge, Rena E (LAS); DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Frank Molli; Gary Oskolkosf, George Pollock; ghammons; Gordon Pospisil; Greg Duggin; Gregg Nady; gspfoff, Jacki Rose; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Williams, Jennifer L (LAW); Jerry Hodgden; Jerry McCutcheon; Solnick, Jessica D (LAW); Jim Watt; Jim White; Joe Lastufka; news@radiokenai.com; John Adams; Easton, John R (DNR); Jon Goltz; Juanita Lovett; Judy Stanek, Houle, Julie (DNR); Julie Little; Kari Moriarty; Kazeem Adegbola; Keith Wiles; Kelly Sperback; Gregersen, Laura S (DNR); Leslie Smith; Lisa Parker, Louisiana Cutler, Luke Keller, Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt, Mark Wedman; Kremer, Marguerite C (DNR); Mary Cocklan-Vendl; Michael Calkins; Michael Duncan; Michael Moora; Mike Bill; mike@kbbi.org; Mikel Schultz; MJ Loveland; mkm7200; Morones, Mark P (DNR); Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nick W. Glover, Nikki Martin; NSK Problem Well Supv; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Renan Yanish; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer, Sternicki, Oliver R; Moothart, Steve R (DNR); Suzanne Gibson; sheffield@aoga.org; Tania Ramos; Ted Kramer; Davidson, Temple (DNR); Terence Dalton; Teresa Imm; Terry Templeman; Thor Cutler, Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater, Anne Hillman; Bajsarowicz, Caroline J; Brian Gross; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Don Shaw; Donna Vukich; Eric Lidji; Erik Opstad; Gary Orr; Smith, Graham O (PCO); Greg Mattson; Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Holly Pearen; Hyun, James 1 (DNR); Jason Bergerson; jill.a.mcleod@conocophillips.com; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Kenneth Luckey; King, Kathleen J (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck, Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Matt Gill; Franger, James M (DNR); Morgan, Kirk A (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Richard Garrard; Richmond, Diane M; Robert Province, Ryan Daniel; Sandra Lemke; Sarah Baker; Peterson, Shaun (DNR); Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); Todd, Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster, William Hutto; William Van Dyke Subject: 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 Or. 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 qi&7c t l@ l A„C Angela K. Singh THE STATE 01ALASK 1 GOVERNOR &ILL 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 wvvw,aogc c. olaska.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 I 1 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 WIT ake 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 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. Rule 6 of CO 569 is amended to read as follows: Rule 6 Common Production Facilities and Surface Comminalin2 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 ComminglinE 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.oerste 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 after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on aweekend or state holiday. TI IN. STATE "ALASKA (.oiNTRNl�p 11111 \ 'AI KFP Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVALS CONSERVATION ORDER NO. 443C.001 CONSERVATION ORDER NO. 562.005 CONSERVATION ORDER NO. 569.004 CONSERVATION ORDER NO. 605.003 Mr. Stephen Thatcher Manager, WMS Development North Slope Operations and Development ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510 Re: Docket Number: CO -18-002 and AIO-18-014 333 west Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 aogcc.olaska.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 r 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 1 I 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 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 terns of this administrative approval. Rule 6 of CO 569 is amended to read as follows: Rule 6 Common Production Facilities and Surface Comminalin¢ a. Production from the Fiord Oil Pool may be commingled with production from other CRU pools and the Lookout Oil Pool in surface facilities prior to custody transfer. b. Production shall be allocated to wells within the Fiord Oil Pool in accordance with the procedures described in Section 5.0 of ConocoPhillips' application dated November 22, 2005. c. Each producing well must be tested a minimum of twice per month. d. The Commission may require more frequent or longer tests if the allocation quality deteriorates. e. The operator shall retain electronic file(s) containing daily allocation data and daily test data for a minimum of five years. f. The operator shall provide the Commission with a well test and allocation review report in conjunction with an annual reservoir surveillance report. CO 443C.001, CO 562.005, CO 569.004, and CO 650.003 August 13, 2018 Page 4 of 4 And Rule 6 of CO 605 is amended to read as follows: Rule 6 Common Production Facilities and Surface Commineline a. Production from the Qannik Oil Pool and other CRU pools and the Lookout Oil Pool may be commingled in surface facilities prior to custody transfer. b. Production shall be allocated to wells within the Qannik Oil Pool in accordance with the procedures described in Section 6.0 of CPAI's application, dated April 3, 2008. c. Each producing well must be tested a minimum of twice per month. d. The Commission may require more frequent or longer testing if the allocation quality deteriorates. e. The operator shall retain electronic file(s) containing daily allocation data and daily test data for a minimum of five years. f. The operator shall provide the Commission an annual well test and allocation review report in conjunction with the annual reservoir surveillance report required under Rule 9 (below). DONE at Anchorage, Alaska and dated August 13, 2018. //signature on file// //signature on file// //signature on file// Hollis S. French Cathy P. Foerster Daniel T. Seamount, Jr. Chair, Commissioner Commissioner Commissioner As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which The AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC greats an application for reconsideration, this order or decision does not become final. Rather, the order a 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 not is nm included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 Penny Vadla 399 W. Riverview Ave. Soldotna, AK 99669-7714 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 n 0 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 RECEIVED) Hollis French, Chair MAR d 1 2018 Alaska Oil and Gas Conservation Commission 333 W. 7th Ave #100 AIDISCIC 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 W V 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 V 25,000 � 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 Jan -43 Application to Amend CRU AGOTR February 28, 2018 Page 5 of 5 ir.:r7 90 so 70 0 Z' 60 0 0 So O 0 30 d m E 30 in 20 j Assumed CmdRlons Pressure = 3750 P. 10 ' Temperature = IS! Current Injectant A 0 20 ?+0 Er) eJ 100 ._. 140 Pore Volumes of Gas Injected, % PV itectant is +—Lean Gas— CurrentCampo s; cral Blend-+- 10:<. Er richmg F'ru id 15:: Enriching Fluid- NY- Enriching Rud Figure 3. Simulated Oil Benefit of Gas Injection 160 17 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 RECEIVED Hollis French, Chair MAR n 1 2018 Alaska Oil and Gas Conservation Commission O1.1 �IJ�C� 333 W. 7th Ave #100 Anchorage, Alaska, 99501-3539 RE: Request for Administrative Amendments, Colville River Unit, North Slope, AK Dear Commissioner French, ConocoPhillips Alaska, Inc. ("CPAI") as operator of the Colville River Unit ("CRU") and Greater Mooses Tooth Unit ("GMTU"), requests that the Alaska Oil and Gas Conservation Commission administratively amend area injection orders for the Fiord, Nanuq, and Qannik oil pools to allow injection of GMTU Lookout Oil Pool ("LOP") produced water into any of the other CRU oil pools. CPAI also requests that the conservation orders for the Fiord and Qannik oil pools be amended to allow commingling of LOP production in surface facilities prior to custody transfer. This request is being made concurrently with applications for a LOP Conservation Order and Area Injection Order. Those applications provide further background for this request. The CO application explains that LOP production is expected to be compatible with production from the CRU oil pools. The Fiord, Nanuq and Qannik pools area injection orders have specific rules for "fluids authorized for injection." LOP produced water is not specifically listed as a fluid authorized for injection. The recent Commission order authorizing the expansion of the Alpine Pool Area Injection Order provides that "[pjroduced water from the Alpine Central Facility" is a fluid authorized for injection. See Area Injection Order No. 18D, Rule 1b. CPAI requests that the Alpine pool language be used to amend the Fiord, Nanuq and Qannik area injection orders to allow for injection of any produced water from the Alpine Central Facility including LOP produced water injection. This amendment will provide for consistency in CRU oil pool area injection orders. CPAI also requests that the Fiord, Alpine and Qannik pool rules be amended to allow for the commingling of LOP production in CRU surface facilities prior to custody transfer. The Nanuq oil pool rules allow production to be "commingled with production from other pools in surface facilities prior to custody transfer." See Conservation Order 562, Rule 7a. CPAI requests that similar language be adopted for the Fiord, Alpine and Qannik pools to allow for the commingling of production from these oil pools with other production at the Alpine Central Facility. Request for Administrative Amendments February 28, 2018 Page 2 of 2 Please contact John Cookson (265-6547) if you have questions or require additional information. Regards, ! 5?, 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 16 ConocoPhillips June 16, 2015 t' i I ", Misty Alexa Manager, WNS Development North Slope Operations & Development ConocoPhillips Alaska, Inc. AWGG 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 ill r 1 • • Roby, David S (DOA) From: Soria, Dora I [ Dora .I.Soria @conocophillips.comj 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); Neumann, 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.soriae/conocophillips.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); Neumann, Michael P (DNR) Subject: Attendance sheet AII, 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 I I 2 aosse k k rwa 7 94 -- -1 z'/ 3A D /oz , - - �� (>° s- y -) X3 ..214.E�, • pp 1-931,-83i kAesflroct otivzifrItt.1 v\ky•N we3a • i • • • • • ConocoPhillips • • • • • CPAI • • AOGCC "Application Report" for • the MPM Multiphase Metering • System • • • • • • • • • • • • MultiPhaseMeters • • • • • • • • • • • • • • • Prepared Parviz Mehdizadeh and Gordon Stobie • 12/14/2010 • • Cover Letter • • G Street Anchorage, A 700 AK 99501 ConocoPhilhips Phone: 907 - 263 -3701 December 14, 2010 Daniel T Seamount Jr., Commissioner RECFIVED Alaska Oil & Gas Conservation Commission 333 West 7 Avenue, Suite 100 DEC 2 1 2010 Anchorage, AK 99501 Alaska 8Q & L3as Cots. C®mmissiof Re: Application Report for MPM Multiphase Metering System Ancl orege 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 t•bove mentioned tests. Taking into acc. 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. Report • • • • • • • • • • • • • CPAI • • AOGCC "Application Report" for • the MPM Multiphase Metering • • System • • • • • • • • • • • • • • • • • • • • • • • • Prepared Parviz Mehdizadeh and Gordon Stobie • 11/11/2010 • • • 12- 02- 2010AOGCC MPM for Approv • • 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 • 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 0 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 • • • • • • Ill 1 - • • • • • • 02- 2010A0GCC MPM for Approvaidoc • • • • 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- 2O1OAOGCC MPM for Approval. • • 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 0 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 • • • • • • •2- 2010A0CCC MPM 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 Sak 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• • • The flow first passes through a Venturi, which is used to measure the total mass flow rate. • 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 • 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 4im • Gamma Detector — a • • — Single Energy Gamma • . • Sensor Body l 1 Electronics/ • Transmitters %; Flow computer • (P, dp) 3D Broadband • Ilk "� �" _ section • Salinity Probe 1 iv • r i./. Termination Box • Venturi • Inlet connection • • • Figure 1- The main components of the MPM meter • • 5 -17 • • • • • • 02- 2010AOGCC MPM for Approval.doc • • • • V � i C i 1 • • t1 /,''list • • 0 • • 9� ,, ' • 11, , F4 • • 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 Appendix 2. - I • �_a ver tea, _...� r • X 1!!1 • . b i 1: • i I I 1 - • nag IF • . Ill C... ,. T • i� sECnn..> wnw= TOP 1.71 • GENERAL A 121 68G �.. II • Figure 3 - Schematic of the MPM Well Head configuration • 6 -17 • • • • 12- 02- 2010AOGCC MPM for Approval. • • Table 3 — Summary of MPM Accuracy (Uncertainty) Specifications at 95% confidence level • Topside & Subsea Meter • Uncertainty i i Sensitivity • MultiPhase Mode GVF range - °Jo GVF • WLR 0 - 80 80 - 96 0 - 95% Gas Flow Rate 0 - 100% 5 % 5 % ± 0,5 °Jo • Liquid Flow Rate 0 - 100 9 2.5 % 5 % ± 0,3 °Jo • WLR <5% & >85% 1 % 1 % ± 0,1 5 -85% 2% 2% ±0,2°Jo • 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 °Jo 10 % ± 0,3 Hydrocarbon mass flow 0 - 100 °' 3 % 3 % ± 0,3 % • Water Fraction (abs) 0 - 100% 0.1 % 0.1 % ± 0,01 % WetGas Mode - 2 Phases ( 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 To • 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 mSlcm > 50 mS!cm • Multi Phase (Salinity Probe) ±2mS /cm (4) ± 4 % rel (4) • Wet Gas (S- curve) ± 50 mS/cm (6) ± 50 mS /cm (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 0 • • • Test Separator • Flow from wells 16ft by 5ft Dia I • • • MPM • • • • • Figure 4- Schematic of MPM Installations at Alpine 7 -17 • • • • • • •2- 2010AOGCC MPM for Approval.doc • • • • • g • I • - 1 • • Dow nwa ID Flow To parato 1' Upward Flow ` 7 y � • To MPM • • • 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 Approv • • 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 • 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 l6ft 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 • • • • • •2- 201OAOCCC MPM for Approvaidoc • • • • 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 -3.1 411/ 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 -33.7 102 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 Approval• • • 6000 f .. - • '• s- 6000 _ 1% • : : • M` e r r Imo- .,� • s -` T � ` • w i 300+0 - f '.. • 1. ' j' • x yr+ 8 2000 - t .r F - - DP saturated > 5000 mbar • 'c f • Q. 2 1000 - s • ...41.1" 4 • ♦,, • a 1000 2300 3000 4 000 5000 6000 • Alpine ssparetor liquid dowret• (stb(d) • 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. • ,00 ., • • 1 70 - • 4 J - • r f II 500 - I .- • ' • • • 10. ,.- • i r 0 -{ - ° • 0 10 20 30 40 50 00 70 00 90 100 Alpine seperetDr water out 4%) • Figure 7 — Water Cut comparison MPM Meter to Test Separator The dotted lines show the ± • 5% variation band • • • • 11 - 17 • • • • • • •2- 2010AOGCC MPM for Approval.doc • • • 2500 • ° a b'M ° , - • 2000 - _. .. _ J - Iies m f • ill /' , ° • 1500 - , - ° • m ± ' y 1000- ° -.- tn to • a / �s �, • ° 500 - ° ° -' j • t f ° • 0 , • 0 500 1000 1500 2000 2500 • Alpine separator oil flowrate lstbld) • Figure 8 — Oil flow comparison MPM Meter to Test Separator the dotted lines show the ±10% • variation band. • 10000 .�.r r - • .� J d �t- 0000 + �J F r r • ,� o r - ' a - .,r 1+� 3 ,,= • v 'r* _ v r J . r �� ,F r • r, so)* r . r ,' • 5 rf • 4003 r • ` ?.r - • }- _ - • :1= - 1 10 , "- • . "1 • 10a5 MO WOO 1000 5 000 OCCIO 7100 OIXO EN 1 • Abele separator q s flowrate illo(h) • 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. • • As noted previously the gas data in Figure 9 shows a positive bias. The MPM meter used the • 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 41900111400 • 12 • 10 • 8 -Gas Density PVT [kg/m3) • 6 - Measured Gas Density • 4 [kg/m3] • 2 • O *I - 4 N N m m .7 =t / N m 0 v1 ti0 t0 r- • • e.i k.r$ '40 n 00 C 2 -$ N m Q -a 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 [ %] [%] • 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 • Total 7 -0.4 DP >5Kmbardata remove • • 13 1 • • • • • •2- 2010A0 \IPM for Approral.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 10BarG - 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 • • Table 8 - Flow Conditions and Fluid Properties In MPM Tests • Test Location Liq Range ;Gait Rangee'-WLR Range; : GNF Range Pressure - . Temp OR API 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 65 -130 38 -52 3 -Phase TS 96-120 (560- • SWRI 0 -150 8.5- 33.9 0-25% 95 -100 1750 -2940 112 620) Variable water salinity 0- 100 %R *, 0- 100 %R *, 88- Stable and Slugging • Ekofisk 0 -8300 1.7 -13.6 300 -350 78 -205 35 1.5 -48% N 97 %N flow • K -Lab 2008 NA NA 0 -100 94 -100 450 -1800 65 -130 94-100 24 Month Wet Gas 2010 Tests • 30 -93%N, 0. Slugging, Emulsions • Alpine 300 -5000* 2.8 -7.8 0.100 %R* 180 -220 65 -80 40 and variable water 100 %R 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 0-100% 95 -100% 1000 60-75 67 Multiphase • • Table 9- Summary of Field and Flow Loop Test Results • Test Location 1 Liquid 1 Gas I WC � Oil 1 Water 1 Reference Used • MPM Flow Lab ±1.1% ±1.23% NA 1.2% +0.03% Loop Sep - 1 • 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% 0.83% Test Sep - 3 Phase -I • Gullfaks Jan 07 ±1.4% - 1.4% NA 0.82% 1.36% Test Sep -3 Phase -2 SWRI Wet Gas * * ** ±0.7% 1.2 - 1.63% NA 0.96% -2.6% Loop Sep -2 Phase -2 • SWRI Wet Gas * * ** ±0.7% ±1.2 - 1.35% NA +5.69% -2% Loop Sep - 3 Phase -2 • pp Ekofisk * ** r +1.2% +19.9 * ** +1.5 %abs r +3% -5.8% Test Sep * ** • K -Lab 2008 -2010 ±5 -10% ±5 -10% ±5 -10% ±5 -10% ±5 -10% Data not Released • Alpine* - 4.7% +7.3% 0.42% +3.7% -5.4% Test Sep - 2 Phase -1 Alpine - Post Proc ** -2.6% -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 • I = 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 214M • 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- 2010AOCCC MPM for Approtiaf.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 Fossd 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- 2OIOAOGCC 141PM 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% • 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% • • • • • • • • dir • � ` �° Ha B aY • Ko9N River +m „ } �.. • .er • 4h 4 NW h11LNE 1 . \ • ■ \! / i i i.. smarm tcom, �� • jc•i t l r. ' • • 'A) 1_� . 3R •. O (� Q DE W SITE I Al� = C \ ' MINE SITEE 8 in. A 41111r,N‘ + 3M S K PD J E • t \ / S W SAK 1 3 N \ W A 7 N W SA 2 H 411 10 • • �t ` E . fir - �. 31 3K , _..._,., 3Fl•'D ` 3H , EUGNU PROD. TEST • [II '1 i� 1 A // / - l!'ll): �t..JJ WSAK 11 • CD - KUPAR IR STRIP 1 12X tA MINE SITE F i 1 MINE CPF- STORA. CO -5 ALPINE WEST • Bear Tooth Unit '- • iiid 2A I ' ,x 1P1 41E '1D MP1 ..�.. u Z W SAK 1 \ CD-4 N UO Allii FT -2 ° 1 � CD8 L• •'OUT 1\ Fr ` ' ° • 2F • Colvill i iver Um '2G i • � 2( Kuparuk River Unit ° • CD-7 '-ARK NUIOSUT n • L ; 1 • ) A W SIAK 25818 .... ,„ ---. • Greater Mooses Tooth Unit • I � N • • 1 \ % W +E / j \_ / • NPR - A s, illii , 1:340,000 -' 0 1.252.5 5 7.5 10 411 ? Miles • Y � Kuparuk River Unit zv f• / • Alask. ConocoPhillips • 1 • ci ` CPAI Operated Facilities • L. . „f" Map r 411 r =:h 1 10100701A00 10 -7 -10 • 1 • • Appendix 2 • • • • • • • rnpm • MuttiPhaseMeters • Appendix 2 • • MPM High Performance Flowmeters • • Installation and User Manual • • MPM Topside Meter • • • 0 • 41, .- lR • • ;, • • • �.- • 10 . • • • • • 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 -003B • 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 4 • 1.5 ABBREVIATIONS 5 2 MPM METER DESCRIPTION 5 • 2.1 GENERAL 5 • 2.2 HIGH PRESSURE/HIGH TEMPERATURE DESIGN 7 • 2.3 TOPSIDE METER 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 Extemal 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 5.24 The Information area 24 • 5.2.5 Graphics area 25 • 5.2.6 Status bar 26 5.3 ALARM STATUS 27 • • TO -010 — Installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 2 of 41 • Project Confidential • • • • • • • • • mpm • VAIF- ttescz • 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 / RECALIBRATION 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 • • • 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: supportempm- 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 • • • • • • • • • • MPM • • • 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. • • • • ,. • • • • • • • _ o ftall • • • • Focus during the development phase was to design a High Performance Meter, characterized by: • • • High operational stability • Unique sensitivity and reproducibility • • Unparalleled accuracy • • • TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 5 of 41 • Project Confidential • • • • • MP M • r.rf • The MPM Meter is an in -line and full bore meter, based on conventional multiphase metering • equipment in combination with the patented 3D- BroadBandTM 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. All 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 Tess • 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 • • • • • • ,• • • • MPM • to • 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- m 203. At the end of the program, DNV issued a Statement of DET NORSKE VERITAS • Compliance, for design conditions as follows: STATEMENT OF COMPLIANCE • P design < 15 -�-- kPSI • T design < 480 °F (250 °C) • - Water Depth < 2700 m ITY • The design and qualification program was further done in accordance to °"""" " "" • • ISO 13628 • • API 17D/ API 6A. • NACE compliance ,u :k ng f.•7 • Z44- • • 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 • • • • • • MP • • 2.4 Mechanical parts • • • Outlet connection — — • Electronics Enclosure • r Gamma Detector — J • • • M l — Single Energy Gamma Sensor Body • Electronics/ Transmitters • Flow computer ;,. • (P, dP) • , 3D Broadband .TM I • � , � section Salinity Probe W � • ° Termination Box Venturi • Inlet connection • • • 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 BroadbandTM 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 • • • • • • • • MPM • 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. The field electronics system is located in the meter housing. The 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 • industrial temperature range of -40 °C to 85 °C. When selecting the electronics units for the system, special attention was made towards z • finding modules with high MTBF figures which had undergone vibration - • and shock testing in addition to HALT (Highly Accelerated Life Time air Test). • • • • • • • • • • • • • • • • • • • • • • • TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 • Project Name: Magnolia, Entrada Page 10 of 41 Project Confidential • • • • • • • • • ITI PM • • 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. • 01 .N.. , I r • • MPM Meter electronics and MPM terminal • • Remote PC FIELD SENSOR AND ELECTRONICS • a 2 a • U • Modbus j mpm _.--ftS 485orTCPnP Flow RF Terminar Compute PCt DSR N Serial Electronics' • 3 a Q jig i • CL o� .O =l II 2 V oa 2S III °I1 • . 211-- vil ■i SCADA I Transmitter Sensor • • The MPM Meter communication protocol is MODBUS v1.1 a. 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 • • • • • • • 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 MPM Terminal (optional )— — Me!ter lagging • meter. It is possible to connect multiple meters to 8� one terminal. its tasks comprise the following: Communk81tlan • scwt� • Poll configured measurement variables at • configured intervals. • Log the polled measurement variables. • • Log alarms, events and diagnostic °ota,t, 3 information from the connected meters • • Create and distribute periodic reports for • service personnel by e -mail, if SMTP server is available titi r - • Run diagnostic functions • • Upload software updates } • Upload configuration /calibration data. I • • 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 1,,,„„h„..„._vetErs • • 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 dPoutlet 1 • dPoutlet 2 • Temperature 1 Temperature 2 • Pressure 1 • Pressure 2 • Gamma Detector • • • TD -0 10 - Installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 15 of 41 • Project Confidential • • • • • • • mpm • 4.3.2 External communication ports • • Before starting error logging on extemal 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 Tess 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 Tess than 0.1%. • Communication Number of Number of errors Error rate [ %] Conclusion • Channel messages • Primary Eth1 port • Primary Eth2 port* • Only app ®cable for electronics wtth redundant Ethernet card • • 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 • • • • • • • • • • MPM • • 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 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 • • • OH 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 P Mol % _ Mol wt [kg/m3 • • 1 if the MPM Meter is equipped with the automatic configuration option (salinity measurement), the • importance is low • • TO-010 — Installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 17 of 41 • Project Confidential • • • • • mpm • 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 IC4 0,583 58,124 • nC4 1,263 58,124 • IC5 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 • • • • • • • • • • mm Nutt,, e,mo6 • • 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 oft 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 took -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 look -up table can be calculated • from the composition for the well. • • 4.4.4 Input of look -up sit and gas densities _,I S�r'I • tables PVT Input type Oden* table O8dens89tkg 31 • In this case, oil and gas Pressure Pang] • densities are provided at 15; e given pressures and 10 �0 �o o 20 830 840 eso 03a vo • temperatures in tabular Temperature 30 eAO 850 880 870 sect form. tom. CI 40 850 eat 870 sea • 50 860 870 880 890 900 • To find the correct densities sffi1 for a given temperature and • pressure, the Meter will do a 10 Fressuef8argJ loss, ,noz 10.03 1014 • linear interpolation between 10 8 e e s the data points in the table. 9 9 Temperature 30 10 10 10 10 10 • In the figure is shown typical lam. n w 17 11 „ 11 11 • density table 50 12 12 12 12 12 The other PVT data are • keyed In via the GUI/ PMP I OK II Cancel 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 • Click on the Icon for the MPM GUI, a login- window like User fuser • the one in Password: • Terminals: • Figure 1 will appear. If the Name 1 Server na 11Paddress • desired MPM terminal is not available in the list, it must loop Termer mpmp Rerntin 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 • I Connect II Cancel I • • • • • 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 (intemet 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. • • MiPM Gill v.1..0.0.212-1 - Sulnca Primary (1010) >-t l X tar and configuration Meter Service Diagnostic D rev: - Update trends and values - -- Trends - - - l - -- - -- -- - - - .__ .. _- - --- ----- ----- _ --_ -. • r Graph averages ® Update Oil, gas and inter flow -- a n ins =. Gr - Flaw rates (Actual c tio,) wrr Ir': Oil nPfi • Oi IIIIME m'!h Gas ( 0010/h Gas 0 ' m'fi Water lMU ,&i • Water �� 1 m'fi i I I - - - - - - [hd yeed � mm ' 1 • Formation MIME OA, Measured tractions -- - - - -- -- • VAR _. - " n m n ass 'Lax • O 4 �R�7;�:. 12.41:0 u uzm GVF MOM —sa. t:> Graph averages - -- - - Sal,nityandConductiv,ty —�crc lm5: - GOR ' ' m'im' Sal. f 0.tl : • - -- -- - -- - - 2 send I 0 ool mskm • Other - - � L - - - -- - -- Temperature W • C ��'{� Pressure 0 Barg st 1'+ I • • Density IIIIIIIIl E k e rip Imo "' • ' Velocity 0.' mss SWI E .. 3 aver, .a.. ,.; ., , �a • Water conductivity MEE nSicm 'gym 1.2.601 nt.m taster salinity tire,:. Graph avrsapes - . . • I+A.R and Gtf —�,cr; Scale Indus MU : ,x .m WLR MEET: -- - -- - -- - - GVF I 10001: • - Active process data set - - - a- -s: -.- N°1- Subsea Meter Number One le- -s= ., • Status ! 0 :OK re .c- -A . Q Meter Online _ _z �� • a 3 • '4012301 c'TAX 11.2.2:01 12490 vwm uMm • 0 undefined `0 WGM mode (3phave) 0 Measured w. density 0 Measured w. conductivity !Staple / Slug Quality 0•4 1110% , 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 • • • • • S • • • mm • 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 1 ` 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 • • • I S • • • • • • • • • • • • • • • • TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 23 of 41 • Project Confidential • • • • • • • mpm • v,:st -tail tietc: ^a • • • 5.2.4 The Information area • The Information area displays current values for [ trends and values - - - - --- - I • flow rates, measured fractions and other j ® Update _ • measurements. rates (Actual carrdtx s) } • A check box on the top makes it possible to ! Oi 32.8 rnvh {!I • stop the updating of values. This is useful if the Gas 253.5 n/ operator wants to stop the update and evaluate the data. Water __._._._.. 34 m;/ • ._.. - Measured fractions ------------- ._..— • The flow rates are presented in the selected Wt_R 9. 3j% j • units. ,A 0.01% Measured fractions display the fractions GVF 87.51% • calculated by the MPM Meter. GOR 0.01 rrr'lrrr' j • The area called "Other" show some of the Other . 4110 transmitter readings, calculated velocity, Temperature X1' • measured Water Conductivity (converted to Pressure 16.31Barg • 25 °C) and measured Water Salinity. Density 0.0 kg/m= • j The status light is green if no alarms are active dP 204.9 mBar • on the meter. If an alarm situation occurs, the Velocity 0.0 m/s light switches to red. SWI 0.0 % j • Click on the light to view Alarm status. From the mSlcm Water conductivity 2.63 1 • Alarm status it is possible to click "View event log" to see the details (See also section 5.3). ! Water salinity 0.81. Scale Index NA1 e • The meter connection state light is green when • the meter is online. If the meter is offine or Status • having communication error (no contact with the 0 Status: OK meter), the light switches to red. 0 Meter Online • 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 • • • • • • • • • • kt_ ,c L • • • 5.2.5 Graphics area • Trends • -.yam =;t; Graph averages Oil, yas ar>dwater — Caisi Water Oil? r,, sz- ars (31 _ Oil I 32.01 r&/h • + " I Y y t .fli"41I FtiVtJ`V '. . a,,, °'YA for . Water I 3.51r?/t, • Gas 258.1Irr/h i X39: • S • tom_ - -X ... • e ^ F✓ rvWJ'✓ V.-.. y+..'/' WwJ'.. -.' VYv...•.-.. �- vti' vuw' u v. r`. m^.-+ �w- vn"1�.�'.rW- .- ^.'�n.�1N+ s I .. r - - z.- 1 • 6 i. 3231. - 3 . :% — Sal. rr" Graph averages • Sali rity and Conk c vitp c,r.,. t18' - 1 �r fj �j JL� Q _ S al. 0.8 • p { I i/"��1i�1.I WVtN ° .I. Y�p ` �"W r�Ii i � ` /L 2a Cond ( 2.73ImS /cm • -. I 1 r ti ' ,'N' 1. 1 4 ,iPtii ::) ktl �yu d- 2 • K .e- 8 • :2- • , • -'J,RR (` Graph averages VILR ar?d G'•IF — 3VF t°45 • .-,x WLR I 9.8 • 9. �._..._ - _. - - ___ , -ts GVF I 87.91 • 2* 61 .12X7 _ =...f. '3.',20. :27: _ .,- • Figure 5 Graphics area • • 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 • t, +•,rrf rNe, �; • • 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. • Qw =Mims (p MTN , ip - - - - - Measured w. d ii Measured se c«,aucti�v Stable 1 Slug ;Quality oz _ (roar 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 • • • • • • • • • mpm • t • • 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 light 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 • Q dPIniei Q Q • dPOutlet • Pressure Q Q • Temperature Q Q • 3D Broadband • Software • External Communication • ( OK Q Failed j 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 • • • • • • • • • MPM • • • 5.4 Event log • • 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 tng ® - -il • 0 • Severity Process __ -. _.. .._.. _.. Evert id ❑Into ❑DSP Interface ❑ Mew conu,xricaGon Save 'A data i9rt(Trl titer data a broadband mw) hes failed (16333) • �A large gap in raw-data (scoured No interpolation don (1 64001 ❑ Warning ❑ External C00000n , ❑ Process Supervise fie IA strange data value href web as occued (16040492) 1) ACo,vo10 eel pah charrcrel (2 ❑ Ella ❑ Flow Calculations Tranrndter Interface I C oul pr 0 datim as (16388) Could not fed we [41081 ❑Log Cab not open tale caalhrati • m constant: nCl961 Date Severely Source Process Evart Id l Event Desatotion • e 03 - 1 2.2006 13 Warring Flow Candeti m ora 163E8 Cakulan issue • 08.1 2 2006 1258 • Warng Flow Calculations 16388 Calculation issue 08.122006 1253 (swannng Flow Calculations 16388 Calculation issue 08.122061250 Info DSP Interlace 20491 DSP/Electrarics dogmas values • 08122006 1250 � Info DSP Interface 20492 Accantated parse ref channel 08.1220061050 Il_ )Info DSP Interface 21490 DSP Serial pat diagnosis values 08.12.2006 1248 . i X lWarcg Flow Calculators 16388 Calculation issue • _ 0E1221061243 • Waring Fbw Calculations 16388 Calculation issue _... 08.1 2 2086 1238 Warri g Flow Calculations 16388 Calculation issue • 08.122008 J Info DSP Interface 20492 Acwnulated parse ref channel 08.12 2006 1035 Jlrfo DSP Interface 20491 DSP/Electronic: diagnosis values 01122006 10 1 Info DSP Interface 20490 DSP Serial port diagnosis values • 08.122061233 Wang Flow Calculations 16388 Calculation issue 08.1221061028 wing Flow Cakukeora 16388 Calculation issue 08.12 2086 1223 Warring Flow Calculations 16388 Lactation issue • 91.1220901020 ,Into DSP Interface 21490 DSP Serial port diagnosis values _- 08.122%161221 • Into DSP Interface 20491 DSP/Electronics diagnosis yak.. _ 29306 1220 Info DSP Interface 20492 Accumulated pah:e ref charnel • _ - _ 08.1 2 2008 1218 , Waning Flow Cactatiau 16388 Calculation issue -_, 011221061213 ' Waning Fbw Calculations 16388 Calculation issue • 08.122006 1208 ' Wang Flow Calabtions 16888 Calculation issue 08.1220061205 ,V Info DSP Interface 20492 Accuulatedpahse ref charnel ( Fast page I I Previous Pape I Nest page I 1 Lacs Page 1 )Page 1.1230 I • • Figure 8 Event log • Event properties Milt ((�� ® Event Id 20490 Sever4y: Info I f • Date: 08.12.20061250:56 Process. DSP Interface 1 4 • Meter Local Meter Description: • 11lr >;'I1sS�aR:18:'TTIIE:uTi!`�J • • ' Addtional data: r Bytes (Hex) G Text • P' SU -OK, TXU -OK, RXSMU -OK, TXSMU -OK, RXU -OK, HWCU -OK • i • • • • • Figure 9 Event properties • • TD - 010 — Installation and User Manual — MPM Topside Meter.Rev01 • Project Name: Magnolia, Entrada Page 28 of 41 Project Confidential • • 411 • • • • • • • • • 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 • Meter untold test meter 2 Stan 105.11.200714 :1201!,1 End 15miutes i Log interval O.5 second I View I Export 11 Close 1 Trend -- - -- -- -- -_... • _... __.. AvaiaGe variables. Local seta ^ • dPl iet dFlydett dPIrlet2 • — Cl3u A eIn..11 — '�dlstalltola ne[n';'fi �Matti A :.nlyaiyneimsti oPGullel ix_ dPOutlet dPOutlet2 • Emulsion alders FCStatus 0=2.11111==.11111 1 • ,.1v V1 AP , A Js,r eisVA ' a ' . A1P -L ,' / o'�J1ti " � t�' GarmaCoint �%- �, Gas density Gas velocity • GOR Mass GOR Standard Mara GOR Standard Volume x.:_ GOR Volume GVF Actual Volume • bow! velocity MeterStatus Ma density • Oil dens y Rescue Pressures • Presre2 QFdmLVater Actual Mass QFormWatet Actual Volume • QFormWater Standard Mass GFormWater Standard Volume • gas: Actual Mass • QGas Actual Volume QGas Standard Melt s- QGas Standard Volume • QOi Actual Mau .�- 4.,w..w.�w�.u4.N -vt , n•, vvr... yn ,,. •y i✓ •vy1 „ r� .Mnn ,.• .� , w ,,, wvu QOi Actual Volume - ON Standard Vass • ON Standard Volume QuaRylndex • a•-n- a - ,x- - QWder Actual Man • /! • Figure 10 Trend/export data • • • • • • • • • TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 29 of 41 • Project Confidential • • • • • • • mpm • • • • • Dialogue toolbar • I _ - 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 fog 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 • f,,,:N Mt.,tw„ • 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] XI P rocett data set s m.a,e - 1 Watercabratbn • Name - - - !Average Composition ford went on LFuriei 1 i Water eondudiv0 d Fwed t7 Meaesred • Description j i Water density O Feed 0 Messed 1 1 -- Water - - • l' Den* kg/m3 at temperature =IQ deg. C f 9t mS /era at temperature 25 deg. C • ..__-- _. -. - - -. -- „. .- -- _. -- d Matarirgyottirgt ._ -_ -- - - - -.. -- - -- -- - - - -- .._. -_ — i - Con , n • . i later Measurement 'node 0 WetGas ©M se O Automatic MPM GVF I 96 s : „- I {off_ , • WGM GVF 97.01 i�l , . I l. 1 = 1 • i ® Use Broad Band den* - Standardcordtions - -- -. - - -- - - - - - -- __ .. _. - .._ .. • Minimum GVF for Broad Bard measuement 1 88.51 ; . Density of I 856.0071 kg/m� I 151 deg. C at Mawrxm GVF for Gams meaawmenl ( 9,9.01 - Deraily gas 0.807 kgM 1 01 bag • ❑ Use Moving Average liter Oft output data • ❑ Use treed GDR Fixed GDR I ' I , 0 Use Lookup table ❑ Disable B8 FiedWLR I -r1 ❑ Add flashed gas komoff • -- - .. _ , , ❑ Enable Live PVT input . -- -- • - Dielectric constant Dielectric constant offset - . ; Gas mace tension -- - - ; O I :1 ❑ Override at I 1 deg C OR 1 01 Gas fuss trop c Emmert 1 1.41 ' ® Water /gas ace tension wafer ( from wata N aak - - • Gas 1 1 ❑Override 1 ' bag Gas 1 01 UseDiyAiDens3y ❑ - - -__ -- - - -- • Salt wain factors - - Viscosity at actual conditions - - Water viscosdy factors - - , - Water sandy liter limits - - - - - - Mass absorption coefficient -- - - - BO I :1 Olt 100081491Pas j D0 I 0,7181 , , Min value 1 0.91% , OR I I ❑ Override • 81 I - - 1 Gas 1 1.59E-051Pas 01 1 0.033591 Max value' 41X Water 1 1 ❑ Ovenide • B2 1 " '1 We 1 ,1Pas ❑ Use ; I D2 1 01 - - -- - - - -- - -' Gas 1 1.01 Ovmdde -- — - - -- - -- • 1 Bose • • 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 look -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 • TO -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. Le., 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 • • • • • • • • • • mm n^,n, t seta $ • • 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 berg) 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 took -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 Isentropic 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 • • • • • • • M PM • nwrMerr • • 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 "Catc 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 • • • • • • • • • • mm MuttiPtawMeers • t • • 5.7 Dialog toolbar • psi Send to meter _j 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 • 14.,yr- i,„r•t aetcrs • • 5.8 PVT, Oil and Gas properties dialogue • Oil and gas properties J • • Pt/T'atpudiSrPs Q table (:) • Viacc6sty I GOR (Actual conditions)! Surface tension oilgas 1 Oil gas mass transferfactor 1 • Density aal kAn31 • T [deg. Ci • I 601 ?u E 0 ' 90' 100 25D ( 544 620 6 201 920 620 • 6 i i _ ._ - ...___ 260 I .__._ 586.E 524 520.9 vt '. Pressure -- — • 1 g1 27D 624 ! 523.6 S 59 0.9 ' 5: +.9 574 -5 280i 620' 5E0 5; r.E ; 574.E 571.5 290 j 620 ; 57721 574.9 i 571.6 , 562.4 • Density gas t1 • Temperature [deg. q I 301 3 40! 45; 50 • 190 14 140.9 136'9 1332 129.E • t Pressure 19: 142.4 ( 144.2 14D.2 ' 126.5 133 • EB&gl 2..r+ 151.2; 147.5 1t3L. 139.6', 132 c_ --. 5$ 146-6 i 142.7 139.1 • 205 1551 150. t 210 15E.3 1 _.5 145.7 175.E 142.1 411 • I OK II Cancel I • • 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 • • • • • • • • • • MPM kk :1a.;,034.1ra • • Oil and gas properties 1 :1 5 --- • FYT input type (;) table 0 cerftv_,..IY3r4 • Densky 1 Viscotily I GOR (Actual concitionsOurface tension oil/gas 01-> gas mass transfer factor I • oar -) gas mass Monier factor • Temperature (deg. q t • 4o i so r 93! io3 1 1 ito 20 00..002233 0.024 • . 1 25 ao21 02H 0. 0.021 i ' 0.0211 0.022 ■ 0.023 : :.. I - -- • Pressure ' 30r _1 00 22 ao23_.4 ! _ o.c24 i i 1 , • 35 : 40 0.028 ( 0.031 , a031 0.032 , 0.031 i I 0.034 i 0.035 0037 i I 0.037 oxpl 0 • • • • • • • • _ _ I OK II Cancel 1 • • • • • • • • • • • • • • • • • 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). • • • -_ OP Centre Server _ • MPM .R Operations Centre • Internet Example: • f FIELD B - Africa Example: .IQa FIELD A - North Sea UPYT / M- ermine! • d • �Qa it I • • III • • • TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 38 of 41 • Project Confidential • • • • • • • • MPM • • In .,u; °t ,r,aete -3 • • • 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 �:Ent Maamoura 01 (#4027) PICT Ei • CAmemunication millimeter Last reset time: 01.04.2008 0a37:47 • Effort 0 • Total 395 1 Reset error counter 1 • Traramite 1 Errors 1 Total (Pinion 0 1592 • cfIrrkt2 8 NA NA 0ut1 NA NA • ____:c ut et2 NA �— NA Gammal 0 1241 • Ganvna2 NA NA • Pressurel 0 i 1591 Pressure2 NA 144 • Temperatue1 0 1591 Teapaature2 I NA NA • 1 Read 11 Reset . 1 1 ck. 1 • 1 • 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 • 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 Tess 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 • I,d.an, n�err, • • • 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 internal 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 • • • ~k14 • • November 30' 2007 Dave Volper of Pioneer Natural Resource called 11/28/2007 to Christine Mahnken, requesting to review CO 569 and AIO 030. Given the information and message to Jody Columbie who is the final say in the process for information concerning AIO's and CO's. Permission was granted, 11/29/2007. Dave then wanted copies of both items after looking through them. AIO 035 is 195 copies @ .25 cents each = $48.75 CO 569 is 221 copies @ .25 cents each = $55.25 CO 569 oversized copies @ .50 cents each = $7.00 NO Emails were copied for the request. 0 STATE OF ALASKA • ALASKA OIL AND GAS CONSERVATION COMMISSION W. 7th Ave. Suite 100 ANCHORAGE, ALASKA 99501-3192 REQUEST FOR EXAMINATION OF AOGCC RECORDS I, the undersigned, request that I be authorized to examine the AOGCC records listed below, I agree not to remove or alter the contents of records and I agree not to remove the records from the room designated for examination. I, certify that lam neither a party, nor representing or acting on behalf of a party, involved in litigation in a judicial or administrative forum with the State of Alaska or public agency to which these records are relevant. Signature: 0" � V Printed name: Company/Firm: � J I U n t er 0, �V'VA' Kf-so yc't; Address: �0 (�' S{ S �'\ i ' � 06 Phone No: 3L-13 - Z % 3 7 AOGCC RECORDS REQUESTED J a� yT - FOR AOGCC USE ONLY: Date and Time Records Requested (6 AAC 96.320): Date and Notice of Receipt of Request Sent (6 AAC 96.310): Date Additional Information Requested (6 AAC 96.315): Date and Time Records Provided for Review: Date and Time Records Returned: ,.r Y c An�r� n 1 .. 71' 1?0.,, r- lvanae of r�v001- Employee Handling ..eq—t. AOGCC will respond to this request as soon a practicable, but no later than the 10th working day after the request is received (6 AAC 96.325) This request is a public record. (6 AAC 96.320) \\ Common\Library\Request for Examination of Records Form.doc ;4/46�Ol &WH466* ' OI F16 APO" QRTY, STATE, ZAP ORDER I SOLD SPIN" TO, A:55-R-Essx— ".TV, STATE, ZAP �F( "OUAMTRINIF DESCMPTIOW11 ppler. 7615 sop-p'rovp - -RTYSTATE, x1p M41"I! MIME C)-L -0— w Owx -,5 3 r4 7 40 Page 1 of 1 Colombie, Jody J (DOA) From: Volper, Dave [Dave.Volper@pxd.com] Sent: Wednesday, November 28, 2007 4:09 PM To: Colombie, Jody J (DOA) Subject: Fiord data request Hi Jody, I am looking for public data Area Injection Order and Pool rules information for Fiord Oil Pool. Thank you, Dave Volper 907.343.2137 11 /30/2007 #13 . . Colville River Unit Gas Off Take Analysis Background: On February 8, 2007, ConocoPhillips Alaska, Inc. ("CPAI") applied for an allowable gas off take 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 CPAI 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 of Injection 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 formation 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 formation volume factor for the injection gas stream that is used above yields a maximum potential voidage replacement loss of760 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 oflean gas that will be i~ected 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 offtake 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. /"'ì ~~.:~~~/ 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 Mr. John Norman Alaska Oil and Gas Conservation Commission 333 W. 7m Avenue, Suite 100 Anchorage, AK 99501 {Jj <~ RE : Gas Allowable Colville River Field Alpine Oil Pool Fiord Oil Pool N anuq 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 ("EOR") 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 CD1-09 production well was shut in last year, this gas provided additional reservoir pressure support in the CD1-09 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 #11 . Subject: Fiord Seawater Co1fipatìb~ From: "WaIk~, Jack A" <Jack.A.Wa1ker@conocophìllips.com> 18 Jo12006 12:15:00 -0800 . ''-.,....L.. Steve, Brine sensitivity testing was completed on Nechelik core from the Fiord 5 well in 2002 in the Phillips Bartlesville lab using a salt saturated Beaufort summer seawater (10X concentration) and normal Beaufort seawater (1X concentration). The 10X concentration represented the maximum brine permeability. Compatibility of Beaufort seawater with Nechelik interval was established with this testing. Steady-state water-oil relative permeability tests on Fiord 5 Nechelik core samples were conducted in 2001 in the ARCO Plan lab using brine of similar total salinity. From the relative permeability testing, it was concluded that Nechelik injectivity should be higher than Alpine. This test also demonstrated compatibility of seawater with the Nechelik interval. Please call if you need additional information. Jack Walker North Slope Operations and Development ConocoPhillips Alaska, Inc. 265-6268 #10 lFwd: Re: lCRU: Fiord Pool KulesJJ IÞ . Subject: [Fwd: Re: [CRU: Fiord Pool Rules]] From: John Norman <john_norman@admin.state.ak.us> Date: Fri, 17 Mar 2006 17:21 :33 -0900 To: Jody J Colombie <jody _ colombie@admin.state.ak.us> print for public inquiry file -------- Original Message -------- Subject:Re: [CRU: Fiord Pool Rules] Date:Fri, 17 Mar 2006 12:24:35 -0900 From:Stephen Davies <steve davies(a?admin.state.ak.us> Organization:State of Alaska To:Alfred James <ajiii88(a?hotmail.com> References:<BA Yl 0 I-F 134770 1 OA1412399] 4BFD9ADEDO(a?phx.gbl> Dear Mr. James, <>According to the Alaska DNR's land records, the working interest owners in Tracts 113 and 115 are ConocoPhillips (78%) and Anadarko (22%). It is my understanding that you have an over-riding royalty interest in these two tracts. As you know, both of these tracts lie offshore, within lease ADL 388527, and inside of the second expansion of the Colville River Unit (see http://www.dog.dnr.state.ak.us/oil/programs/units/2002/CRU 2ndEXP finalF&D 11.08.02.pdt). Both ConocoPhillips and Anadarko have approved the Colville River Unit Agreement and the Colville River Unit Operating Agreement. ConocoPhillips, as Unit Operator, has two proposed wells near Tracts 113 and 115: CRU CD3-111 and CRU CD3-112. Public information concerning these wells has been published in the Commission's Weekly Drilling Report for March 5, 2005 and the Monthly Drilling Report for February 2006, available on the Internet at http://www.state.ak.us/local/akpages/ADMIN/ogc/drilling/dindex.htm. Both of these wells will lie inside the Colville River Unit and their closest approach to the Colville River Unit boundary will be about 1/2 mile. <> As proposed, CRU CD3-111 and CRU CD3-112 will conform to the 500-foot setback specified in State of Alaska regulation 20 AAC 25.055 (a)(1). Set-back requirements established by regulation 20 AAC 25.055 are based on property lines where ownership and landownership change. As defined in AS 31.05.170, neither of the terms "owner" or "landowner" encompass over-riding royalty interest owners. If anyone has concerns about correlative rights, the first step is always to address those concerns with the Unit Operator. Sincerely, Steve Davies Petroleum Geologist AOGCC 907-793-1224 Alfred James wrote: lof3 4/9/20063:21 PM u'wa: Ke: LLKU: nom 1'001 KU¡eSJJ . Steve: I note in AS 31.05.110 (Unitization and protection of correlative rights of owners), sec.(b)(4) provides for commission order to create a unit to protect, safeguard, and adjust respective rights and obligations of the several perons affected including royalty owners, overriding royalty owners, oil & gas payments, carried interests, mortgages, lien claimants, and others, as well as the lessees. Looks like that might include us...if data supports it...right? Thanks, Fred James . Prom: Stephen Davies <steve davies(cì¿admin.state.akus> To: ajiii88(cì¿hotmail.com CC: bodarrah(cì¿onemain.com Subject: Re: [CRU: Fiord Pool Rules] Date: Thu, 09 Mar 200616:31:47 -0900 Dear Mr. James, The Fiord Pool Rules are in progress, and are expected to be published in the next few weeks. As the Commission processes each permit to drill application, our staff closely monitors proposed well trajectories to ensure correlative rights are protected. Recently, permits to drill have been issued for wells CRU CD3-111 and CRU CD3-112. These proposed wells lie within the boundaries of the Colville River Unit and conform to the property line set-back requirements established by regulation 20 AAC 25.055. The term property line referenced in this regulation denotes a change in ownership and landownership, terms that are defined in section AS 31.05.170 of the Alaska Statutes. Commission regulations are available on line at http://www.aogcc.alaska.gov, and Alaska's oil and gas statutes and definitions can be found on line at http://www.legis.state.akus/cgi-bin/folioisa.dlllstattx05/query=* /doc/ {tI3188}? Reporting requirements are specified in regulation 20 AAC 25.537. Accordingly, the Commission makes the following information available to the public: ! of3 4/9/20063:21 PM [Fwd: Re: [CRU: Fiord Pool Rules]] . . surface and proposed bottom-hole location for a well after approval of the Permit to Drill; total depth, bottom-hole location, and status after the Well Completion or Recompletion Report and Log is filed; regular production data and reports; and regular injection data and reports. All other data and logs are held confidential by the Commission for 25 months from the date of completion, suspension or abandonment of a well. During this period, the Commission cannot release any confidential data unless the operator gives written and umestricted permission to release all of the reports and information at an earlier date. You must discuss your request for confidential data directly with the operator. Please let me know if you have any additional questions, and please refer all inquires on this matter to me. Sincerely, Steve Davies Petroleum Geologist Alaska Oil and Gas Conservation Commission (907) 793-1224 John K. Norman <John Norman@admin.state.us> Chairman Alaska Oil & Gas Conservation Commission ,0f3 4/9/20063:21 PM #9 . ConocJPhillips . Chris Alonzo Development Supervisor, WNS ConocoPhillips Alaska 700 G Street Anchorage, AI< 99501 Phone: 907.276.1215 January 25,2006 RECEIVED JAN 2 7 2006 Alaska Oil & Gas Cons. Commission Anchorage Mr. John Norman, Chair Alaska Oil and Gas Conservation Commission 333 West ih Avenue, Suite 100 Anchorage, AK 99501 Re: Contraction of the Alpine Oil Pool Affected Area Colville River Field Dear Chairman Norman: ConocoPhillips Alaska, Inc. (CP AI) as operator of the Colville River Unit and on behalf of the Working Interest Owners, requested a conservation order regarding the proposed Fiord Oil Pool, and an area injection order (AIO) authorizing enhanced recovery operations in the proposed Fiord Oil Pool. The proposed affected area for the Fiord Oil Pool conservation order and area injection order overlaps with the affected area for the Alpine Oil Pool under Conservation Order 443A and Area Injection Order 18B. CPAI requests a contraction of the affected area for the Alpine Oil Pool such that there is no overlap with the proposed Fiord Oil Pool area. The area of overlap of the proposed Fiord Oil Pool with the affected area of CO 443A (corrected January 17, 2006) and Area Injection Order 18B (October 7,2004) is Umiat Meridian Township 12 North Range 5 East Sections 13, 14, 15 as shown on the attached map. CPAI requests that these three sections be contracted from the Alpine Oil Pool and Area Injection Order 18B affected area. 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 . . Contraction of the Alpine Oil Pool Affected Area Colville River Field January 25, 2006 Page 2 cc: Alaska Department of Natural Resources Division of Oil and Gas Attention: Mike Kotowski 550 W. ih 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 825 W. 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 I Contraction of the Alpine Oil Pool Affected Area Colville River Field January 25, 2006 Page 3 Colville River Unit --.J I I , , , \' "\ '\. \. " '\ \. '\ " ... \. ... \. \ \ '\ \... ; " 'I.... ~ , ~ '" \. -..-" , ~ ~ .::::-.... ... " CI M Oil Pool Contraction Map ------- Requested AOP Contraction UM T12N R5E Sec. 13, 14, 15 Existing Wells Proposed Wells #8 . . CPA forecast of the Fiord production profile (Confidential) #7 Conoc~Phillips Alaska, Inc. . . * # P. O. BOX 100360, ATO-1454 ANCHORAGE, ALASKA 99510-0360 ~ ~ ~. .~ RECEIVED Telephone 907- 265-1505 Facsimile 907- 263-4966 .II.:: \) J 3 Z006 To: Jack Walker -, .Alaska Ojl & Gas CtlIlS. Commission ~ Anchorage ..4 From: Wayne Campaign CPAI Petrophysicist Subject: Attachment 3, Shallow Salinities in the Fiord Pool area. Date: January 11, 2006 The purpose of this memo is to discuss the presence of potential Underground Sources of Drinking Water (USDW) in the area of the Fiord Oil Pool. Four wells have been selected for this analysis. They are Fiord's 1, 4, 5-PB1, and Nigliq 1. All have porosity logs up to the surface casing points, with MWD GRlResistivity to surface. Analysis for water salinity has been carried out using the Rwa technique common to the industry in the sections with porosity logs, down to a depth of 4000'. The MWD logs are then used to provide qualitative evaluation from surface casing to the base permafrost. Individual annotated log plots are included with this document. The first concern is to pick base permafrost. Permafrost is defined as the depth at which equilibrium formation temperature is DoC, and can only be reliably picked from a stabilized temperature log. The only geophysical manifestation of this condition is the presence of ice in the sands. The difficulties of this have been previously documented in the attached memo "Shallow Salinities in the Nigliq Area" (Feb. 26, 2001), submitted in support of the Nigliq drilling permit application. Using the method developed in that example, lowest "Ice-Bearing Layers" have been picked in the subject wells, with base Permafrost assumed to be below those depths. All wells indicate frozen sands within the permafrost. Fiord 4 indicates two sands between permafrost and a depth of 4000'. The water sand @ 2660' md calculates salinity of 14 Kppm. The sand @ 3000' md contains gas, making salinity calculations invalid. An RFT pressure set was attempted in this sand. The zone drew down to < 100 psia with no flow. Fiord 4 also shows sands of high salinity within the lower part of the permafrost, at depths of 1355' and 1580-1620' md.(refer to attached log plot). Nigliq also has 2 minor sands in the interval. One of marginal quality and high apparent salinity, the second (2865' md) calculates salinity of 20 - Kppm. Salinity is also calculated in the shales of all wells and presented as histograms at the bottom of the plots. Though absolute accuracy may be slightly in question, the conclusion of saline conate water, is not. We conclude there is no evidence of USDW's in this area. If you have questions or comments, feel free to contact me. Wayne Campaign Staff Petrophysicist ConocoPhillips Alaska 907 265-1505 1. VlJ.eJ'v ~rr- ~ 5 / ÎD ~J Áe.Q- rik t~ FIORD_I 501032016200 ~/ ConocoPhillips LOCA TIO'" tAr· 70.411197 LOf4G: - 150.8' -14 7 ZONE:: ASP-1 X: "'00011.2ß Y: 6002857 FIELD NORIH AI.ASKA rxrLORA110N DRILLED DEPTfI 102;,0 STATUS SPUD DATE 1992-02~01 COMPLETIO", DATE 1992-0'~ 18 OPERATOR N¡CO ALASKA DHIATION ElHATIONS: KB Jft GL SAMPLE QUALITY r ("; VSH 3: ...-......- I o V/V 1 tds ss 1.65 RHOB_EDT 3 G/C3 NPH.!:S 2.65 o KPPM '/'J't.': i. RD__2 40 DEPTH SSTVD i-------õiñit------ióå ,;ii- nn nu RWA_3 ...-.-....- ..,"-_..._."..~...-. l:1J 0.1 OIlMM 10 150 D'f_2 USIY 50 1200 ~t :::¡:: ...rti-~T~~:;, · ~ ' ' . :"...... "'" . ~ ~... -..~ r-....'" _. ¡ ~ ; ...... '- '\ -Z .:-='''''-------'- ~~..,.,..... Ice_Bearing Sands 1300 .. 1900 ~--'- ..: .~:~;' . ' . ",' w' -,.- ------'-f~ ~'~- · · ----11' 1400~ i ==:~l ~ ( ". --"\. ----'-'- ;> ~ -~ ", ,.1 ---.: --> ~ 1100 --l ---.J - --"'.~. .;.' ~\- ì 1 800 .::.:ïL...--.....:. ---;4:-. ~. .( _t- \ 1900. :. -f" ~ 1360' md Permafrost? (Uncertain) 1300 1400 -- -- 1500 1500 1600 1600 1700 1800 -.- 2000 Porosity logs only extend up to 2388'. GR and Resistivity from MWD are displayed above that depth to illustrate the section. 2000 21 00 ,. ~ ---'~ -z-- ~ I conclude there are no sands between the casing shoe and the Permafrost, nor high resistivity to indicate salinity change. 2100 2200 · To: Dave Bannan Laurie St. Aubin From: Wayne Campaign Shallow salinities in the Nigliq area. Feb. 26,2001 Subject: Date: PHIUIp¡, Œ1 PH.JPS Alaska, Inc. A Subsidiary of PhiLLIPS PETROLEUM COMPANY This document will discuss the evaluation of shallow aquifers in selected North Slope well logs. The purpose is to demonstrate that the casing programs intended for this year's wells will protect potential aquifers. Further objective is to identify and map these potential aquifers for future references, or to document the absence of such aquifers if that is deemed to be the case. Several wells have been selected for this study. These wells have been picked base on the presence of sufficient shallow logs, and for geographic coverage over the area of Exploration interest to Phillips. The logs have been evaluated for water salinities using common techniques to the industry and specified in the EP A document. ARca Colville River St. #1 PermafÌ'ost Pick Gamma Ray ~ 10 111) IL SP W _-Delta IìììiíI -90 MV 1ft Q 1 200 lTõ"..,....~-·'m-n ~ 1 r I 'mnl : IIII': ~"__ ~~ ---iTrr¡r¡rrri¡¡ . 1_~!,..5 '¡Iil:!¡ Iii 'L.þ' ;III:'~' I' ¡ I I: i ¡!!,!]Ì I, II ! 1: -,-rn:El Ii" ! t S ¡ ! 900 . t ¡ flHI 1'!iiT " I '2i i -:-¡--II:---I'I! lit'·!: , , . 1..1 I I:' I; J i ¡ II '''I ¡HI i i: I pi Old PiCkllt~'Iii¡ í {.;- ! 'I .flU II,~ .]> 1 "h.-..L 100d" II i: HI li'~ j"¿ 1 Þ !~: !i'ill II I.r, lii¡ihi,III!1i ; !~: iil¡!¡¡ ::':·'Tfi I! II ill - ¡:' ¡: , ' þ; "00 ii~! I~'!<i :1:'fI¡"I:!,'·-~ ¡ i i S: :i6¡j ¡! iH!: tl'~' ~"'iI" I '" : 1200 ,~·.·III' :; .1"". ! ! : '.," I I; 1.1 i ' I I . ':' j i Hi 1_ i ~ ;!-',,' \1 II I~,<,,- ¡liIV,III:- I I I if I mil' II II' n I i I I þ1300 "ii"'" ~ ~: : i ~ u¡ New Pick ':.. : ~s:.:i ~_ I , ~ _~~ I, ¡r ,',' '~, I i ¡.3 1400 II i! .1 : !~' ( :~:~ ~::' -¡-~~ .-,---7- 'X_ ',~ 1500 II l i,1 : ~ +~~:- 1* tm- ? i- f i One facet of this evaluation is unique to the arctic. The first step is to select the base of Permafrost. It seems the sands freeze while the shales do not. This makes the shales conductive and the sands resistive. In the past, many have picked Pennafrost based on a 'simpÌe resistivity cutoff, usually 100 Qm' s. When possible, I have employed sonic information as well. Ice consolidates these uncompacted sands and the sonic displays faster travel times. Below the frost level, the sands show travel times similar to the shales. This example from the ARCO Colville River State #1 illustrates this. Note that a simple resistivity cutoff would place Base Pennafrost much higher. Keep in mind, this only represents a "Ice-down- to" pick. There must be sand present in the section for the permafrost to be detected by any means short of a stabilized temperature survey. In fact, temperature data collected from Alpine suggests permafrost to be significantly deeper than these techniques have implied. Frozen sands will present high resistivities for reasons other than low salinity. Calculations will be meaningless. Phillips Alaska, Inc. is a Subsidiary of Phillips Petroleum Company · PHlnI" ~ PHII.lPS Alaska, Inc. A Subsidiary of P ILLlPS PETROLEUM COMPANY Also, the sands would not flow anything and could not be considered aquifers. Similar meaningless results would occur with the presence of hydrates, though they can exist at temperatures above freezing and just below actual permafrost. These situations need to be identified and excluded ftom this work. Two methods are used in this evaluation. The "Rw Apparent" or Rwa technique re-writes the Archie equation Ro = a*Rwfcþm to solve for Rw. The assumptions are; the sand is 100% water bearing (that is the implication of the term Ro to represent the sand resistivity), and no excess conductivity (shale) in the system. Porosity (CÞ ) is derived from Neutron-Density crossplot when available, but more often ftom the sonic, as it is more common in the shallow sections. For sonic porosity, I use an adaptation of the "Hunt-Raymer" algorithm J. . cþ = 0.6* (AT-56) fAT Other assumptions include values for a and m (cementation exponent). The EPA document uses the Humble formulation (a = 0.62 and m = 2.15), and I have used that here. I use a temperature gradient of 2.1 ° F per 100 feet. I have also converted all water resistivities to 75° F for easier comparison, and calculated salinities to kppm Total Dissolved Solids. Rwa has also been calculated in the shales. Porosities will be overestimated and mineral conductivity will be a factor, but these are opposing effects a...'1d the result will still be at least a qualitative measure of the fluid properties. The second technique uses the Spontaneous Potential (SP) curve. This curve measures the electric potential created by salinity contrasts between invading mud filtrate and connate water. Bounding shales serve as semi-permeable membranes, which enhance the reaction. Other effects on the SP are shale content of the sand, sand permeability and thickness, invasion, and hydrocarbon content. Empirical charts are available that attempt to correct SP for these and other effects, but I have used the SP directly. Understand, that overlooking shaliness will suppress SP and result in a salinity too low, thus providing a lower limit. One further issue with the SP is that it often will wander, especially in these shallow sections. To straighten, or "baseline" the SP curve is a standard procedure, though may be somewhat subjective in extreme cases. Continuous water resistivity curves have been calculated for those wells with sufficient data, to a depth of 4000'. Sands with maximum SP excursions have been calculated with the SP technique as a check. Other wells have been calculated with the data available and conclusions drawn. Following are results for the wells around the Nigliq location. The presentations are X- Y plots of Rwa corrected to 75°F, versus measured depth. Where possible, SP estimates have been included as spot checks. The colors represent the Volume shale as determined from standard log analysis. Also included is a small discussion on each well. From this and other work, we conclude there are no ftesh water aquifers below planned casing point. Pllillips ¡\Iaska, inc. is a Subsidiary of Phillips Petroleum Company Mr. Wayne Campaign January 13, 2006 Page 3 e e Reference 1. Raymer, LL., Hunt ER., & Gardner JS., "An Improved "Sonic Transit Time-to-Porosity Transform", Transactions of the SPWLA 21s1 Annual Logging Symposium (1980). ¡:::::-é ".10 .. W W !::!:..,,:":W!Ii! .. '4. ;--i¡<" j. . - . - - - . - - - ; J';1O 300 -·:.LJU" ';oJO. - - - - . I - . - . - I I I I I I rn Q - - .... .. I - ""- Ca-sÎñg~ Depth ~_ if .;. -8 l- e. ::.·5;JO W C ¡ (,JiJ - - - - - - J ~':!'J a¡.,¡;. .:1 ']0 - , - -'i-þ,""-- I!jí '" ·:1-:1(1 ~ o D .~.óI'.n "'n'-~;" ~- --- Color: VSH1 Nechelik #1 This well has a number of sands just under the permafrost. Raw resistivities drop to 2 am by 1300', indicative of salty waters, which shows also in the Rwa calculation above 1700'. I have also run SP calculations in the first log run section (200' -2700'). These values are systematically higher than the Rwa, and I suspect improper measurement of the surface mud samples. In this section of the well, the mudcake measurement is reported as more conductive than the filtrate, an unusual situation if true. On the second logging run, the SP appears to be a reverse resistivity curve and not a valid measurement of salinity. Unfortunately, this problem is not unusual in the arctic or offshore, where proper grounding may be difficult to achieve. Still, the Rwa calculated for the shales indicate saline waters and no sands. In the sands from Permafrost to 1700', Rwa @ 75°F averages 0.25 am for a salinity of24 Kppm TDS. Below 1700' there are few sands and average Rwa @ 7SoF is 0.35 am for a salinity of 17 Kppm TDS. Phillips Alaska, Inc. Is a Subsidiary of Phillips Petroleum Company I I , I I I I I ,"~no', - - - . - - f . - - - .....' I I I F -I -- 1 1 1 I I ,....C' - - - - - - 1 - - - - 1 1 Mr. Wayne Campaign January 13, 2006 Page 4 lù(,C' I.,;DI:, - 160[' - ~~'::r-,r; I.U I.U =::.. :~:~;[:c - - - :::J: I- ~ ""1''''- .. W C 31 DC' _,,' f.'[) "1m;:. o e e RW A DEPTH Crossplot Well: TEMPTATtON_1 ... ' I I - I I I : Casmgi- - r--_ - - f - - - -. Depth - ~ I ~ I- I .- E I E a. I a. - 0.- - - I - a.. ,"0 .. I 0 "J gig ë I C"i - I I I ,_ _ _ _ __ _ _ 1 _ _ _ _ . _ _ _ _ _ __ _ 1 I I I ·1 ^ ^ ...., <> Rw A {o HMM. 1in'Ii.:,,~""'" r,;: .~, .r'-'~·- --_ 1 Co'tor: VSH1 Temptation #1 Unfortunately, there are few sands in the shallow section of this well and this LWD data does not have an SP. However, we can look at the Values ofRwa calculated in the shales as indication of the expected salinities for this section. Average Rwa of 0.3 Om at 75°F results in a salinity of20 Kppm TDS. This data starts at the casing shoe depth of 1820' MD. This analysis indicates high salinities and no sands to serve as aquifers. Wayne Campaign Sr. Staff Petrophysicist Phillips Alaska, Inc. Is a Subsidiary of Phillips Petroleum Company e e ~ ConocoPhillips Chris Alonzo Development Supervisor, WNS ConocoPhillips Alaska 700 G Street Anchorage, AK 99501 Phone: 907.276.1215 R -- ~t:. ';. - 'Þ-__ ·:it -~ > -- ~\r:'l~L. November 22, 2005 ~'\:. ~ .f6;' ':;;1 Mr. John Norman, Chair Alaska Oil and Gas Conservation Commission Alaska Department of Revenue 333 West 7th Avenue, Suite 100 Anchorage,AJ( 99501 ." ~ Re: Proposed Fiord Oil Pool Conservation Order and Area Injection Order Colville River Field Dear Mr. Norman: In accordance with 20 AAC 25.520, ConocoPhillips Alaska, Inc. (CPAI) as operator of the Colville River Unit, requests a conservation order by the commission regarding the classification of the Fiord reservoirs as an oil pool and prescription of rules to govern the proposed development and operation of the pool. CP AI also requests an area injection order authorizing enhanced recovery operations for the proposed Fiord Oil Pool in accordance with 20 AAC 25.460. Attached to this letter is an information package supporting the classification and rules for the proposed Fiord Oil Pool and an application for the Fiord area injection order. I am available to discuss this requests with you and your staff if needed. Please call me at 265-6822 or Jack Walker at 265-6268 if you have questions. ~ ~~ Coo Alonzo Development Supervisor, Western North Slope ConocoPhillips Alaska, Inc. Attachments e e Proposed Fiord Oil Pool Conservation Order and Area Injection Order Colville River Field Page 2 November 22, 2005 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 825 W. 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 Petro-Hunt, L.L.C. Attention: Joe Lucas 1601 Elm Street, Suite 3500 Dallas, Texas 75201 (214) 880-8400 Fax: (214) 880-7101 e e I nformation for the Alaska Oil and Gas Conservation Commission for the Classification and Rules for the Proposed Fiord Oil Pool Colville River Field ConocoPhillips Alaska, Inc Anadarko Petroleum Corporation November 14, 2005 Information for proposeard Oil Pool Colville River Field e November 14, 2005 Table of Contents INTRODUCTION .... ....... ... ...... ........ ..... ........ ... ..... ... ... ... ... ..... ..... ... ... ..... ......... ....... .......1 1.0 RESERVOIR STRUCTURE AND TRAP ..........................................................3 2.0 RESERVOIR FLUID PROPERTIES.................. ................... ............. ...............5 3.0 DRilliNG, COMPLETION, AND WEll OPERATIONS .................................6 3.1 Drill ing Plan .......................................................................................................... .....................6 3.2 Drilling and logging ......................................................... ....................... ................................ 1 0 3.3 Well Spaci ng ........... ....................................................................... .................... .............. ........1 0 3.4 Well Work Plan ................... ......................... .......... ......................................... ......................... 1 0 4.0 FACILITIES SCOPE AND DESIGN ...............................................................11 5.0 AGREEMENTS AND PRODUCTION AllOCATION ....................................12 PROPOSED CONSERVATION ORDER ..................................................................13 list of Fiaures Figure 1 Proposed Affected Area for the Fiord Oil Pool .............................................2 Figure 2 Fiord Oil Pool Type Log ...............................................................................4 Figure 3 Proposed Fiord Oil Pool Development Wells and Existing Wells .................6 Figure 4 Well Schematic ............................................................................................. 7 Figure 5 Annular Disposal Interval Type Log: Bergschrund 1 ....................................8 Figure 6 Annular Disposal Interval Cross Section .......................................................9 Attachment Fiord No.5 Well Test 2 (Nechelik + Kuparuk) Composition of Prepared Reservoir Fluid Page i ConocoPhillips Alaska, Inc. Information for propose~rd Oil Pool Colville River Field Wovember 14, 2005 INTRODUCTION This document includes information for the Alaska Oil and Gas Conservation Commission to classify two hydrocRrbon zones in the Colville River Field as the Fiord Oil Pool and to prescribe rules to govern develòpment of the pool in accordance with 20 AAC 25.520. The proposed Fiord CD3 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 Fiord Oil Pool. The proposed Fiord Oil Pool includes the Nechelik sand within the Kingak Formation and Kuparuk C sand in the Kuparuk River Formation. The Fiord-Kuparuk and Nechelik zones have sand-on-sand contact and hydraulic communication in the oil column in the northern portion of the accumulation. ;I A common oil accumulation exists in the Nechelik and Kuparuk zones, but due to substantially different permeabilities and the limited area of sand-on-sand contact of the Nechelik and Kuparuk zones, dedicated wells are planned for each zone with completions limited to a single zone, except where the zones have direct sand-on-sand contact of the Nechelik and Kuparuk zones. Ol;1e well is known to have sand-on-sand contact, but other ' wells are not expected to encounter contiguous reserVoir sand-on-sand in the Nechelik and Kuparuk zones. See section 6 for more on reservoir description. Concurrent with this request, ConocoPhillips Alaska, Inc. (CPAI), as operator of the Colville River Unit (CRU) and on behalf of the working interest owners (WIOs), is seeking an Area" Injection Order by the Commission to endorse and authorize the proposed Fiord CD3 Miscible Water Alternating Gas Project. The project is located in the Colville Delta area approximately 6 miles north of the Alpine Central Facility. The project is comprised of a single drill site served by ice roads in the winter and airstrip. It will be connected to the existing Alpine Central Facility (ACF) by pipelines and electric power lines. Seventeen horizontal wells are planned to develop the two zones: 5 wells for Fiord-Kuparuk and 12 wells for Nechelik. Implementation of miscible water alternating gas operations from field start-up is planned. For each zone in the proposed Fiord Oil Pool, the working interest owners plan to form a separate participating area within the CRU. Preliminary boundaries for the future participating areas are shown on Figure 1 with the present CRU Boundary. CPAI as operator and on behalf of the WIOs, plans to apply to the State of Alaska and Arctic Slope Regional Corporation, to form a Fiord-Nechelik Participating Area and a Fiord-Kuparuk Participating Area in early 2006. Development drilling and facilities construction started in early 2004 at Drill Site CD3, and Fiord production start up is planned in 2006, creating the need to establish pool rules and complementary area injection order for the proposed oil pool. 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. Page 1 ConocoPhillips Alaska, Inc. Information for propose4l'rd Oil Pool Colville River Field .ovember 14, 2005 I ~ I ,~ .~~ Colville River Unit ~ J ~ '~ ~ ,cd -lÞ.~ :i j~r~ " II- ., L , I ... ... ... Proposed Fiord Oil Pool / , Fiord-Nechelik Preliminary PA - ___ r CD4 -- '1 Figure 1 Proposed Affected Area for the Fiord Oil Pool Page 2 ConocoPhillips Alaska, Inc. Information for propose_rd Oil Pool Colville River Field ~ovember 14, 2005 1.0 RESERVOIR STRUCTURE AND TRAP The proposed Fiord Oil Pool is comprised of two reservoir sands, Nechelik and Fiord- Kuparuk. The proposed pool is defined from the top of Kuparuk C sand at 6,876 feet measured depth (MD) to the base of the Nechelik sand at 7,172 feet MD in Fiord 5 as shown on Figure 2. Original oil in place is estimated at 60 to 130 MMSTBO for the Nechelik sand, and 20 to 60 MMSTBO for the Kuparuk sand. / The Nechelik sand is an Upper Jurassic (Oxfordian) sandstone within the Kingak Formation. The Nechelik, Nuiqsut, and Alpine zones are informal names for three Upper Jurassic sand bodies present within the CRU. The Nechelik lies stratigraphically below the Nuiqsut and Alpine. Conventional cores in the Fiord #1, Fiord #5, and Nigliq #1 wells help define both the vertical and lateral extent of the Jurassic facies. The Nechelik interval was deposited in a progradational to aggradational shallow marine setting.' The best reservoir quality sands occur near the top of the interval.' The erosion of the Nechelik by the Lower Cretaceous Unconformity (LCU) forms the updip trap, on the northern flank of this stratigraphically trapped reservoir. / The Kuparuk C interval is a shallow-marine transgressive sandstone deposited on the LCU. Over most of the CRU, the Kuparuk C is present as a thin transgressive lag, generally less than 5 feet thick. Locally, the Kuparuk C sand thickens on the downthrown side of normal faults which created accommodation space during Lower Cretaceous time. The 'Fiord' fault is a northwest trending normal fault, down to the west, which provided accommodation space for the Kuparuk C reservoir in the CD3 area. The Fiord #1 well has 23 feet of Kuparuk C sand and is located approximately 2700 feet west of the 'Fiord' fault. The lateral extent of Kuparuk C reservoir sands west of the 'Fiord' fault is defined by Fiord #1, #2, and #5 and the CD3-108, -109 and -110 wells. The Nechelik sand is underlain by interbedded mudstone, siltstone, and very fine-grained sandstone of the Kingak Formation. The underlying Kingak sequence is over 1,100 feet thick in the Fiord #1 well. At total depth, the Fiord #5 well penetrated 330 feet of Kingak below the Nechelik zone. Overlying the Kuparuk sand is approximately 90 feet of shale-rich lithology. Directly overlying the Kuparuk C sand is roughly 50 feet of Kuparuk D shale and, 40 feet of Kalubik shale. Between the Kuparuk and Nechelik sands in the Fiord #5 and Fiord #1 wells, there is a wedge of non-reservoir shale and sandstone of the Kingak Formation which thickens to the south. The top of the non-reservoir wedge is the LCU which dips to the north. The base of the non-reservoir wedge is the top of the Nechelik which dips to the south. In the northern part of the proposed pool, the LCU intersects and cuts into the Nechelik zone. In the southern portion of the proposed Fiord Oil Pool at Fiord #1, there exists 376 feet TVD of non- reservoir Kingak interval between the LCU and the Nechelik zone. In the Fiord #5 well, roughly 10,000 feet north-northwest of Fiord #1, the Nechelik and Kuparuk zones are separated by 131 feet TVD of non-reservoir Kingak. At the heel of the horizontal well, CD3- 108, there is approximately 190 feet TVD of non-reservoir Kingak separating the Kuparuk and Nechelik zones, but at the toe of CD3-108, almost 8000 feet north-northwest lateral distance from the heel, Kuparuk sand and Nechelik sand are contiguous in the oil column. / Kuparuk sand is not always present on top of the LCU, but at the CD3-108 toe location approximately 22 feet MD (5 feet TVD) of Kuparuk C Sand exists with sand-on-sand contact / with the Nechelik zone. The Kuparuk reservoir trap is formed by the Fiord Fault to the east with stratigraphic pinchouts elsewhere. The Kuparuk structure generally dips to the north, and the sand thins westward from the Fiord Fault. The Nechelik zone is truncated by the LCU to the north of the development area and the sand quality degrades to the south and west. Page 3 ConocoPhillips Alaska, Inc. Information for propose_rd Oil Pool Colville River Field ~ ~ roE Q.LL ~ ~ - E LL ~ CO C) c: ~ - Q ~ ;::,- :;~ Q.CD ;::,.. ~.5 Kuparuk e .. - ;::'ca &~ "S S z.5 ~- =ca CD ~ .cCD u.. CD c z- Fiord 5 Gr LWD Depth o 150 MD ~...E.;}I..E..~.. 6840 . ...~'. 6860 ~:i~~E~ft.U:" 6880 Figure 2 Fiord Oil Pool Type Log Page 4 ttv0vember 14, 2005 6876 Top Kuparuk e 6892 Base Kuparuk e (LeU) 6943 Base Nuiqsut 7021 Top Nechelik 7172 Base Nechelik ConocoPhillips Alaska, Inc. Information for proposecerd Oil Pool Colville River Field eovember 14, 2005 2.0 RESERVOIR FLUID PROPERTIES Fiord CD3 project fluids were characterized with samples from the Fiord #1, Fiord #5, and CD3-108 production tests, augmented with subsurface RFT samples acquired in Nigliq #1. Separate samples were collected from the Kuparuk and Nechelik zones in some cases and commingled samples were collected in some cases as shown in Table 1. Table 1 Fiord Crude Sample Summary Well Zone( s} Viscosity (cp) Solution GaR (SCF/STB) Relative Oil Volume (RB/STB) Oil Gravity (degrees API) Fiord #1 Kuparuk 0.889 609 1.333 31.3 Fiord #5 Nechelik 0.891 538 1.299 28.6 Fiord #5 Commingled 0.786 556 1.310 29.4 Nigliq #1 Nechelik 0.92 556 1.307 30.9 Solution GOR, relative oil volume, and oil gravity date in Table 1 were taken from the differential vaporization tests run at 165°F, except for Fiord #1 which was run at 158°F. Only oil gravity data is available for the CD3-108 sample: 28.6° AP I. Additional results of the Fiord #5 pressure-volume-temperature behaviour of the Fiord #5 KuparuklNechelik commingled sample are shown in Table 2. Table 2 Fiord #5 PVT Summary (RFL 990089) Temperature: 165°F Saturation pressure: 2395 psig Single phase compressibility: 8.64 x 10-6 v/v/psi (average 5000 to 2395 psig) Thermal expansion: 1.05234 v at 165°F I v at 60°F Density of reservoir fluid: 0.7534 g/cc Analysis of the reservoir fluid from the Nechelik and Kuparuk zones is shown in the attached report on Composition of Prepared Reservoir Fluid for the Fiord NO.5 Well - Test 2 (Nechelik + Kuparuk) RFL990089. Page 5 ConocoPhillips Alaska, Inc. Information for proposeerd Oil Pool Colville River Field ~ovember 14, 2005 3.0 DRILLING, COMPLETION, AND WELL OPERATIONS / Seventeen horizontal wells are planned at the Fiord CD3 development. The Nechelik ' development is planned with 12 wells (6 producers and 6 injectors), and the Kuparuk development is planned with 5 dedicated wells (3 producers and 2 injectors). Nechelik wells are planned with openhole completions and Kuparuk wells are planned with slotted liner completions. The surface and intermediate holes will be directionally drilled with water based mud systems and cased. The horizontal intervals will be drilled with a reservoir drilling fluid. With the exception of the production/injection hole liners for Kuparuk, the well plans for the Fiord Oil Pool are almost identical to the standard development well design used in the Alpine Oil Pool. For both Nechelik and Fiord-Kuparuk, producers are planned with surface-controlled subsurface, safety valves and injectors are planned with differential / pressure-operated, subsurface-controlled subsurface safety valves. Surface safety valves / are planned for all wells. ' 3.1 DRILLING PLAN Hole and casing sizes, mud systems, directional profile and departure, drilling techniques, and geologic section drilled to reach the Fiord Oil Pool targets are similar to those for the Alpine Oil Pool. Existing wells and future development wells are shown in Figure 3. Drilling began at Alpine in 1999 and 102 horizontal wells have be completed as of October 12, 2005. / Fiord Oil Pool wells will be drilled from 20-foot centers. N FIORD 4 . NIGLlQ 1 N N ~,\ ) K NECHELlK 1 . . Future Nechelík Producer Future Nechelik Injector Future Kuparuk Producer Future Kuparuk Injector Existing Nechelík Penetration Existing Kuparuk Penetration 1: 72000 1 FlORO 2 \ N N K ...... K······ I \ ~ \ \ \ \ AL~E \ i\ \ \, \\ \ STRTUTE MILES 0 FlORO 3 2 STRTUTE M ¡ LES 1 I Figure 3 Proposed Fiord Oil Pool Development Wells and Existing Wells Primary, secondary, and general well control for drilling and completion operations will be performed in accordance with 20 AAC 25 Articles 01 and 06. Casing and cementing will be performed in accordance with 20 AAC 25.030. Surface casing, cemented to surface, is Page 6 ConocoPhillips Alaska, Inc. Information for propose_rd Oil Pool Colville River Field tlþV0vember 14, 2005 planned at approximately 2400 feet true vertical depth. Intermediate hole will be drilled to the target formation and production 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. / Nechelík wells will be cemented such that the Kuparuk zone is protected. Zones above Kuparuk will also be evaluated on a well-by-well basis. If a significant hydrocarbon zone(s) is indicated by logging discussed in the following section 3.2. the cementing program will be designed for that well to protect that zone(s). Either leak-off or formation integrity tests are planned after drilling 20 to 50 feet beyond the respective surface casing shoe and the production casing shoe. The horizontal sections will be drilled with a reservoir drilling fluid. The Kuparuk wells will completed with a 4%-inch slotted liner across from sands and blank liner across from shales. Nechelik wells will be completed openhole. A packer and tubing will be run for both Kuparuk and Nechelik wells. A proposed producing well schematic is shown in Figure 4. CD3 - KuparuklNechelik Sand Producer 16' Insulated Conductor to 114' II Surface-.controUed. subsurface safety valve at +/·2000' TVD 9-5/6' 40 ppf L·BO BTCM Surface Casing at +/·2400' TVD. cemented to surface 3·y," 9.3 ppf or 4-y," 12.6 ppf L·BO 1ST Mod. tubing GC , Gas líft mandrels and valves Liner top hanger Top Reservoir at +/~ 6800' TVD Kuparuk 6900' TVD Nechelik I~=§~~~~~=~~~~~ I~~~~~~~~~~~=I )\11 3,500 -10.000' MD Horizontal 7' 26 ppf L·BO BTC Mod Production Casing @ +1_85° K.uRawJs.interval: 4-%" 12.6 ppf L-80 SLHT hanger/linerwl blank across Shale and s)ots across sand ~ interval; apen hole completion (no hanger/liner) Figure 4 Well Schematic Page 7 ConocoPhillips Alaska, Inc. Information for proposeerd Oil Pool Colville River Field eovember 14, 2005 Injection wells will have similar completions, except the upper two gas lift mandrels and the sliding sleeve will be omitted from the tubing string and the subsurface safety valve will be differential pressure-controlled. Disposal of drilling wastes will be proposed for Drill Site CD3 in accordance with 20 AAC 25.080 in annuli of wells with surface casing set below the permafrost. ' No underground ~ sources of drinking water exist beneath the permafrost in the CRU area (AOGCC Area Injection Order No. 188, October 7, 2004.)'The proposed CD3 pad annular injection interval will be the Upper Cretaceous Seabee and Torok Formations (Figure 5)., ~t~.~ - ~ ~lFl~ : ~ ~~~~-1~E~J ~oo ~~:;~~ - IIHOB " . . FlU'~ ~'"~U,. .. E'-'OD , "'INtI <011I Lithology '" o ~ '" C! Z <{ > <{ C> <{ U) PERMAFROST (1500ft) '" <{ U) s: UPPER BARRIER (800ft) SURFACE CASING ANNULAR DISPOSAL INTERVAL (1800 ft) LOWER BARRIER (700 ft) Figure 5 Annular Disposal Interval Type Log: Bergschrund 1 \\ '~~l ~'S ~ ç' ~ç~ cr-è) <v'-' (i) \ ~ S This interval contains over 1800 feet of interbedded sandstone and shale. The Seabee and upper part of the Torok are continuous over most of the CRU (Figure 6). Annular injection has been successful at CD1 and C02 pads in the Seabee and upper Torok. Surface casing will be set 10-20 feet above the C-30 marker. The upper barrier is composed of 800 feet of Page 8 ConocoPhillips Alaska, Inc. Information for proposeded Oil Pool Colville River Field eovember 14, 2005 shale and siltstone of the Upper Cretaceous Schrader Bluff Formation. Approximately 1500 feet of permafrost overlies the Schrader Bluff. The lower Barrier is composed of 1900 feet of shale and siltstone of the Torok Formation. , RD 1 RHoa 1 , ði;....'(dl.. , ~ --- ~ ,~ ·l' :~"~" + ¡ 1 CD3 CD3-108 ~ CD1 CD1-22 CD2 ALPINE 1 ~' . ... ~_..,".,.~~,,~ 2300 ~ . ... l ¡ ~ r ; ~ RD 1 RHOS 1 GR 00;....:0;::,,'..,- ~, . ii;.... L __-..:......"-'''00 '.Im ,.'.'.' ________ ........~J :i't . - 2200 ';~2200 RD 1 RHOS 1 GR 1 ~ , ~ f :I 4'~ ~.5'''D t . ~ : ~ "1'000 '''0 I ;~ "-'i" '000 :" .~ '", ... . , '.">-j zron \ A- '{ 2600 \ 2.9 ¡-~ ¡ t 5.3 Miles 2.3 Miles -- .,"" CD4 NANUK 1 GR 1 ~ RD 1 RHoa 1 t ,;,.¡";;:;,cr::. . . C-40 '000 , C-30 .5 Annular "'r Disposal i Interval --}.. 2600 C-20 Figure 6 Annular Disposal Interval Cross Section Page 9 ConocoPhillips Alaska, Inc. Information for propos.rd Oil Pool Colville River Field .ovember 14, 2005 3.2 DRILLING AND LOGGING Preliminary slot assignments and directional plans for the 17 wells have been generated. Drilling from 2Q-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 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 Fiord CD3 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 Fiord Oil Pool 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 bottomhole assembly. The surface and intermediate holes in the CD3-108 well were logged with gamma ray/resistivity/neutron/density logs. / 3.3 WELL SPACING Well spacing requirements under 20 AAC 25.055 should be waived because the horizontal well development will yield greater recovery than a conventional well development with a minimum spacing rule. The average Nechelik horizontal well will contact roughly 200 times more reservoir than a conventional well. Reservoir simulation of conventional wells and horizontal wells indicated Kuparuk sand ultimate recovery can be maximized with horizontal wells. 3.4 WELL WORK PLAN Well service operations are planned in accordance with 20 AAC 25 Article 03. Drillsite CD3 is planned with winter-only road access to the ACF, and air access at other times. 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. Page 10 ConocoPhillips Alaska, Inc. Information for proposede-d Oil Pool Colville River Field eovember 14, 2005 4.0 FACILITIES SCOPE AND DESIGN The Fiord CD3 surface facilities scope includes a gravel airstrip connected to a 12.6-acre gravel pad. The drilling rig will be moved to and from Drill Site CD3 on ice roads. Drillsite CD3 will be connected to the ACF with pipelines, power lines, and communications. Drillsite facilities include the following: · Production, test, artificial lift, gas injection, and water injection headers; · Tie-in slots for 17 wells with wellhead shelters and space for 7 additional wells; · Wellhead hydraulic panels (in well house); · Fuel gas conditioning · Electrical and instrumentation module with transformers. switch gear, and telecommunications; · Instrument air compressor package; · Test separator; · Emergency shut down (ESD) skid; · Water injection line pig receiver; · Production heater; · Warm and cold storage buildings; · Gravel maintenance equipment, slickline unit, pad vehicle, etc.; · Chemical injection and storage; · Waste handling containment facility; · Emergency living quarters; · Emergency power generator; · Lighting, surveillance, and communication equipment; · Powerlines (13.8 kV) suspended by messenger cable below the pipelines; · 16-inch diameter production pipeline; · 8-inch diameter water injection pipeline; · 6-inch diameter MI pipeline; · 6-inch diameter gas-lift pipeline; and · 2-inch products line for freeze protection. The Fiord CD3 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 major river channels as CD 1 and CD2, thus simplifying road access to the new drillsite · Minimizes disturbance of bird nesting area · Consideration of hydrolology study results Page 11 ConocoPhillips Alaska, Inc. Information for propose.d Oil Pool Colville River Field _ovember 14, 2005 5.0 AGREEMENTS AND PRODUCTION ALLOCATION All lands within the Fiord CD3 project area are leased and within the CRU. Most leases in the area have the same working interest as the Alpine Field (78 percent CPAI and 22 percent Anadarko Petroleum Company), but three tracts include a 0.38% working interest owned by Petro-Hunt. Discussions with Petro-Hunt on participating in the project are being initiated. ' ~ The CRU Agreement among the royalty interest owners, State of Alaska and Arctic Slope Regional Corporation, and the working interest owners prescribes a methodology for establishing participating areas and equity determination. The operations of the Fiord CD3 project are subject to the CRU Operating Agreement. Development of the proposed Fiord Oil Pool is planned with development wells solely dedicated to a single zone with no subsurface commingling, except where sand-on-sand contact exists such as the existing injector well CD3-108. Unitized substances produced from the Fiord Oil Pool will be commingled on the surface with substances from the other oil pools in the Colville River Field. 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 weiis that have commingled production streams and injection streams, respectively. The information u~ed in the allocation procedure is derived from pressure and flow measurements on individual prociúc!ion and injection wells along with measurements on aggregate commingled streams. Discrete prociuciion 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 = Vt1 + Vt2 + ... VI11 Vaggregate = Aggregate volume transferred (or used for injection, fuel, etc.) for the CRU AF = Allocation factor AF = Vaggregate / V tCRU V Ai = Allocated volume for well i VAi = AF Vti Page 12 ConocoPhillips Alaska. Inc. Information for proposecerd Oil Pool Colville River Field tþ'0vember 14, 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 T12N R4E sections 1,2,11-14 T12N R5E sections 1-18 T13N R4E sections 25,34-36 T13N R5E sections 15-22,26-36 Rule 1. Field and Pool Names The field is the Colville River Field and the pool is defined as the Fiord Oil Pool. / Rule 2. Pool Definitions The Fiord Pool is defined as the accumulation of oil and gas common to and correlating to the interval found in the Fiord NO.5 well between the depths of 6876 and 7172 feet / measured depth. Rule 3. Well Spacing The requirements of 20 AAC 25.055 are waived for development wells in the Fiord Oil Pool. Without prior notification, development wells may not be completed closer than 500 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 Fiord 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, 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. (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. 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 bottomhole pressure surveys shall be measured annually in the Fiord Page 13 ConocoPhillips Alaska, Inc. Information for ProposeAard Oil Pool Colville River Field -- Wovember 14, 2005 Oil Pool. (c.) The reservoir pressure datum shall be 6850 feet subsea. (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 Fiord 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 Fiord Oil Pool may be commingled on the surface with production from other Colville River Field pools 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 Casing Pressure (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 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 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 require the operator to take emergency corrective action before 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 Page 14 ConocoPhillips Alaska, Inc. Information for proposeerd Oil Pool Colville River Field evovember 14, 2005 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 (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 A9ion 0 ç- Upon proper application .Pf'its own motion, the Commission may administratively waive the requirements of any rule stated above or administratively amend this order. Page 15 ConocoPhillips Alaska, Inc. Information for proposeoerd Oil Pool Colville River Field eovember 14, 2005 ARCO Technology & Operations Services Fiord No.5 Well· Test 2 (Nechelik + Kuparuk) RFL 990089 Composition of Prepared Reservoir Fluid (by Low Temperature Distillation/Extended Chromatography) Component Name Mol % Wt% Density MW (gm/cc) Hydrogen Sulfide 0.00 0.00 0.8006 34.08 Carbon Dioxide 0.34 0.12 0.8172 44.01 Nitrogen 0.32 0.07 0.8086 28.013 Methane 35.71 4.64 0.2997 16.043 Ethane 4.83 1.18 0.3562 30.07 Propane 6.04 2.15 0.5070 44.097 iso-Butane 1.36 0.64 0.5629 58.123 n-Butane 3.19 1.50 0.5840 58.123 iso-Pentane 1.34 0.78 0.6244 72.15 Total Sample Properties n-Pentane 2.10 1.22 0.6311 72.15 Hexanes 3.69 2.51 0.6850 84 Molecular Weight 123.68 Heptanes 3.36 2.61 0.7220 96 Theoretical Liquid Density. gm/scc . 0.7732 Octanes 4.47 3.87 0.7450 107 Nonanes 3.27 3.20 0.7640 121 Decanes 2.91 3.16 0.7780 134 Undecane~ 2.42 2.87 0.7890 147 Dodecanes ;>14 2.79 0.8000 161 Tridecanes 2.16 3.06 0.8110 175 T etradecanes 1.89 2.90 0.8220 190 I I Density I Pentadecanes 1.82 3.03 0.83;¿C 206 Cyclic Compounds Mol % Wt% MW Hexadecanes 1.52 2.72 0.8390 22¿ (included in individual hydrocarbon fractions) Heptadecanes 1.29 2.48 0.8470 237 Octadecanes 1.23 2.51 0.8520 251 Methylcyclopel,;3'1!, 0.48 0.33 1)7529 84.16 Nonadecanes 1.10 2.33 0.8570 263 Benzene I') 06 ú.04 0.8836 78.11 Eicosanes 0.92 2.06 0.8620 275 Cyclohexane 0.47 0.32 0.7826 84.16 Heneicosanes 0.81 1.92 0.8670 291 Methylcyciohexane 1.39 1.10 0.7732 98.19 Docosanes 0.73 1.79 0.8720 305 Toluene 0.36 0.27 0.8710 92.14 T ricosanes 0.65 1.67 0.8770 318 Ethylbenzene 0.15 0.13 0.8708 106.17 T etracosanes 0.56 1.50 0.8810 331 meta & para Xylenes 0.38 0.33 0.8664 106.17 Pentacosanes 0.52 1.44 0.8850 345 ortho-Xylene 0.21 0.18 0.8838 106.17 Hexacosanes 0.42 1.22 0.8890 359 iso-Propyl benzene 0.13 0.13 0.8656 120.20 Heptacosanes 0.40 1.21 0.8930 374 n-Propylbenzene 0.23 0.22 0.8656 120.20 Octacosanes 0.37 1.16 0.8960 388 1.2,4- Trimethylbenzene 0.28 0.27 0.8798 120.20 Nonacosanes 0.33 1.07 0.8990 402 T riacontanes 0.29 0.98 0.9020 416 1 Mol % I I Density I Hentriacontanes 0.26 0.92 0.9060 430 Plus Fractions Wt% MW Dotriacontanes 0.24 0.84 0.9090 444 T ritriacontanes 0.21 0.76 0.9120 458 T etratriacontanes 0.19 0.72 0.9140 472 Hexanes plus 44.77 87.70 0.8841 242 Pentatriacontanes 0.17 0.66 0.9170 486 Heptanes plus 41.08 85.19 0.8917 256 Hexatriacontanes plus 4.43 27.74 1.0626 774 Decanes plus 29.98 75.51 0.9148 312 Pentadecanes plus 18.46 60.73 0.9481 407 Eicosanes plus 11.50 47.66 0.9811 513 Pentacosanes plus 7.83 38.72 1.0105 612 T riacontanes plus 5.79 32.62 1.0363 697 Pentatriacontanes plus 4.60 28.40 1.0587 764 Totals 100.00 100.00 Page 16 ConocoPhillips Alaska, Inc. e e Application to the Alaska Oil and Gas Conservation Commission for the Fiord Area Injection Order Colville River Field ConocoPhillips Alaska, Inc Anadarko Petroleum Corporation November 22, 2005 Application to the AOGeOr the Fiord Area Injection Order Colville River Field e November 22, 2005 Table of Contents Introduction........................................................................................................................... ........... 3 20 AAC 25.402 (c)(1) Plat of Wells Penetrating Injection Zone....................................................... 4 20 AAC 25.402 (c)(2) Operators and Surface Owners within One Quarter Mile of Injection Operations............. ............................................................................ .... ....... ............... ..................... 5 20 AAC 25.402 (c)(3) Affidavit of Jack A. Walker Regarding Notice to Surface Owners ................ 6 20 AAC 25.402 (c)(4) Description of the Proposed Operation ........................................................ 7 20 AAC 25.402 (c)(5) Description and Depth of Pool to be Affected............................................... 9 20 AAC 25.402 (c)(6) Description of the .Formation...................................................................... 11 20 AAC 25.402 (c)(7) Logs of the Injection Wells.......................................................................... 12 20 AAC 25.402 (c)(8) Casing Description and Proposed Method for Testing............................... 13 20 AAC 25.402 (c)(9) Injection Fluid Analysis and Injection Rates ............................................... 14 20 AAC 25.402 (c)(10) Estimated Pressures.......... .................. ......... ...................... ................. ..... 15 20 AAC 25.402 (c)(11) Fracture Information ................................................................................. 16 20 AAC 25.402 (c)(12) Quality of Formation Water....................................................................... 17 20 AAC 25.402 (c)(13) Aquifer Exemption Reference................................................................... 18 20 AAC 25.402 (c)(14) Incremental Hydrocarbon Recovery .........................................................19 20 AAC 25.402 (c)(15) Mechanical Condition of Wells Within ~ Mile of Proposed Area.............. 20 List of Fiaures Figure 1 Proposed Affected Area for Fiord Area Injection Order.................................................. 21 Figure 2 Proposed Fiord Oil Pool Development Wells and Existing Wells................................... 22 Figure 3 Fiord Type Log........................................................... ..... ..... ........................................... 23 Figure 4 Typical Fiord Injector Well Schematic ............................................................................24 Attachments Fiord Area Fracture Containment Modeling Fiord #1 Well Completion Report (AOGCC Form 10-407) Fiord #1 P&A Schematic Fiord #2 Well Completion Report (AOGCC Form 10-407) Fiord #2 Plug and Abandon Schematic Fiord #4 Well Completion Report (AOGCC Form 10-407) Fiord #4 P&A Schematic Fiord #5 Well Completion Report (AOGCC Form 10-407) Fiord #5 P&A Schematic Nechelik #1 Well Completion Report (AOGCC Form 10-407) Nigliq #1 Well Completion Report (AOGCC Form 10-407) Nigliq #1 P&A Schematic CD3-108 Well Completion Report (AOGCC Form 10-407) CD3-108 Well Schematic CD3-109 Application for Permit to Drill CD3-109 Suspension Schematic CD3-110 Application for Permit to Drill CD3-110 Suspension Schematic Page 2 ConocoPhillips Alaska, Inc. Application to the AO.for the Fiord Area Injection Order e November 22, 2005 Colville River Field Introduction This area injection order application seeks Alaska Oil and Gas Conservation Commission endorsement and authorization for the proposed Fiord CD3 Miscible / Water Alternating Gas Project in the CRU. This project involves the development of two zones from Drill Site CD3: Nechelik and Fiord-Kuparuk./ This application has been prepared in accordance with 20 AAC 25.402 (Enhanced Recovery Operations) and 20 AAC 25.460 (Area Injection Orders). The proposed Fiord CD3 Miscible Water Alternating Gas Project is an enhanced oil recovery project employing the cyclic injection of miscible gas (MI) and water / to be implemented for the development of the proposed Fiord Oil Pool, which is located within the Colville River Field on the North Slope of Alaska. The proposed Fiord Oil Pool includes both the Nechelik zone within the Kingak / Formation and the Kuparuk zone in the Kuparuk River Formation. The Kuparuk and Nechelik zones have sand-on-sand contact and hydraulic communication in ( the oil column in the northern portion of the common accumulation. ' A common oil accumulation exists in the Nechelik and Kuparuk zones, but due to substantially different permeabilities and the limited area of sand-on-sand contact of the Nechelik and Kuparuk zones, dedicated wells are planned for each zone with completions limited to a single zone, except where the zones have direct sand-on-sand contact of the Nechelik and Kuparuk zones. One well is known to have sand-on-sand contact, but other wells are not expected to encounter contiguous reservoir sand-on-sand in the Nechelik and Kuparuk zones. See section 6 for more on reservoir description. Concurrent with this application for an Area Injection Order, ConocoPhillips / Alaska, Inc., as operator of the CRU and on behalf of the working interest owners (WIOs), is seeking a Conservation Order by the Commission regarding the classification and rules to govern the development of the proposed Fiord Oil Pool. For each proposed zone, the working interest owners plan to form a separate participating area within the CRU. Preliminary boundaries for the future participating areas are shown on Figure 1 with the present CRU Boundary. ConocoPhillips Alaska, Inc., as operator and on behalf of the WIOs, plans to apply to the State of Alaska and Arctic Slope Regional Corporation to form a Fiord-Nechelik Participating Area and a Fiord-Kuparuk Participating Area in early 2006. Development drilling started March, 2005 at Drill Site CD3 and Fiord production start up is planned in 2006, creating the need to establish pool rules and complementary area injection order for the proposed oil pool. Page 3 ConocoPhillips Alaska, Inc. Application to the AOGttror the Fiord Area Injection Order e November 22, 2005 Colville River Field 20 AAC 25.402 (c)(1) Plat of Wells PenetratinQ Injection Zone The attached map (Figure 2) shows all existing wells penetrating the injection zones in the proposed injection area. The maps also show the areal extent of the injection zone relative to preliminary participating areas within the CRU, and the location of all proposed Fiord Oil Pool development wells (injection wells and development wells). Page 4 ConocoPhillips Alaska. Inc. Application to the AOGeOr the Fiord Area Injection Order Colville River Field tit November 22, 2005 20 AAC 25.402 (c){2) Operators and Surface Owners within One Quarter Mile of Injection Operations Operator: ConocoPhillips Alaska, Inc. Attention: Matt Elmer P. O. Box 100360 Anchorage, AK 99510-0360 Surface Owners: State of Alaska Department of Natural Resources Attention: Mike Kotowski P. O. Box 107034 Anchorage, AK 99510 Kuukpik Corporation Mr. Isaac Nukapigak PO Box 187 Nuiqsut, Alaska 99789-0187 Page 5 ConocoPhillips Alaska. Inc. Application to the AOG.r the Fiord Area Injection Order Colville River Field e November 22, 2005 20 AAC 25.402 (c)(3) Affidavit of Jack A. Walker Regarding Notice to Surface Owners Jack A. Walker, on oath, deposes and says: 1. I am the Fiord Production Engineer for ConocoPhillips Alaska, Inc., the operator of the Colville River Unit. 2. On November 22, 2005, I caused copies of the application for the Fiord Area Injection Order to be provided to the surface owner and operator of all land within a quarter mile of the proposed injection wells as listed below: a. State of Alaska Department of Natural Resources Attention: Mike Kotowski P. O. Box 107034 Anchorage, AK 99510 b. Kuukpik Corporation Mr. Isaac Nukapigak PO Box 187 Nuiqsut, Alaska 99789-0187 c. ConocoPhillips Alaska, Inc. Attention: Matt Elmer ATO-1750 P.O. Box 100360 Anchorage, Alaska 99510-0360 ~~~ STATE OF ALASKA ) ) ss. THIRD JUDICIAL DISTRICT ) SUBSCRIBED AND SWORN to before me this 22nd day of November, 2005. /(YÆLJß.~. NOT~UBLlC IN A':¿ :t~SKA My Commission Expires: ~ . /t,../ e?()()ß STATE OF ALASKA /~,w¿:;, NOTARY PU8L1C-~', Carol Kelly My Commission E:~p¡res Aug. 16, 2008 Page 6 ConocoPhiJlips Alaska. Inc. Application to the AOGeor the Fiord Area Injection Order It November 22, 2005 Colville River Field 20 AAC 25.402 (c}(4) Description of the Proposed Operation / An Area Injection Order is needed to develop the proposed Fiord Oil Pool. The scope of the development project includes drilling 17 wells from a new CRU Drill / Site, CD3. Five wells are planned to develop the Kuparuk zone and twelve wells ' are planned to develop the Nechelik zone. Development of the proposed Fiord Oil Pool is planned with development wells solely dedicated to a single zone, except where the Nechelik and Kuparuk zones have contiguous sand-on-sand contact. Unitized substances produced from the proposed Fiord Oil Pool will be commingled on the surface with substances from the existing Alpine Oil Pool / and proposed Nanuq and Nanuq-Kuparuk Oil Pools. Similar to the existing allocation of unitized substances for the Alpine Oil Pool, production allocation for the proposed pool will be based on periodic well tests and producing conditions, e.g. up time; and injection allocation for the proposed pools will be based on meters on each injection well. Water alternating with MI injection is the proposed recovery mechanism for both zones. The project scope includes injection of water and enriched hydrocarbon; gas from the Alpine Central Facility ("ACF"), also located within the CRU. At the end of the Fiord CD3 Project MI phase, lean gas and/or water may be injected to recover the remaining mobilized oil and injected hydrocarbons. . Injection of water is scheduled to begin in 2006,1 followed by MI injection beginning in 2007.' Five injection wells for the Nechelik zone and two injection· wells for the Fiord-Kuparuk zone and one Nechelìk/Kuparuk commingled injection well are included in the scope of the Fiord CD3 Project. Surface facilities will be installed at the CD3 drillsite to deliver and meter both MI and water to each injection well. Horizontal development wells will be drilled from Drill Site CD3. For both zones, well layout is a direct line drive pattern configuration with alternating injectors and producers. Planned interwell spacing is 2,100 feet for the Nechelik and 4,500 ; feet for the Fiord-Kuparuk. Different well spacing may be implemented after analysis of reservoir performance. Horizontal production and injection holes are planned at approximately 8,000 feet in the Nechelik zone and approximately·· 4000 feet for the Kuparuk zone. / The Fiord CD3 surface facilities scope includes a gravel airstrip connected to a 12.6-acre gravel pad located north of the ACF. The drilling rig will be moved to and from Drillsite CD3 on ice roads. The project includes produced oil, water injection, MI, and gas lift pipelines and electric powerline between the ACF to the Fiord CD3 drillsite. Drillsite facilities include the following: Production, test, artificial lift, gas injection, and water injection headers; Tie-in slots for 17 wells with wellhead shelters and space for 7 additional wells; Wellhead hydraulic panels (in well house); Fuel gas conditioning; Page 7 ConocoPhillips Alaska, Inc. Application to the AOGCer the Fiord Area Injection Order Colville River Field e November 22, 2005 Electrical and instrumentation module with transformers, switch gear, and telecommunications; Instrument air compressor package; Test separator; Emergency shut down (ESO) skid; Water injection line pig receiver; Production heater; Warm and cold storage buildings; Chemical injection and storage; Waste handling containment facility; Emergency living quarters; Emergency power generator; Lighting, surveillance, and communication equipment; Powerlines (13.8 kV) suspended by messenger cable below the pipelines; 16-inch diameter production pipeline; 8-inch diameter water injection pipeline; 6-inch diameter MI pipeline; 6-inch diameter gas-lift pipeline; and 2-inch products line for freeze protection. Page 8 ConocoPhillips Alaska. Inc. Application to the AO.for the Fiord Area Injection Order e November 22, 2005 Colville River Field 20 AAC 25.402 (c)(5) Description and Depth of Pool to be Affected Location The proposed Fiord Oil Pool is located in the CRU approximately 6 miles north of the Alpine Central Facility. As shown on Figure 1, the affected area proposed for the Fiord Area Injection Order is: Umiat Meridian T12N R4E sections 1,2, 11-14 T12N R5E sections 1-18 T13N R4E sections 25,34-36 T13N R5E sections 15-22, 26-36 Pool Definition The proposed Fiord Oil Pool is the hydrocarbon-bearing interval between 6,876 and 7,172 feet measured depth in the Fiord #5 well (Figure 3) and its lateral equivalents. Pool Description The proposed Fiord Oil Pool is comprised of two reservoir zones, Nechelik and Kuparuk. The Nechelik zone is an Upper Jurassic (Oxfordian) sandstone within the Kingak Formation. The Nechelik, Nuiqsut, and Alpine zones are informal names for three Upper Jurassic sand bodies present within the CRU. The Nechelik zone lies stratigraphically below the Nuiqsut and Alpine zones. Conventional cores in the Fiord #1, Fiord #5, and Nigliq #1 wells help define both the vertical and lateral extent of the Jurassic facies. The Nechelik interval was deposited in a progradational to aggradational shallow marine setting. The best reservoir ' quality sands occur near the top of the interval. The erosion of the Nechelik by the Lower Cretaceous Unconformity (LCU) forms the updip trap, on the northern flank of this stratigraphically trapped reservoir. ' The Kuparuk zone is a shallow-marine transgressive Cretaceous (Hauterivian) sandstone deposited on the Lower Cretaceous Unconformity (LCU). Over most of the CRU, the Kuparuk C is present as a thin transgressive lag, generally less than 5 feet thick. locally, the Kuparuk C sand thickens on the downthrown side of normal faults which created accommodation space during lower Cretaceous time. The 'Fiord' fault is a northwest trending normal fault, down to the west, which provided accommodation space for the Kuparuk C reservoir in the CD3 / area. The Fiord #1 well has 23 feet of Kuparuk C sand and is located approximately 2700 feet west of the 'Fiord' fault. The lateral extent of Kuparuk C reservoir sands west of the 'Fiord' fault is defined by Fiord #1, #2, and #5 and the CD3-108, -109 and -110 wells. Page 9 ConocoPhillips Alaska, Inc. Application to the AOGeOr the Fiord Area Injection Order Colville River Field e November 22, 2005 The Nechelik zone is underlain by interbedded mudstone, siltstone, and very fine-grained sandstone of the Kingak Formation.' The underlying Kingak sequence is over 1,100 feet thick in the Fiord #1 well. ' At total depth, the Fiord #5 well penetrated 330 feet of Kingak below the NecheJik zone.' Overlying the Kuparuk sand is approximately 90 feet of shale-rich lithology.' Directly overlying the Kuparuk C sand is roughly 50 feet of Kuparuk D shale and. 40 feet of Kalubik shale. Between the Kuparuk and Nechelik sands in the Fiord #5 and Fiord #1 wells, there is a wedge of non-reservoir shale and sandstone of the Kingak Formation which thickens to the south. The top of the non-reservoir wedge is the LCU which dips to the north. The base of the non-reservoir wedge is the top of the NecheJik which dips to the south. In the northern part of the proposed pool, the LCU intersects and cuts into the Nechelik zone. In the southern portion of the proposed Fiord Oil Pool at Fiord #1, there exists 376 feet TVD of non-reservoir Kingak interval between the LCU and the Nechelik zone. In the Fiord #5 well, roughly 10,000 feet north-northwest of Fiord #1, the NecheJik and Kuparuk zones are separated by 131 feet TVD of non-reservoir Kingak. At the heel of the horizontal well, CD3-108, there is approximately 190 feet TVD of non-reservoir Kingak separating the Kuparuk and NecheJik zones, but at the toe of CD3-108, almost 8000 feet north-northwest lateral distance from the heel, Kuparuk sand and Nechelik sand are contiguous in the oil column. Kuparuk sand is not always developed on top of the LCU, but at the CD3-108 toe location approximately 22 feet MD (5 feet TVD) of Kuparuk C Sand exists with sand-on-sand contact with Nechelik zone. The Kuparuk reservoir trap is formed by the Fiord Fault to the east with stratigraphic pinchouts elsewhere. ' The Kuparuk structure generally dips to the north, and the sand thins westward from the Fiord Fault. The Nechelik zone is truncated by the LCU to the north of the development area and the sand quality degrades to the south and west. Page 10 ConocoPhillips Alaska. Inc. Application to the AOG4ttor the Fiord Area Injection Order e November 22, 2005 Colville River Field 20 AAC 25.402 (c)(6) Description of the Formation The Nechelik zone sands are a coarsening upward (becoming more sand rich) sequence with the best reservoir quality sandstone near the top of the interval " (equivalent to deposition in the shallowest water). Nechelik sandstones are bioturbated and analysis of the trace fossils shows that near the base of the interval most of the deposition is in the shelf setting 'while at the top of the interval the sediments were deposited in upper lower to middle shoreface settings.' Neither water-oil nor gas-oil contacts have been observed in the Nechelik zone. ' Porosity averages approximately 16% and permeability to air averages approximately 8 md. Average water saturation is approximately 34% in the Fiord #4 and Fiord #5 wells. Original Nechelik reservoir pressure is 3200 psi at 6900 feet true vertical depth (TVD) subsea. The Kuparuk is a fine- to medium-grained, quartz-rich sandstone that contains variable amounts of glauconite and siderite cement. Porosity averages approximately 22% and permeability to air averages approximately 110 md. Average water saturation is approximately 22% in the Fiord #5 well. Geochemical analysis on the reservoir fluids in Fiord #5 (well tests) and Fiord #4 (RFT) indicated that the Nechelik oil and Kuparuk oil are likely the same oil and' were derived from the same source rocks. The Kuparuk oils in Fiord #1 and Fiord #5 are essentially identical and indicate reservoir continuity between Fiord #1 and #5 in the Kuparuk zone. The similarity between the Kuparuk and the Nechelik oils suggests that the two reservoirs are in communication. - Pressure-Volume-Temperature test results are summarized in Table 1 for reservoir fluid samples collected in the development area. Gas-oil ratio, relative oil volume, and API gravity data are reported for differential vaporization tests. Table 1 PVT Summary Well Zone(s) Viscosity (cp) Solution GOR (SCF/STB) Relative Oil Volume (RB/STB) Oil Gravity (degrees API) Fiord 1 Kuparuk 0,889 609 1.333 31.3 Fiord 5 Nechelik 0.891 538 1.299 28.6 Fiord 5 Commingled 0.786 556 1.310 29.4 Nigliq 1 Nechelik 0.92 556 1.307 30.9 Page 11 ConocoPhiJlips Alaska. Inc. Application to the AOGeOr the Fiord Area Injection Order Colville River Field 20 AAC 25.402 (c)(7) Loos of the Injection Wells e November 22, 2005 A typical well log for proposed injection wells is shown in Figure 3. Page 12 ConocoPhillips Alaska, Inc. Application to the AOGeOr the Fiord Area Injection Order Colville River Field e November 22, 2005 20 AAC 25.402 (c)(8) Casing Description and Proposed Method for TestinQ \ CJ10L'\.\ (; (- \...: """', \!l All underground injection into the proposed Fiord Oil Pool will be through wells 'z permitted as service wells for injection in conformance with 20 AAC 25.005, 9~ " approved for conversion to service wells in conformance with 20 AAC 25.280. -PJf typical well schematic is included as Figure 4. The proposed Fiord Oil Pool will be accessed from wells directionally drilled from a gravel pad utilizing drilling procedures, well designs, casing and cementing programs consistent with current practices in other North Slope fields. For proper anchorage and to divert an uncontrolled flow, 16-inch conductor casing will be drilled and cemented at least 75 feet below pad. Cement returns to surface will be verified by visual inspection. A diverter system compliant with the Commission requirements may be installed on the conductor. Primary, secondary, and general well control for drilling and completion operations will be performed in accordance with 20 AAC 25 Articles 01 and 06. Casing and cementing will be performed in accordance with 20 AAC 25.030. Surface casing, cemented to surface, is planned at approximately 2400 feet true vertical depth. Intermediate hole will be drilled to the target zone and production casing will be cemented with the shoe in the target zone. Either leakoff or formation integrity tests are planned after drilling 20 to 50 feet beyond the respective surface casing shoe and the production casing shoe. The production casing will be cemented with such a volume to protect any significant hydrocarbon zones. Production and injection holes will be drilled beyond the casing shoe horizontally in the target zone. Slotted liners are planned in the production and injection /""",', holes for the Kuparuk zone. The Nechelik zone will be completed with open / holes. Except where Kuparuk and Nechelik sands are contiguous, e.g. the toe of £.0 SC-I0-\;>" CD3-108, operating wells with the Kuparuk and Nechelik zones open in the same f ~\,\r¡;;~ well are not planned. Tubing and packer, or other equipment, will be run to ¡ ~ ~ isolate pressure to the injection interval consistent with 20 AAC 25.412, but the \ ~ \ .\-~ 1 maximum spacing of 200 feet measllJt:'d depth bdw~en the pressure isolation\'",-__// equipment and the top of the injection zone should be waived to accommodate efficient wireline operations down to the pressure isolation equipment. Casing-tubing annulus pressures will be monitored and reported during injection operations in accordance with 20 AAC 25.402(e). Automated monitoring of injection rates, tubing and casing-tubing annulus pressures is planned. Prior to commencement of injection, each injection well will be pressure tested in accordance with 20 AAC 25.412(c). In the event pressure observations or tests indicate communication or leakage of any tubing, casing, or packer, ConocoPhillips will notify the Commission within 24 hours of the observation to obtain Commission approval of appropriate corrective actions. Commission approval will be received prior to commencement of corrective actions unless the situation represents a threat to life or property. Page 13 ConocoPhillips Alaska, Inc. Application to the AOGe,or the Fiord Area Injection Order Colville River Field e November 22, 2005 20 AAC 25.402 (c)(g) Injection Fluid Analysis and Injection Rates The water injection plan for the Fiord Oil Pool is based on a single water pipeline between the Alpine Central Facility (ACF) and Drill Site CD3. Seawater will initially be used for water injection followed by produced water or mixed produced water I seawater later in the field life. Production commingling 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. - OcK-S \~7\'^.-~v':\\~i os-Q. Í'<D\-Q.o~,\~,.\~þ\(¿ Small amounts of non-hazardous fluids (NHF) occasionally may be blended with seawater and produced water for injection. These NHF include: sump fluid, hydrotest fluid, rinsate generated from washing mud hauling trucks, excess well work fluids, and treated camp waste water. These NHF will normally be injected into the WD-02 Class I disposal well, but will be blended with injection water for enhanced oil recovery (EOR) when WD-02 is unavailable. NHF blended in the entire stream of Colville River Field EOR injection water will yield a concentration of 0.02% of the EOR injection water. Because the Fiord development is a road less drill site, mixing of fluids collecting in well cellars and secondary containment, almost entirely from snow or rain, and glycol and treated waste water from emergency living quarters and warm storage building with Fiord injection water may be necessary. Normal disposition of these fluids is planned in WD-02, but injection of these fluids into the Fiord Oil Pool will provide EOR. The volume is expected to be less than 2400 barrels per year, or a concentration of 0.04 %. This concentration is not expected to affect the EOR efficiency in the Fiord Oil Pool. The anticipated MI composition available from the ACF is: Component Mol Fraction H2O 0.0001 CO2 0.0056 Nitrogen 0.0098 Methane 0.6276 Ethane 0.1106 Propane 0.1560 i-Butane 0.0271 n-Butane 0.0517 Pentanes 0.0095 C6+ 0.0020 Injection rates will be managed based on voidage for both zones. Individual well injection rates will vary according the reservoir properties encountered. Injection of MI and water will alternate in each injection well. The maximum expected and average injection rates are: Maximum MI Rate Average MI Rate Maximum Water Rate Average Water Rate (MSCFD) (MSCFD) (BPD) (BPD) Nechelik 10,000 6,300 10,000 1,900 Fiord-Kuparuk 10,000 6,500 10,000 2,200 Page 14 ConocoPhillips Alaska, Inc. Application to the AOGeOr the Fiord Area Injection Order Colville River Field e November 22, 2005 20 AAC 25.402 (c)(10) Estimated Pressures The MI pressure available from the ACF is expected to be approximately 4000 - psi. Due to pressure losses in the distribution system, wellhead injection pressures are expected to be 3800 psi with MI. Injection wells may be choked to lower wellhead pressures to manage injection rate. The seawater injection pressures from the ACF pump discharge are expected to average approximately 2500 psi. Due to pressure losses in the distribution system, wellhead injection pressures are expected to be 2400 psi with water. / Injection wells may be choked to lower wellhead pressures to manage injection rate. Page 15 ConocoPhiJlips Alaska, Inc. Application to the AOGeOr the Fiord Area Injection Order Colville River Field e November 22, 2005 20 AAC 25.402 (c){11 ) Fracture Information Modeling of the proposed Fiord Pool indicated injection fluids will remain within the injection zones. Digital log data from the Fiord #5 well were processed to estimate elastic properties and in-situ stress. Actual fracturing pressure of the Fiord #5 well Nechelik zone indicated a 0.69 psi/ft fracture gradient. / / Maximum water injection pressure will exceed the parting pressure of both the Kuparuk and Nechelik zones. The fracture model indicated that fracturing due to long term water injection will be arrested in the confining zones above and below, the Kuparuk and Nechelik. Fractures initiated in the Kuparuk sand could potentially grow down into the Nechelik sand if the interval between the two zones is very thin. However, hydraulic fracturing of the Kuparuk interval is not expected at the planned injection rates. ~ Maximum gas injection pressure could -"exceed the parting pressure of the Nechelik zone, but is not expected to exceed the parting pressure of the Kuparuk zone. Nechelik zone fracturing due to gas injection is not expected to grow throughout the entire interval. A report on Fiord fracture modeling is attached. Page 16 ConocoPhillips Alaska, Inc. Application to the AOGeOr the Fiord Area Injection Order e November 22, 2005 Colville River Field 20 MC 25.402 (c)(12) Quality of Formation Water Water has not been produced from wells in the proposed Fiord Oil Pool area, nor have water-oil contacts been observed in the Nechelik or Kuparuk zones within that area. Salinity was calculated for the Nechelik #1 well in the proposed Fiord Oil Pool area in zones deeper than the proposed injection zones. Using the standard Archie correlation and open hole log data, the salinities in the Sag River (8432- 8480 feet MD) and Ivishak (9420-9460 feet MD) Formations were calculated to be 18,000 and 17,000 parts per million (ppm) NaCI equivalent, respectively. Approximately 10 miles south of the Fiord area, the Nanuk #2 well produced water from the Torok Formation above the proposed Fiord Oil Pool stratigraphic interval. From perforations at 7,048 to 7,108 feet MD, the Nanuk #2 well produced formation water with the following composition: / Sodium 7,000 ppm Potassium 150 ppm Calcium 200 ppm Magnesium 0 ppm Bicarbonate 800 ppm Sulfate 0 ppm Chloride 10,600 ppm Page 17 ConocoPhillips Alaska, Inc. Application to the AOG.r the Fiord Area Injection Order Colville River Field e November 22. 2005 20 AAC 25.402 (c)(13) Aquifer Exemption Reference No underground sources of drinking water exist beneath the permafrost in the CRU area. See Area Injection Order 188 (October 7,2004) conclusion 3. The proposed Area Injection Order has an affected area entirely within the CRU area. Wells in the proposed Fiord Oil Pool are planned with surface casing set below the base of permafrost. Annular disposal of drilling waste is planned at Drill Site CD3 after authorization under 20 AAC 25.080. Page 18 ConocoPhilJips Alaska, Inc. Application to the AO. for the Fiord Area Injection Order e November 22, 2005 Colville River Field 20 MC 25.402 (c)(14) Incremental Hvdrocarbon Recovery The Fiord CD3 Project will employ a miscible water-alternating-gas (MW AG) / process to maximize ultimate oil recovery by miscible displacement of reservoir fluids. This process consists of a multiple-contact miscible displacement of reservoir oil. The MI contacts oil not swept by water injection, and mixes with that oil so that it becomes mobile. This mobilized oil is then pushed to production wells by subsequent alternating slugs of injected MI and water. Through this miscible displacement process, the residual oil saturation is reduced to very low levels in the swept pore volume, with the mobilized oil displaced to the producing wells. By alternating between the injection of MI and water, gas and water interaction in the pore space improves reservoir sweep efficiency by reducing the' effective mobility of the MI. The injected water helps maintain reservoir pressure, . retards gravity segregation of the MI, and controls gas channeling. By combining the mobilization of unswept oil by the miscible displacement process with the sweep efficiency enhancement of alternating gas and water injection, the MWAG displacement process results in more than an insignificant increase in ultimate crude oil recovery, compared with waterflood alone. \ 5" * çs. -\ \ -;) \ ~.;,,-d-C:) -t \- ~ For the Nechelik zone, incremental waterflood recovery is expected to be 8 to 12% of original oil in place (OOIP) above primary recovery of 15 to 20%,~ and numerical compositional simulation supports an incremental recovery factor over waterflood of 12% to 18% 'OOIP for the MWAG process. ~Iik. P'is estimated at 60 to 130 MMSTBO. / ~ SC) For the Kuparuk zone, incremental waterflood recovery is expected to be to 52% OOIP above primary of 5 to 10%: and numerical compositional simulation supports an incremental recovery of 13 to 19% OOIP for the MWAG process. Kuparuk OOIP is estimated at 20 to 60 MMSTBO. ~ -\- -SS ~ \ ~® \a1":S~~ Numerical simulation, tuned to laboratory experiments and PVT modeling, ~ demonstrated that the ACF MI design composition is miscible with Fiord crude oil at initial reservoir conditions, and will significantly reduce residual oil saturations below waterflooding. An equation-of-state (EOS) fluid model was created and validated against laboratory measurements of the Nechelik and Kuparuk crude oil PVT properties. This EOS was tuned to predict the phase behavior of mixtures of crude oil with a variety of hydrocarbon gas compositions. Annualized peak production rates for the Nechelik is expected to be between 10,000 and / 25,000 barrels of oil per day (BOPO). Annualized waterflood injection rates are estimated to peak between 18,000 and 40,000 barrels of water per day (BWPO) and MI / rates are expected to peak at 12 to 29 million standard cubic feet of gas per day (MMSCFO). Annualized peak production rates for the Kuparuk are expected to be between 4,400 ' and 15,700 BOPD. Annualized waterflood injection rates are estimated to peak between 5,300 and 18,900 BWPO and MI rates are expected to peak at 3.7 to 13 MMSCFO. / Page 19 ConocoPhillips Alaska, Inc. Application to the AOG.r the Fiord Area Injection Order Colville River Field e November 22, 2005 20 AAC 25.402 (c)(15) Mechanical Condition of Wells Within X Mile of Proposed Area Six abandoned wells as shown in Figure 2 penetrate the proposed injection -žf:ñ'1es within X mile of the injection area: Fiord #1, Fiord #2, Fiord #4, Fiord #5, Nigliq #1, and Nechelik #1. Well Completion Reports (AOGCC form 10-407) and schematics are attached for the five abandoned wells. /~~ Three new wells were drilled in early 2005 to develop the Nechelik zone: CD3- 108 was completed as primarily a Nechelik horizontal injector with a thin Kuparuk sand open at toe; CD3-109 and CD3-110 were drilled into the Nechelik zone where production casing was set and cemented above the Kuparuk zone. Well schematics and drilling permit cover letter or Well Completion Report (form 10- 407) are attached for the new wells. / ~ \_~. co\,pf' ~ \ J DC.~~"-\ "/ \ \, ~ \ Il/ " Q "7 ~12:S'?~\i'-~ Q;) ~ CO\~"'\-\~~¿, Page 20 ConocoPhillips Alaska, Inc. Application to the AOGeOr the Fiord Area Injection Order Colville River Field e November 22, 2005 I ~ I ì-.J Cowille River Unit --1 , ,,,-,,,"11 .~ "'9: :F; .... .., L , I .... -' ,.. Proposed Fiord Oil Pool / Fiord-Nechelik Preliminary PA - r -.... CD4 , Figure 1 Proposed Affected Area for Fiord Area Injection Order Page 21 ConocoPhillips Alaska, Inc. Application to the AOGeOr the Fiord Area Injection Order Colville River Field e November 22, 2005 J' N N FIORD 4 . N ./ J /KV- ..., < .. K ./ NECHELlK 1 . . Future Nechelik Producer Future Nechelik Injector Future Kuparuk Producer Future Kuparuk Injector Existing Nechelik Penetration Existing Kuparuk Penetration I: nøøø I nORD 2 / \"" N N K ...... K II. S.. II 1\\\ \ \ ~\:\ STRTUTE MILES 0 FIORD ;5 2 STATUTE MILES I Figure 2 Proposed Fiord Oil Pool Development Wells and Existing Wells Page 22 ConocoPhíl/íps Alaska, Inc. Application to the AOGeOr the Fiord Area Injection Order Colville River Field ~ :::s roE Q.LL :::s ~ - E LL ~ ro C> c ~ . o ~ ::::1- :¡ ~ ~G) ::::1- ~.E Kuparuk e -- ::::IfIS &~ .- G) ::::1- z.E ~- =11 .!~ uS G)c z- Fiord 5 G'_LWD Depth Deep Res LWD o 150 MD 1 100 6840 6860 ~+"'-"'~ :~ 6880 : ' ¡ ; ! [ ¡ .....,;--~.......:;- .;,.~,~¡-+~·,,~:-~i·...,;·;;_· Figure 3 Fiord Type Log Page 23 e November 22, 2005 6876 Top Kuparuk e 6892 Base Kuparuk e (LeU) 6943 Base Nuiqsut 7021 Top Nechelik 7172 Base Nechelik ConocoPhillips Alaska, Inc. Application to the AOGar the Fiord Area Injection Order Colville River Field e November 22, 2005 CD3 - Kuparuk/Nechelik Sand Injector Completion j l ~ 16" Insulated Conductor to 114' E iii 4-Y>" DB Nipple w/ differential pressure-operated injection valve at +/-2000' TVD 9-5/8" 40 ppf L·80 BTCM Surface Casing at +/-2400' TVD, cemented to surface 4-/;''' 12.6 ppf LBO !8T Mod. tubing Circulating mandrel normally with wI dummy valve above Packer Production Packer Top Reservoir at +/- 6800' TVD Kuparuk 6900' TVD Nechelik / Liner top hanger / I --..:---..:-- - --- _..:-- ---I 1-= - -" -= - -= - - I ): ------------- ------------! ==t:~=t:=ë======~==~===== ~$-§.~§:§..§:§.~§'?= ! 3,500 -10,000' MD Horizontal ¡ 7" 26 ppf L-80 BTC Mod Production Casing @ +/-85° ~interval: 4-W' 12.6 ppfL-80 SLHT hanger/Jinerw/ blank across shale and slots across sand ~ interval: open hole completion (no hanger/liner) Figure 4 Typical Fiord Injector Well Schematic Page 24 ConocoPhillips Alaska, Inc. e e Fracture Containment Modeling in the Fiord Area Jack Walker September, 2005 Fiord Area Fracture cont_ent Modeling . September 2005 Summary Modeling fracture growth in the Nechelik and Kuparuk intervals in the Fiord area with Mfrac software 1 indicated that fractures caused by water and miscible gas injection will be arrested in confining zones above and below the injection intervals. The Alpine injection system has the capability of exceeding the parting pressures of the Nechelik and Kuparuk sands. However, insitu stress contrast is adequate to confine fractures initiated in the sands. Procedure Mechanical properties were calculated from Fiord #5 well logs (VanDeVerg 2005)2 and tuned to the actual Nechelik fracture data collected in Fiord #5. Based on mechanical property trends, 22 intervals between 6147 and 7206 feet subsea were identified including the productive sands. Mechanical properties were averaged over these intervals and used for fracture simulation. Figure 1 shows the mechanical properties plotted with depth. At a depth of approximately 6940 feet (subsea), the Nechelik fracture gradient was 0.69 psilft in Fiord #5 (Braden 1999)3. Mechanical properties logs indicated the Kuparuk sand fracture gradient is slightly higher (0.005 psi/ft) than the Nechelik sand fracture gradient. Maximum surface delivery pressures are expected to be 2400 psi for water and 3800 psi for miscible injectant. Ignoring friction pressure drop in the wells, these maximum surface pressures translate into bottomhole injection pressures of approximately 5500 psi and 4800 psi for water and gas, respectively. The injection system will be capable of delivering water at pressures exceeding the fracture pressures of Nechelik and Kuparuk sands. The gas injection pressure may barely exceed the NecheJik fracture pressure, but will likely not exceed the Kupaurk fracture pressure. Mfrac was run using 1 % KCI water as a substitute for seawater. Miscible injectant properties were created and named MGAS in the Mfrac fluid library. Leakoff was manually calculated based on reservoir and fluid properties4. Permeability, relative permeability and reservoir fluid viscosity were taken from Fiord #5 core and fluid studies. High injection rates (15,000 BPD for water, 15 MMCFD for MI) were chosen to model greater than planned injection pressure and greater stress on confining layers than that likely to be encountered during planned operations. The modeled rates are 150% of the maximum planned rates. The specific injection rate per foot of interval for the vertical well fracture model was more than an order of magnitude greater than the expected specific injection rates in the planned horizontal injectors. The much higher than expected rate was modeled as a conservative approach to ensure induced fractures will be confined. 2 Fiord Area Fracture cont_ent Modeling e September 2005 Perforations with large flow capacity were chosen to model low pressure drop. A vertical well frac was modeled with 1000 perforations (1" diameter) over each ~1J"'In \:- injection interval. The perforated interval was limited to the top 45 feet of the ""' ~ ";~ ' Nechelik sand, and over the entire Kuparuk sand. Fracturing of the Nechelik and Kupaurk sands were individually modeled with injection into only one of the two sands. _= Stress Gradiem -:c:l::L . -... -., - -,- - . - . -.,- -,- - p " I .;J.C;:. I I " Stress ~ > I ¡ ,~¡ ~. *0' -: -~ -! -:- -;-- 7;O~ ' :::'-':; CL~ (psi:!) (Psi) Figure 1 Mechanical Properties Fiord #5 Results Young's Modulus ¡ " ", '" I ¡ I I) I 1" - - - - - - - - - - - - - -- , " ," ¡" " J ,! ¡ "! _.. _1_ L _,_ J. ...1_ _ J. ...._1... . , , " " It I I I I I -., -,- r -.- 't...,- - T ""-r , " " ," , ., ¡ " '" r , ,,¡ ¡ I , ¡ J I I , , :Lt iJitH:t ,; ¡ I 11 I , " I' ¡ I ( I .,-~-.... ~I-T""--T-¡-r- , " 'I "[ I I I I I I , I' 'I I J I "'~'" . .J _1_ '- _I ...J_ _ J. ...1_'- , , , "" I _~_:_" _ ;~_L;~_~. , ¡ I \ I , ¡ -:-:-; -: --'-,:-;-;- .:e-.:~ ~A ~,; (¡...= {p::i) Poisson's Ratio , , , j I ,! r --------~-------~ I J' ", 1 ¡ I ", _ _ L. _ L _ J. _ _ _ .J _ -'_ -'__ , , , f I J ¡ . - r - r - ..- - - - ., - - -, - - : : : JI : : : .~~_~_~_ I ~__ , , , --~-~-¡- --U-i-- ::~:~ ;-~~~-~-~~~ : : : I : : : [ [ ! , --~-~-~--- -~-~-- , , , ! I' I' J --r-r-T---1 ~-~-- , , , I I ¡ I ----------- ----- , " , , I r I J c,;, c,.. Fracturing caused by water injection into the Nechelik interval would be confined ./ by the zones immediately above and below the Nechelik sands. The fractures induced by water injection may grow throughout the Nechelik interval even though only the highest quality sands are open at the top of the Nechelik. Nechelik fracturing was modeled with a vertical well model and a specific injection rate of >100 BPD per foot of open interval. This specific injection rate is much higher than the expected specific injection rate of approximately 2 BPD per foot of interval open to injection. The planned well geometry is an open hole horizontal well with a length of zone open to injection of approximately 8,000 feet. The Nechelik fracture geometries with vertical stress profiles are shown in Figures 2 and 3 for the water and gas vertical well cases with very high specific injection rates, respectively. Water injection into the Nechelik sand at the planned 3 Fiord Area Fracture con.ent Modeling e September 2005 specific injection rate of 2 BPD per foot would yield a much more narrow fracture than the case with> 100 BPD per foot specific injection rate. 5200 Stress 2' '-" a ?- t""" 7200 4000 5000 Stress (psi) Width Profiles % Length -.0- I .20 I .40 I III 60 I III 80 I _1!I90 I 895 i .99 I -0.05 o Width (in.) 005 0.10 Figure 2 Nechelik Water Injection Case Fracture Geometry Fracturing caused by gas injection into the Nechelik interval will likely be confined to a subset of the Nechelik interval because the delivery pressure is too low to part the lower portion of the Nechelik. Figure 3 shows the Nechelik gas injection case plotted with an expanded depth scale. Gas injection into the Kuparuk sand will likely have insufficient pressure to propagate fractures. Water injection into the Kuparuk sand will be arrested in the zones above and below the Kuparuk sand as shown in Figure 4. Kuparuk water injection would be confined to a height of approximately 90 feet height for the 15,000 BPD case based on the vertical well model, or a specific injection rate of more than 800 BPD per foot of open interval. However, water injection at the planned specific rate of 5 BPD per foot of interval open will not propagate a fracture in the Kuparuk sand. If the Nechelik and Kuparuk sands are less than 40 feet apart, injection into the Kuparuk via a vertical well at maximum delivery pressure and extremely high injection rate could potentially break into the Nechelik. , , . r& ~ '-JQ~\-~ c~\o 0C["~~ ~ \,,()\'\~~ ct 4 Fiord Area Fracture con.ent Modeling Stress ~ ¢:: -- a r 5000 Stress (psi) e - Width Profiles - % Length .0 I .20 I 1140 \ _I~g L III 90 I 1195 I .99 I -I September 2005 - ___ ._... ._._. __ - - J. _. _ -... h_'_ _ _u _ __ r----- i I I I , --------1----------- 6000 -0.10 ·005 o Width (in.) Figure 3 Nechelik Miscible Injectant Case Fracture Geometry Stress ~ -= --. a > t- Width Profiles - %Leng¡/¡ .0 - II III 20 I 11I40 ¡ -------1iI ----.~ ~g _11I90 11I95 .99 - - - - - - - - - - ~ - - - - - - - 0.05 0.10 5000 Stress (psi) Figure 4 Kuparuk Water Injection Fracture Geometry 6000 -0.10 -005 o Width (in.) 5 0.05 0.10 Fiord Area Fracture contceent Modeling e September 2005 Conclusions 1. Fracturing the Nechelik sands is possible with the delivery pressure and ' rate expected to be available at Drill Site CD3. 2. Fracture growth caused by injection into the Nechelik sands will be - confined to the Nechelik sands. The fracture model indicated that fracturing induced by miscible injectant will not grow throughout the Nechelik interval. 3. Fracturing the Kuparuk sands is not expected at the planned injection rate. Fracturing the Kuparuk sands is possible with extremely high injection water rates at the maximum delivery pressure. 4. Miscible gas injection pressure is not expected to exceed the Kuparuk minimum horizontal stress. 5. Fractures initiated in the Kuparuk interval by extremely high water injection rate would be arrested in the Kuparuk D Shale above the Kuparuk C Sand. Fractures initiated in the Kuparuk sand could potentially grow into the Nechelik sands if the interval between the Kuparuk sands and Nechelik sands is much thinner than that interval at the Fiord #5 well. 6 Fiord Area Fracture cont_ent Modeling e September 2005 References 1 Meyer & Associates, Version 5.2.1209, Natrona Heights, PA 2 VanDeVerg., fiord_5pb1_tops_model.xls 3 Braden, J., "Fiord #5 Testing and Stimulation Summary", April 10, 1999 4 Gidley, et. aI., Recent Advances in Hydraulic FracturinQ SPE Monograph Volume 12. 1989, pp. 147-157 7 i r __ STATE OF ALASKA _ ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG . f 1 &atus of W" OIL D GAS 0 2 Name 01 Operator ARCO Alaska. Inc 3 Address P.O. Box 100360, Anchorage, AK 99510~360 4 Location 01 we. at surlac. ABANDONED [!] SERVICE D SUSPENDED D 526' FSL, 420' FWl. SEC 2. T12N, R5E. UM AI. Top Producing InteMlI N/A AI. Total Depth 625' FSL. 1105' FEL. SEC 3. T12N, R5E. UM 5 Elevation in feet (Indicate KB. DF. etc.) 6 Leasa Designation and Serial No. ADL 372104 14 Dale Corrp., Susp. or Aband. 04/18192. 19 Directional Survey YES ŒJ RKB 38' ABOVE SEA LEVEL 12 Dale Spudded 13 Date T.D. Reached 02104192. 03/18192. 17 Total Deplh (MD. NO) 18 Plug Back Depth (MD+ TVD) 10.250' MD. 9973' TVD SURFACE NOD 22 Type Electric or Other Logs Run MLUDlUGRlCHT ZDIJCNlDEL 2ISL ClassJic41ÏOf1 01 Service W" 7 ¡Permit Nwrber 9,.,47 8 API NunÐer 50-103-20162 9 Unit or \..ease Name NA '--___.. '~1~) 11 . d and Pool EXPLORATION /15 Water Depth. fotfshont 116 No. oI~' NA feel MSL NA /20 Depeh where SSSV set , 21 Thickness of permafrœt NONE feelUD CASING SIZE 20" WT. PER FT. 91.5# 72# I GRADE H-4O MAJ, DIPLOG. VSP. SSTlCBT/GR. uS¡ CASING. UNER AND CEMENTING RECORD SElTING DEPTH MD TOP OOlTOM SURF 108' SURF 2388' 23 HOLE SIZE 26' 13-318· L-80 17-112· 9-518· SURF 7981' 12·1/4· 47# L-80 24 Perforations open to Production (MD+ TVD of Top and Bottom and interval. size and nurrber) 25 SIZE N/A N/A CEUENTlNG RECORD PERMAFROST GROUT 1075 SX PF 'E'.SOO SX CLASS G 100 SX TYPE C TOP JOB 4000 SX CLASS G TUBING RECORD DEPTH SET (MD) PACKER SET (MD) AMOUNT PULLED 26 ACID. FRACTURE. CEMENT SQUEEZE. ETC DEPiH INTERVAL (MD) I MtOUNT & KlIÐ OF MATERIAL USED · See attached o...aUo.. sur"'" 27 Oat. First Production PRODUCTION TEST I Melhod 01 Operalion (Flowing. gas lift. etc.) PRODUCTION FOR Oll-BBl GAS-MCF TEST PERIOD . CALCULATED OIL-BBl GAS-MCF 24-HOUR RATE. Date 01 Test Hours Tested Flow Tubing Press. Casing Pressure 28 CORE DATA Brief desa"Ption 01 lithology. porosity. fractures. apparent dips and presence of oil. gas or water. Submil core dI~. , Core data and log Information 10 be eubmltted by Exploration Department. FOITII 1 G-407 Rev. 7+80 CCNTNÆD 00 REVERSE SÐE WATER-BBl CHOKE Sl2£ I GAS-OIL RAllO OILGRAVIlY-API (con) WATER-BBl ~ it dt.Øcate I\M\-~.I.- :<.::: .1..:::;;:)1 l~:K~U/LI/NV/DRILLING ~ TEL NO:8888 (~ -- t:l898 P02 ..,.---:'....--..:r~............-............., ....... . " .., .. œJcœ~ FatM'R:W'1Ø'II ~. ., ~. CEP1H 1RÆVERT. ŒP1H ~ Interval teØd. ".... data. II ~ ~ tncf 81Ø11r. GaR. artt1 lime of tach phMe, IWE 'FomIIUon.....1D be ......,tIv ~ 0.. .... AllIICIfIetf ", usTcF..rr~ "'A~1IC.Gm),fØ'CR'tŒ OI"eMTOe .. . f ,.,.~ ÕMtly lhar diå 'farfgOing !lINt .,., c:urrwc:l1O ,... be. øI irrt - ~ .- J1øL~------ TI'1e ~"!)fU I NC'ì ~~ Datt rf~~ INSTRUCTIONS Generaf: This form Is designed for submitting a complete and correct wen oompletion report and log on all types of lands and teases in Alaska. Item 1: CfassfflCStion of Service WeDs: Gas InJection. water InJection, steam injection, ait Injection, salt water disposa', water supply for injection, observation, Injection for in-situ combustion. Item 5: Indicate which elevation is used as reference (where not olhslWise shown) for depth measurements given in other spaces on this form and In any attachment.. Item 18 and 24: I' this wen Is completed for separate production from more than one interval (multiple completion), so state In item 16, and in item 24 show the producing Intervals for only the Inlerval reported ¡l"Illem 27. Submit a separate 10nn for each additiona' intetvallo be separately produced, showing the data pertinent to $uch inreIYal. Item 21: Indicate whether from ground lever (GL) or other elevation (DF. 1<8. etc.). Item 23: Attached supple menial records for thIs well should show the derails of any multiple stage cement· 1"0 and the location of the cementing tool. nem 27: Method of Operation: Flowing, Gas lift, Rod Pump, Hydraulic Pump. Submersible, Water In· jectlon. Gas Injection, Shot·rn, Orher-exprain. (fern 28: If no core$ taken, indlcate -none-, Fomt f~.o' . . FIORD #1 PIA SCHEMATIC RKB, 31' above ground (All depths Gravel 20· Csg shoe @ 1 OS' 9-5/8· esg cut off @ 260' CBL indicates TOC in 9-5/8- X 13-3/8- annulus @ 350' 10.2 ppg brine 1 bbJ emt 11.3 bbls emt 1 0.2 ppg brine 10.2 ppg brine 2.2 bbls emt 18.2 bb/s emt 10.6 ppg brine 2.3 bb/s emt 25.2 bb/s emt level) Ground Level (31' RKB) 13-318- & 20- cut off @ 50' .........................~ :5........................... ....:.:.:.:.:.:.:.:.:.:.:-:.:.:.:-:.:.:...~ ~ ;iJJJ~i~i;:~~:~~ TOC ~ 170' (12 bbls cmt) r~,,;cr~. ~r~.~. ~ .. .- Cmt retainer @ 250' .~c~C~(~C~(~(~~(AC; .. ~.1'.1~.1~.1~.1~.1f~r ~ 12 bb/s emt ~~ ·~r~~l~~~~c~c , - ..... . . '~·~.i~i~i~i~.1·~~ ';<r;<r~ "è.lèKèAf f (, '~~1~1~1:1z t · ~:~:~~~: ~l~~ I ,.~ . . . ... c'" c" c'" cA c'" (J ·1:-1:1~1:1~1:~ . ;"'1"'1"1"1"1"; t·~· ".1 r~ r¡r.a r.a r.a rJ "Cc"Cc"'CC'~<C'~c~. ...·il!k, P.a".I: r.a r.a" ~ lf1:1:1f~ . ¡C:l:1rl~~ Irlr1:1:~ ~~lrlrl~~ . 10.2 ppg mud (:anCSd p'Ug-œOla,e. g:.~\ bearing interval 9830' - i 9950' ¡ / I I Þ : I I I I I I ~CA<4CC4C'¡ . l:l~l~l~~ I ,~rl~lr~~~ 1:1~1~1~~ ~.,~r:-~~"t . . ,,----. . .....~ 13-3/8- Csg shoe @ 2388' · TOC @ 678S' · Cmt retainer @ 6800' )-~ · Perfs 6876'·6906' ~ I Bridge Plug @ 6940' · Casing leak @ 6957' · TOC @ 727(1 I· C...t r~ @ 7300:' · Perfs 732~ · TOC @ 7898' · Cmt retainer @ 7930' · 9-518- Csg shoe @ 7981' BOC @ 8287' TOC @ 9618' BOC @ 10,050" TD @ 10,250' ·-.- ,~'- STATE OF ALASKA ( . KA OIL AND GAS CONSERVATION C.íSSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1 Status of Well Classification of Service Well OIL 0 GAS 0 2 Name of Operator ARCO Alaska. Jne 3 Address P.O. Box 100360. Anchorage, AK 99510-0360 4 Location of well at surface SUSPENDED 0 ABANDONED [K] SERVICE D 7 Permit Number 94-09 Pennitf94.061 SA 8 API Number __~ 50-103-20201 9 Unit or Lease Name 2126' FNL, 1314' FWL. SEC 24, T 12N, R 5E. UM At Top Producing Interval NA At Total Dep1h N/A 10 W \ ) FIORD #2 1 Field and Poo 934' FSL, 835' FEL, SEC 14, T12N, R5E, UM _ 5 Elevation in feet (indicateKB. OF. etc.) RKB 42' 12 Date Spudded 11-Feb-94 17 Total Depth (MD+ìVD) 8400' MD, 7214' TVD WILDCAT 13 Date T.D. Reached 02-Mar-94 18 Plug Back Depth (MD+ ìVD) SURF 16 Lease Designation and Serial No. ADL 372106 14 Date Compo , Susp. or Aband. 03/07/94(P & A) 19 Directional Survey YES [RJMWD NO 0 115 Water Depth, If offshore 16 No. of Completions NA feet MSL NA /20 Depth where SSSV set 121 Thickness of pennafrOst NA feet MD NA APf>ROX 22 Type Eledric or Other Logs Run DILJGR. SOT. DIUMSFL.DSI/GR, FMf/GR. SWC 23 CASING. LINER AND CEMENTING RECORD SETTING DEPTH MD I CASING SIZE 16" 9.625" wr 62.58# 53.5# GRADE B L-80 TOP SURF. SURF BTM 110' 2231' HOLE SIZE 20" 12.25" CëMENïÆCORJ 250 SX AS I 259 SX AS III, 447 SX CLASS G 24 Perforations open to Production (MD+ TVD of Top arid Bottom and interval. size and number) NA 25 SIZE TUBING RECORD DEI'TH SET (MD) PACKER SET (MD) NA 26 ACID, FRACTURE. CEMENT SQUEEZE. ETC DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED 27 Date First Production Date of Test Hours Tested PRODUCTION TEST MethodOfoperatiOl1(Rowing. gas 11ft. etc.) PRODUCTION FOR OIL-BBL GAS·MCF TEST PERIOD E: CALCULATED OIL'BBL GAS-MCF 24-HOUR RATEË WATER-BBL CHOKE SIZE I GAS-OIL RATIO OIL GRAVITY·API . (corr)' Flow Tubing Press. Casing Pressure WATER-BBL 28 CORE DATA Brief description of lithology. porosity, fractures. apparent dips and presence of oil. gas or water. Submit core chips. "'0 be sent under separate cover by Exploration Geology Form 10-407 Rev. 7-1-80 CONT1NUÉD ON REVERSE SlÖE Submitinduplic,sta -: .. i . Casing cut and backfilled 3' below ground level RA A A A A . A A A A A A A A A A A A A A A A A A ~ A A A A A A A A A A A A A A A A A A A A A A A A . ~'\~<~':. ~ ':. ': A ~ A A A A A A A A A ~ ':. ~ ':.A~<,\ P&A Cap Marker 3' below ground level ~,~ MC ~.1œ Q1) ~$.i.~~iI J.f.~~~~l Surface Plug , ...-:.:.:...:.;-::-:.~.:..........:..........~.................... Bndge Plug @ 300 . Wl~}~":/Æ~~ }/i~~~H/~~ 16 , 62.58#. PEB . .' iïít.. .' .' . .' .' ..~ .' . (110' R~I \Y' fil! til""w per 20 AAC 25.105 (k) ~~~~~i 11.2 ppg :~~~~~~~ ~;~.» M d I););~;~ ~,.~;~;~ u 1~1';~"~ ...!'ti...!.". ...!\t-!'8.. ~~('(~-t ~ít~«íC: ~.tt("-t ·.tt~t.tt: tttt.::.~-t ·~t.::.t.tt: .J'..~."". ........".~ ".!'8.~" .......... t"'~"'~"'- ~-t!-t!-t~ TOC @ (2075') ..,...,. .,......,. ::;);~; ~;);~;~ ......... !'.i........ .,.-".,. arl'.a"'.,. ......:*ti.... .......... .,.,.,- .fI'............ . I 9-5/S· 53.5# L-SO BTC 1'J.~,~,... '~J.~J.~J.~ Cement Retainer @ 2175 t I' \i~.". ........ ( 2231'PBTD I 2076' TVD) t~-t"'· ·~ot~J per 20 AAC 25.105 (g2) Casing Shoe Plug BOC @ (approx.2331') per 20 AAC 25.105 (k) 11.2 ppg Mud per 20 AAC 25.105 (12) 20 AAC 25.105 (I) waived 20 bbls Hi-Vis TOC @ (approx. 2400') pressu;~) C30 I (2890·.~ BOC @ (3300') per 20 AAC 25.105 (k) 11.2 ppg Mud per 20 AAC 25.1 05 (f1 ,1) Hydrocarbon Kuparu k/J4 (7794'-79 BOC @ (S044') Showl ARCO FIORD #2 PLUG AND ABANDON SCHEMATIC frj = Lead Cement per 20 AAC 25.105 (k) 20 bbls Hi-Vis : 11.2 ppg : Mud I ---------------, ~ .WiN .'XX.,...,·.., ~#j#f:; f3 = Tail Cement = Cement Plugs = Gravel Fill TD @ 8400' MD WLM 4/4/94 4. OIL AND GAS CONSERVATION COMJ_N WELL COMPLE"n"ON OR RECOMPLETION R~PORT AND LOG 1. Status of well Classification of Service Well Oil 0 Gas 2. Name of Operator ARCO Alaska, Inc. 3. Address P. O. Box 100360, Anchorage, AK 99510-0360 4. location of well at surface o Suspended o Abandoned 0 Service 0 7. Permit Number 99-016 8. API Number 50-103-20289 9. Unit or lease Name 254' FSl, 842' FWL, Sec. 22, T13N, R5E,-UM At Top Producing Interval 572·FSl,1025'FWL.Sec.22, T13N,R5E, UM At Total Depth 572' FSl, 1025' FWL, Sec. 22, T13N, R5E, UM 5. Elevation in feet (indicate KB, DF, etc.) 16. lease Designation and Serial No. KB 28', Pad 1.6' ADl364472 AlK 4544 12. DateSpudded 13. Date TD. Reached 14. Date Comp., Susp. Or Aband. March 2,1999 March 9,1999 March 13, 1999 17. Total Depth (MD + TVD) .18. Plug Back Depth (MD + TVD) 19. Directional Survey 7171' MD17138' TVD P&A YES 0 No 0 22. Type Electric or Other logs Run MWD GR/Resistivity, Platform Express/CMR, Dipole Sonia. RFT, Sidewall Cores 23. CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD TOP BOTTOM Surface 108' Surface 1973' 115. Water Depth, if offshore (P&A'd) NIA feet MSL 120. Depth where SSSV set na feet MD 16. No. of Completions na 21. Thickness of Permafrost 1195' MD/TVD CASING SIZE 16" 9.625" WT. PER FT. 62.5# 40# GRADE H-40 HOLE S1ZE CEMENTING RECORD AMOUNT PUllED 24" APprox. 200 CF 410 sx AS III plus 230 Sx Class G + additives L~f:!O na na na na 12-1/4" 8-1/2" o 24. Perforations open to Production (MD + TVD of Top and Bottom and interval, size and number) 25. SIZE TUBING RECORD DEPTH SET (MD) PACKER SET (MD) * Plugged & Abandoned all mud logged shows- no perforations 26. ACIP, FRACTURE, CEMENT SQUEEZE. ETC. DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED P&A procedures approved by Blair Wondzell 3/11/99. See P&A Addendum for specifics. 27. Date First Production N/A Date of Test Hours Tested PRODUCTION TEST Method of Operation (Flowing. gas lift, etc.) Plugged & Abandoned Production for Oll.BBl GAS-MCF Test Period > Calculated Oll·BBl WA TER-BBl CHOKE SIZE IGAS-Oll RATIO Oil GRAVITY - API (corr) N/A Flow Tubing Press. 28. Casing Pressure GAS-MCF WA TER-BBl 24-Hour Rate> CORE DATA Brief description of lithology, porosity, fractures, apparent dips and pressence of oil, gas or water. Submit core chips. See attached information Form 10-407 Rev. 7-1-80 . CONTINUED ON REvERSE SIDE tit Submit in duplicate 29. 30. GEOLOGIC MARKERS FORMATION TESTS NAME I ncludeinterval tested, pressure data, all fluids recovered and gravity. GOR, and time of each phase. MEAS. DEPTH TRUE VERT. DEPTH Albian B 5732' 5672' Albian C 6201' 6140' Albian D 6280' 6320' Base H RZ 6545' 6482' K1 6609' 6549' Kuparuk C 6686' 6622' Nechelik 6695' 6631' See Attachments 31. LIST OF ATTACHMENTS Logs, Core descriptions. geologic tops, daily summary, mud log. & directiomal survey 32. I hereby certify that the following is true and correct to the best of my knowledge. Signed70J Y1~ Title ExplorationlTarnlTabasco Team Leader Date 4/13/ CfC¡ Prepared by Sharon Allsup-Drake 4/8/99 INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Item 1: Classification of Service wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion. Item 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other spaces on this form and in any attachments. Item 16 and 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the producing intervals for the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. Item 21: Indicate whether from ground level (GL) or other elevation (DF, KB, etc.). Item 23: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, Other-explain. Item 28: If no cores taken, indicate "none", Form 10-407 '¡:¡i:',"! ~!'I¡',I!i: ;;::i;)!,¡\ 'HH%¡\ È}[¡¡i,; . '. '.' JWj~¡¡i~ :,;::,::'; ,..., .jm:r.'><· '. .'.. ,I!¡:·!':! '¡:n¡¡!¡j~ :'1ihj¡:: m¡Wm ¡~¡!mw I rlord #4 f-J & A ~chematic e e ::::;::': :ii:¡:::: .;.;.,.;. ,:;:-¡:;:: iWHüt ¡¡¡¡!,!:!.. 16" Conductor to 115' ¡iE¡¡j¡fE: .::. ~mmm 33' - 300' 21 Bbls of 15.7 ppg AS 1 slurry 1920' EZSV Retainer 9-5/8" 40 ppf, L-80, BTC Surface Casing @ 1973' MD I 2440' TVB cemented to surface ;:,: ¡!¡ ;;;; %! ;';;":':' :)¡j,: .::::!:::, Squeezed 10.7 Bbls below the retainer and dumped 3.8 Bbls on top of retainer utilizing 15.8 ppg Class G Cement · 2850' - 3100' 23 Bbls 15.8 ppg Class G Cement · 3100' - 3385' 25 Bbls Hi Vis 10.6 ppg mud pill · 4000' - 4300' 30 Bbls. 15.8 ppg Class G Cement · 4300' - 4585' 20 Bbls Hi Vis 10.6 ppg mud pill · 5500' - 630Q' 67 Bbls. 15.8 ppg Class G Cement · 6300' - 6500' 14 Bbls Hi Vis 10.6 ppg mud pi,lI . 6500' - 71"(0',,53 Bbls. 15.8 Class G Cement . TO @ 7171' MO/7138' TVO r r ~. tit STATE OF ALASKA . ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1. Status of well Classification of Service Welt Oil 0 Gas 2. Name of Operator ARGO Alaska, Inc. 3. Address P. O. Box 100360, Anchorage, AK 99510-0360 4. Location of well at surface o Suspended o Abandoned 0 Service 0 7. Permit Number 99-020 8. API Number 50-1 03-20292 9. Unit or lease Name 739' FNL, 437' FEL, Sec. 32, T13N, R5E, UM AtTop Producing Interval 353' FNL, 177' FWL, Sec. 33, T13N, R5E, UM At Total Depth 353' FNL, 177' FWL, Sec. 33, T13N, R5E, UM 5. Elevation in feet (indicate KB, DF, etc.) /6. lease Designation and Serial No. iKB 28', Pad 6. feet ADL 364471 ALK 4480 12. Date Spudded 13. Date ToO. Reached 14. Date Comp., Susp. Or Aband. March 14, 1999 March 31, 1999 April 23,1999 17. Total Depth (MD + TVD) 18. Plug Back Depth (MD + TVD) 19. Directional Survey 7490'MDI7400'TVD surface YES 0 No 0 22. Type Electric or Other Logs Run LWD GRlResistivity plus SWS Piatíorm ExpresslCMR, Dipole Sonic, RFT's, Sidewall Cores 23. CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD TOP I BOTTOM Surface 112' Surface 1981' Surface 7484' NI A~-'-----¡ ~ber ./ FIORD #5 11. Field Pool o ville River Unit 15. Water Depth, if O.ffshore NIA feetMSL /20. Depth where SSSV set NI A feet MD 16. No. of Completions 1 21. Thickness of Permafrost 1250' MD CASING SIZE 16" 9.625' 'NT. PER FT. 62.5# 40# 26# GRADE H-40 L-80 L-80 HOLE SIZE 24' 12-1/4" 8-112" CEMENTING RECORD 9 cu yds High Ear'¥ 480 sx AS3 plus 230 sx CI G 400 sx 13.0 ppg ci G plus 245 sx 15.B ppg CI G AMOUNT PUllED 7" ------- 24. Perforations open to Production (MD + TVD of Top and Bottom and .interval, size and number) Wellbore has been P&A'd Nechelik Interval w/ 4-1/2" 5 spf 7024' to 7044' MD (6934' to 6954' TVD) 7044' to 7064' MD (6954' to 6974' TVD) Kuparuk Interval w/2-1/8" Enerjets @ 4 spf 6880' to 6900' M D (6790' to 6800' TVD) TUBING RECORD DEPTH SET (MD) 301/2" 9.3# 8 rd EUE 6830' MD TT 26. ACID, FRACTURE. CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED 25. SIZE PACKER SET (MD) 6713' MD 7024' to 7064' MD 24B,OOO Ibs 16/20 ISP Proppant 27. PRODUCTION TEST . Date First Production Method of Operation (Flowing, gas lift, etc.) April 11 ,1999 Without lift and with nitrogen lift from annulus. First test with Nechelik only, second test with Nechelik & KuparUk Date otTest Hours Tested Production for OIL-BBl GAS-MCF WATER-BBl CHOKE SIZE ¡GAS-Oil RATIO 4/11-4/20 65.5 hrs & 65 hrs Test Period> 10,053 4657 561 128 (open) 463 Flow Tubing Casing Pressure Calculated Oll-BBl GAS-MCF WATER-BBl Oil GRAVITY - API (corr) 1BOt0540 400 10 B70 24-HourRate> 1227/2475 551/1165 166/40 30.5degAPI 28. CORE DATA 3rief description of lithology, porosity, fractures, apparent dips and pressence of oil, gas or water. Submit core chips. See Attachment :>rrn 10-407 Rev. 7-1-BO CONTINUED ON REVERSE SIDE Submit in duplicate 29. . GEOLOGIC MARKERS 3Q. . FORMATION TESTS MEAS. DEPTH TRUE VERT. DEPTH Include interval tested, pressure data, all fluids recovered and gravity. GOR, and time of each phase. NAME See Attachments 31. LIST OF ATTACHMENTS 32. I hereby certify that the following is true and correct to the best of my knowledge. Signed '1?w.1 Y>Jtv!A ~ Paul M:UßB: - Title DrillinQ Team Leader Date 5i2A Iqq Prepared by Sharon Allsup-Drake INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Item 1: Classification of Service wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion. Item 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurementsgiven in other spaces on this form and in any attachments. Item 16 and 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the producing intervals for the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. Item 21: Indicate whether from ground level (GL) or other elevation (OF, KB, etc.). Item 23: Attached supplemental records for this welJ should show the details of any multiple stage cementing and the location of the cementing tool. Item27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, Other-explain. Item 28: If no cores taken, indicate "none". Form 1 0-407 e . ARCa <> Subject,.,-:. .n -#- r T () It D-rr-.c:; . File ~ p fA ~CJehA~../-/r I By TJ ß (¡ Calculations Ch Sheet number @ Date 'f/~! 11 /& ·CY\ dt.A.c/vr e J / tj ''¡2ý¡j ..,....~~. ~...\" ""-.' !P ~:~" '. """'",- ..... .....~ " "--- ..... "' "-- ' n' J '" ...:...".,,''-.....,... I '4,. """,Iv;;)!.' e ) l Ç"CI Jw' .~..'.<,.'.". . ."....., " ........ '. " '.' ''L . .. '. '..', '. .... ", -'. \.. . / ~ c¡ ~ ',£" f~c~ Qrl'"'5e. }f~1 Àfl) C¡,.. r ,,/ Y 80 rx, '!>:] I'IIAJ "2Jof";<. CI ~ --I G LlM..e of (Í) ~ ] {..' 7.1 Ji.. O.OOS~~ . J12.l.t tlfl"l..ke. O.02C.' ?~ ^ 'fPG' 4Þ1..kr(! æo 2.~2.¿ ~ to?" Be 0 .OJ%?.. t:,¡,f '. 9 r;( x--;- .. ,iÎ.-r<I-Lr h /("00"'"-:::" l-fJ lo~1 J vI-. I}-S I G~wf " 2 '11 r ~~:-::~ ./ ./ JOC L.~J f2 J7tf),O þ1¡) - ,,~ .~ " '. -'" " . ", ,"'" 6LiV...~?G¿b . ..'~~ L x N,y.,-Ie... <2. ~']/" ,/''''/ ;' ..; 70 L T'-;~ ct· "ø'" /It;!) ,/,' .:'-... ,...-/' . , ,'::::·X.. '.' / . \,~. {)L ~ ~ ~ ":lea, . , 6L",,(! '~13 þ " ,/, j<J2yh.?o ç.. 'I. '. ", ~ ~¡"l~~ , ;"\..:...:..-..:.-----_._-_.~-~. -- _. II- .. ..!./' ;'.l;'::~·:f A"; ;'~:.~ ·{:..:-f:J" iii¡J ........1 .' ,~.. ··1 (¡:~~-tj :~~?f.'~ :':;>h~.~ ~¡i ~f;:l ;~:'J :;(1 ';..-q .:'~.j :::~J ~~:. , ~~\:'-~ ~." . ~{;~:'~ ',:;'j ~M "..! :}\I "j '.' .J ".'..¡ . '~'; '.f ....¡ .~/~ ~ ": :D ".;1 N ., ...1 /~t ::1 './~ ~ ~ d .oj ,j '·1 ;, ~ ì1 ., j 1 ·1 :1 . ' ~.;:~ -_:--~~~~~I - { STATE OF ALASKA~/~' . . . c ALASKAr~?)AND'GAS CONSERVATION;~Dg}1ISSI0_N . V:~LL COMPlEïla.'4 OR FU!COF¡~PLETIOtTf~ËPORT At-'JD LOG . -------»-,...,..- ---.--..- ----------- ---_.---- - -.-- - -- .'.-- - ~- . ---. ---.- 1. Status of Well Classification of Service Well ollD GAS 0 SUSPENDED 0 ABANDONED Q: SERVICE 0 2. Name of Operator 7. Permit Number _~ohio AJª-ê_ka Petroleum Company 3. Address 81-149' 8. API Number POllclLk~-Anchorage , 4. location of well aj surface 814' WEL ~'i340' E.LV~ ' At Top Proaucing Interval 50- 101-70020 9. Unit or lease Name A 1 ;:¡ s k.a..-:....9.9...5.D2 NSL. Sec. 18, T12N, R5E. UPM LOCATIONS ~e~' "'7 VER~IFIED N h 1· k Jll .,/ Ë ec e 1 It ,/ ,..' At Total Depth Surf. 1 ~..~~I~ an~ ~/ vertical well B. H. . ~ (exploration) 5. Elevation in feet (indicate KB, OF. etc.) /6. lease Designation and Serial ~o. KBE '= 43.82' AMSL ADL 25538 . 12. Date Spudded 13. Date T.D. Reached 14. Date Comp., Susp. or Aband. /15.: Water Depth. if offshore /16. No. of Completions ---1L.17/82 3/7/82 3/17/82 . nla feetMSl n/a 17. Total Depth (MD+TVD) la.Plug Back Depth (MD+TVDI 19. Directional Survey 20. Depth where SSSV set 121. Thickness of Permafrost' 10018' MD&TVD Surface YES 0 NO Q tI/ a feet MD 1150' , 22. Type Electric or Other logs Run VSP, Borehole Graviometer. sidewall cores SP/DIL/GR/BHCS. FDC/CNL/GRicAL. HDT. DIL/GR. BHCS/GR. FDC/CNL/GR, NGT, RFT, BHCS/GR!DIL, 23_ CASING. LINEA AND CEMENTING RECORD 'SETTlNG DEPTH MD GRADE TOP BOTTOM ConductoTSlIrf;:¡ce 91' T~80 Surface 2700' T~80 Surface 8559' CASING SIZE WT. PER FT. 20" 104# 13 3/8" 7211 9 5/811 47/1 CEMENTING RECORD AMOUNT PULLED 171 cu. ft. PermafrQst II 2352 cu. ft. Permafrost II 1150 cu.ft. Class G~ 130 cu.ft. Permafrost C HOLE SIZE 26" 17 1/2" '12 1/4" 24. Perforations open to Production (MD+TVD of Top and Bottom and interval. size and number) 25. SIZE N/A TUBING RECORD DEPTH SET (MD) PACKER SET (MD) N/A 26. ACID, FRACTURE. CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED. Sp-e Well Hi~tory .- . . . 27. Date First Production PRODUCTION TEST I Methoç! of Operation (FIO~j~9: gas li~t, etc.!: . .~. PRODUCTION FOR Oll-BBl GAS-MCF WATER-BBl TEST PERIOD. ;. CALCULATED Oll-.BBl, 24,HOUR RATE .. ,. '.' CHOKE SIZE I GAS-~Il R,ATIO Oil GRAVITY-API (cord Date of Test Hours Tested Flow Tubing· Casing Pressure Press. GAS-MCF WATER-BBl ro, 28. CORE DATA . Brief description of lithology. porosity, fractures, apparent dips and presence of oil. gas or water. Submit core chips. See enclosed Well Data Sheet C~ fn'~ lrl~r~ RrdJA'l' 'Fqr-....¡¡p, ~p.~1,n ~~l,t. r~ tï::~_.f:'·(' ..... ~.~ ~ ~ ~ ~ U S" ~ ~ I' i r'i - If f""'" Fr~'?;;" ·i<~.,H""1I ~ APR 161982 . _~~ ~~ i!. ~(\~ß !~ ~ ~ . . ~~ U [( j .ï· ~ ,. J [l A!3ska Oil & Gas Cons. Co~mjss~' ._ . '. - ." . , . '. Anchorage .on _ RECEIVE~ Form 10-407 Rev. 7-1-80 Submit in d~plicate CONTINUED ON REVERSE SIDE ..;",i;}/ "iF'· _ ~:: -:::4 . 'I: >,'{ .~ ':'~ '. i .',¡ 1 -¡ ··.1~ . ~lj .j J J "'\" {l ] ," :"J :~1 ;~.I .~~ ,~ '~~ .q ..~ ,; .-~ j .~ :~ ~1i " "'; ;~1 :~ ;~ a j 1 !i ~ j ¡ ¡ ; ~ ---< r' ~ GEOLOGI'C'MA~¡ 30. {¡PORMAT'ON TESTS 29. NAME Jnclu de interval tested. preSSlJre data, all fluids recovered and gravity, GOR, and time of each phase. MEAS. DEPTH TRUE VERT. DEPTH Lower Cretaceous 6590' 6590' No DST's run in well Permo-Trias. ¡ 8436' 9908' . 8436' Carboniferous .9908,'. t()t~JF!O~:~~TI At· ~..¿, i( 1j g t :..':,,~ ~":IIJ ~ ~ äj~ . ~ ~,.,.",..... f- n. P":'P.ØI \.(' ~ ~\ H H'~ ~~ ~ ·I;\~; ~ ~ .' r'. _. x ". t J ¡ \¿ ~ ~.... '( '\io,. .._ ,..,.... 31. LIST OF ATTACHMENTS '. Well History. Logs. Core Data Sheet. Dry Cuttings 32. I hereby certifY,that the,.,foregoing is true a[1d èorrect to the best of my knowledge ',' . .~ Signed ~~ tt~ ~ R. H. R~i,ley llt· /~n'. Dist,ict Dril1ingo". I .. Eng1neer v-'''I ''"I-- INSTRUCTIONS . General: This, form is designed for submitting a complete and correct well completion report and log on all types of lands and leases inA.laska. Item 1: Classification of Service WeHs: Gas injection, water injection, steam injection, air injection, salt water disposal, water sl!Pply for injection, observation" injection for in-situ combustion. Item 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other spaces on this form and in any attachments. Item 16 and 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the producing intervals for only the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. . . . Item 21: Indicate whether from ground level (G L) or other elevation (DF, KB, etc.), Item 23: Attached supplemental records for this well should show the details of any multiple stage cement- ing and the location of the cementing tool. Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water In- jection, Gas I njection, Shut-in, Other-explain. Item 28: If no cores taken, indicate "none". .Form 10407 -~,. . .-,.----- -....----..-...-.-. - _ _____._ __~h - ~-:,...~_.';"'~ , , ~.':- ~. ~,~, b:Je .. , ~-.j.-\ ~ WELL HISTORY NECHELIK ff1 Spudded well at 1500 hours, January 17, 1982. Installed & tested diverter system. Drilled 17 1/2" hole to 2710'. Ran open hole logs. Ran 70 jts. 13 3/8" 72/1 L-80 Buttress casing to ,2700'. Cemented with 2352 cu.ft. Permafrost II cement~ Nippled down diverter, installed and tested BOPE. Cleaned out to 2662'. tested casing to 3000 psi, okay. Drilled out to 2732'. performed leak-off test to 0.82 psi/ft. gradient (no leak-off obtained). Drilled and cored 12 1/4f1 hole to 7450'. Cut 3 cores from 6338-7230'; total cut 179.75'. total recovered 150.5'. Ran open hole logs and RFT. Drilled 12 1/4" hole to 8527' and ran open hole logs, RFT, and side- wall cores. Drilled 12 1/4" hole to 8559'. Ran 222 jts._-.2.-u,5j~!3~ 47/1 L-80 Buttress casing to 8559'. Cemented in two stages: First stage with 1150 cu. ft. Class G cement;· second stage through D.V. packer at 2623' with 130 cu.ft. Permafrost C cement preceded by Arctic Pack. Cleaned out D.V.; tested casing to 3000 psi. okay. Cleaned out float equipment and drilled 8 1/2" hole to 8587'. Performed leak-off test to 0.815 psi/ft. gradient. Drilled and cut 18 cores from 8763-9918'; total cut 977'; total recovered 977.25'. Drilled to 10018'. Attempted to run open_hole logs; hit bridge at 9890'. Made wiper_trip to clean out hole. Ran HDT; stuck in hole; recovered. Ran velocity survey, HDT. sidewall cores. and gravity meter. Set bottom cement plug at 10018' with 114 cu.ft. Class G cement. Pumped second plug from 8869-8660' (160 cu.ft. Class G cement). Set EZ Drill at 8459' and squeezed 70 sks Class G; lay_cement plug (30 sks) on top of EZ Drill. Pressure tested to 3000 psi. Lay cement plug from 2650-2280' (145 sks Permafrost C cement). Cut off 9 5/8" casing at 92' _BKE and cut off 13 3/8" casing 5' below cellar top. Cut cellar out below tundra and cemented from 92' BKE to surface with 52 sks Permafrost C cement. Installed abandonment marker and released rig at 2000 hours. March 17. 1982. NOTE: Cement plugs witnessed by Bobby Foster of AOGCC. RECEIVED APR 161982 Ä!3.:;!<a Oil & Gas Cons. Commissiu¡t Anctwrag!: cn~~Jç~f\,~~\~TI ~l' J~... ,I '" - ,_:4 ~ ~ L\ "~,y ~ ~~.~_ _: ,j< '.~~.~.'J ~/ ~(. § f\ ft· , , '.,. ~,,'" ~ ~ )" ~ I:· )"' :;:: i ~ ; '" · ~ I~ \iL<J a-S ~u H. t.L __ ",. ~ _.... _,"""" .u_.. ,..... ,-~;:::: .-:::....-:. ::;.~,~T :·:·,~·;~rr:~-~-"'":·~·~: -: .~-:.....~--- .. .... Nectflik #1 P & A Schemat. r·'·'·'·····,·,·..,·,· "wI 13-3/8" 72#, L-80, BTC Surface Casing cut off @ 5' 20" Conductor to 91' ...=---- 9-518" 47# L-80 casing cut off @ 92' BKB Cemented from Surface to 92' BKB with 52 sks Permafrost C cement . 2280' - 2650' 145 sks Permafrost C cement plug · 30 sks cement plug on top of EZ Drill · EZ Drill set at 8459' · Squeezed 70 sks Class G cement . 8660' - 8869' 160 Cu. Ft. Class G cement plug . 114 Cu. Ft. Class G Cement Plug . TD @ 10018' MDfTVD i:¡. /~ ~- (. STATE OF ALASKA a( ALA. OIL AND GAS CONSERVATION COM ION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1. Status of well Classification of Service Well Oil 0 Gas 0 Suspended 0 2. Name of Operator Phillips Alaska, Inc. 3. Address P. O. Box 100360, Anchorage, AK 99510-0360 4. location of well at surfaœ Abandoned It) Service 0 7. Permit Number 201-036/301-062 8. API Number 50-103-20370-00 9. Unit or lease Name 210' FSL, 1170' FWL, Sec. 2, T12N, R4E, UM (ASP: 369592, 6003006) AtTop Producing Interval 1009' FSL, 328' FWL, Sec. 2, T12N, R4E, UM (ASP: 368762, 6003820>- At Total Depth 1011' FSL, 337' FWL, Sec. 2, T12N, R4E, UM (ASP: 368771, 6003822) 5. Elevation In feet (indicate KB, DF. etc.) 6.lease Designation and Serial No. 43 DP RKB I Pad 15' ADL 380092/388525 12. Date Spudded 13. Date T.D. Reached 14. Date Comp.. Susp. Or Aband. March 5,2001 March 14,2001 March 21,2001 17. Total Depth (MD + TVD) 18. Plug Back Depth (MD + TVD) 19. Directional Survey 8040' MD 17875' TVD 2050' MD 12036' TVD YES 0' No 0 22. Type Electric or Other logs Run MWDILWD with(ARC5-GRlRes), PEX(MCFUCNLfTLD/GRlAITH), CSI, DSI, MDT 23. CASING. LINER. AND CEMENTING RECORD SETTING DEPTH MD TOP BOTTOM Surface 117' Surface 2036' N/A .'\ '/ Exploration 115. Water Depth, if offshore (P&A'd) N/A feel MSL 120. Depth where SSSV set N/A feet MD 16. No. of Completions o 21. Thickness of Pennafrost CASING SIZE 16' 9.625· WT. PER FT. GRADE 62.5# 36# H~4!' HOLE SIZE 24" 12-1/4' CEMENTING RECORD AMOUNT PUllED J-S5 285 sx AS I 318 sx AS /II & 233 sx Class G 24. Perforations open to Production (MD + TVD of Top and Bottom and interval, size and number) 25. Size Plug #1: 8040'-6940' Plug #2: 4600'-3770' Ipl~g Ir.s; 2587:2050' TUBiNC RECORD DEPTH SET (MD) NM NM PÃCK'ER SET (MD) N/A None 26. ACID, FRACTURE, CEMENT SQUEEZE. ETC. DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED Plug 1: 8040'-6940' 400 sx 15.8 ppg Class G cement Plug 2: 4600'-3770' 345 sx 15.8 ppgClass G cement Plug 3: 2587'-2050' 275 sx 17 ppg Class G cement 27. Date First Production N/A Date of Test N/A Row Tubing Press. Hours Tested PRODUCTION TEST Method of Operation (Flowing. gas lift. etc.) Plugged & Abandoned Production for Oll-BBl GA5-MCF Test Period > Calculated Oll-BBl GAS·MCF 2~Hour Rate> WATER-BBL CHOKE SIZE GAS-Oil RATIO Oil GRAVITY - API (corr) Casing Pressure WATER-BBl 28. CORE DATA Brief description of lithology. porosity, fractures, apparent dips and pressenœ of oil. gas or water. Submit oore chips. To be sent under separate COVêr letter Form 10-407 Rev. 7·1-80 CONTINUED ON REVERSE SIDE Submit in duplicate 29. /--" GEOLOGIC MARKER~e 30. .--' ~ I \e FORMATION TESTS MEAS.DEPTH TRUE VERT. DEPTH Include interval tested, pressure data. all fluids recovered and gravity. GOR. and time of each phase. NAME To be submitted under separate cover See Attachment 31. LIST OF ATTACHMENTS Summary of Operations, Directional Survey, As-Built. Geological Markers 32. I hereby certify that the following Is true and correct to the best of my knowledge. Questions? Call Scott Reynolds 265-6253 Signed ß~ t..' ~ G. C. Alvord TItle Alpine Drillina Team Leader Date {, (4((.)/ Preþa,ed by Sharon Allsup-Drake INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Item 1: Classification of Service wells: Gas injection, water injection, steam injection, air injection,salt water disposal, water supply for injection, observation, injection for in-situ combustion. Item 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other spaces on this form and in any attachments. Item 16and 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the producing intervals for the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. Item 21: Indicate whether from ground level (GL) or other elevation (DF, KB, etc.). Item 23: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, Other-explain. Item 28: If no cores taken, indicate ·none·. Fonn 10-407 N~iq #1 P & A Schematice 16" Conductor to 117' 9-5/8" 36# J-55 @ 2036' MD 11989' TVD . 2050' - 2587' 275 sks 17 ppg Class G cement plug 10.4 ppg Kill Weight Mix I . 3770' - 4600' 345 sxs 15.8 ppg Class G cement plug 10.4 ppg Kill Weight Mix . 6940' - 8040' 400 sxs 15.8 ppg Class G cement plug . TD @ 8040' MDI 7875' TVD .. STATE OF ALASKA .. ALA~ OIL AND GAS CONSERVATION COM~ION WELL COMPLETION OR RECOMPLETION REPORT AND LOG " ¡,.' 1 a. Well Status: Oil 0 Gas U GINJ 0 2. Operator Name: ConocoPhillips Alaska, Inc. 3. Address: WlNJ 0 WDSPL 0 Plugged 0 Abandoned 0 20AAC 25.105 No. of Completions _ Suspended 0 20AAC 25.110 Other WAG 0 6003843 6010042 6016746 5. Date Comp., Susp., or Aband.: April 11, 2005 6. Date Spudded: March 22, 2005 7. Date TD Reached: April 9, 2005 8. KB Elevation (ft): 36.7' RKB /49.6' AMSL 9. Plug Back Depth (MD + lVD): 18915' MD I 6816' 1VD 10. Total Depth (MD + lVD): 18915' MD 16816' 1VD P. O. Box 100360, Anchorage, AK 99510-0360 4a. Location of Well (Govemmental Section): Surface: 1349' FSL, 816' FEL, Sec. 5, T12N, RSE, UM At Top Productive Horizon: 2331' FSL, 724' FWL, Sec. 33. T13N, R5E, UM Total Depth: 1586' FNL, 1806' FWL, Sec. 29, T13N, R5E, UM 4b. Location of Well (State Base Plane Coordinates): Surface: x- 388228 y- TPI: x- 392484 y- Total Depth: x- 388364 y- 18. Directional Survey: Yes 0 NOU 21. Logs Run: GRlRes, Dens/Neutron 22. CASING SIZE WT. PER FT. 16" 62.5# 9.625" 36# 7" 26# GRADE H-40 J-55 L-80 Zone- 4 Zone-4 11. Depth where SSSV set landing nipple @ 2267' 19. Water Depth, if Offshore: N/A Zone- 4 feet MSL CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD SETTING DEPTH lVD TOP BOTTOM TOP BOTrOM 36.7' 114' 36.7' 114' 36.7' 3075' 36.7' 2437' 36.7' 11076' 36.7' 6998' 12.25" 23. Perforations open to Production (MD + lVD of Top and Bottom Interval, Size and Number; if none. state "none"): open hole completion 213. Date First Production 24. SIZE 4.5" 1 b. Well Class: Development 0 Exploratory 0 Service 0 Stratigraphic TesD 12. Permit to Drill Number: ,I 15. Field/ 16. Property Designation: ADL 372105/372104/364471 17. Land Use Permit LAS21122 20. Thickness of Permafrost 1293' MD HOLE SIZE 42" CEMENTING RECORD AMOUNT PULLED 10 yds Portland Type III 522 sx AS Lite, 239 sx Class G 254 sx Class G 8.5" TUBING RECORD DEPTH SET (MD) 10097' I PACKER SET 10037' 25. ACID, FRACTURE, CEMENT SQUEEZE. ETC. DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED n/a PRODUCTION TEST Method of Operation (Flowing, gas lift, etc.) Shut-In, refer to attachment for flowback rates Production for OIL-BBL GAS-MCF WATER-BBL CHOKE SIZE Date ofTest Hours Tested Test Period-> FlowTubing Casing Pressure Calculated OIL-BBL GAS-MCF WATER-BBL press. psi 24-Hour Rate -> 27. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water (attach separate sheet, if necessary). Submit c;ore chips; if none, state "none". Form 10-407 Revised 12/2003 NONE CONTINUED ON REVERSE ,GAS-OIL RATIO OIL GRAVITY - API (corr) not available GEOLOGIC MARKERS e 29. e FORMATION TESTS I 28. NAME MD ìVD Include and briefly summarize test results. List intervals tested, and attach detailed supporting data as necessary. If no tests were conducted, state "None". CD3-108 Seabee Form. Nanushak Gamma Ray Shale Kalubik Kuparuk Formation 3203' 5460' 9564' 10060' 10147' 2509' 3913' 6456' 6706' 6746' N/A 30. LIST OF ATTACHMENTS Summary of Daily Operations, Diiectional Survey, Mechanical Integrity Test, Monthly Production Report 31. I hereby certify that the foregoing is true and correct to the best of ~¥ !o:nnwledge. Contact: Vem Johnson @ 265-6081 p~nted Name ..I.) " .R. ,Ivord Signature / --, - ~ Title: Phone Alpine DrillinQ Team Leader Date , r" f o-S~ Prepared by Sharon Allsup-Drake INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Item 1a: Classification of Service wells: Gas injection, water injection, Water-Alternating-Gas Injection, salt water disposal, water supply for injection, observation, or Other. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 4b: TPI (Top of Producing Interval). Item 8: the Kelly Bushing elevation in feet abour mean low low water. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 13: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 20: True vertical thickness. Item 22: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 23: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 26: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, Other (explain). Item 27: If no cores taken, indicate "none". Item 29: List all test information. If none, state "None". Form 10-407 Revised 12/2003 _ ConocoPhíllips AlaskatC. r~ - CD3-108 TUBING API: (0-10097, . SSSV Type: 00:4.500, 10:3.958) SURFACE -----< (0-3075, OD:9.625, 'M:36.00) 'ROOUCTION (0·11075, OD:7.000, 'M:26.00) PACKER 10037·10038, 00:5.970) NIP 10084·10085, 00:5.000) WLEG 10095-10096, 005.200) OPEN HOLE 11075-18915, 00:6.125) _., . 4tLPINE 501032050700 NONE Well Type: SVC Orig 4/11/2005 Completion: Last W/O: Annular Fluid: Reference Log: 38' RKB Last Tag: Last Tag Date: Ref Log Date: TD: 18915 ftKB Max Hole Angle: 0 deg @ Casing String· ALL STRINGS Description CONDUCTOR SURFACE PRODUCTION _ OPEN HOLE Tubing String· TUBING Size I Top 4.500 0 Gas Lift Mandrel5'Valves St I MD I TVD I ~~~ I Man Type V Mfr 1 9932 9932 CAMCO KBG-2 Other ()Iugs, equip., etc.) . JEWELRY Depth TVD Type 33 33 HANGER 2267 2267 NIP 10037 10037 PACKER 10084 10084 NIP 10095 10095 WLEG 10097 10097 TTL General Notes Date ¡Note 4/11/2005 TREE: FMC/Unihead System w/Horizontal Tree Gen 11/4-1/16" 5K TREE CAP CONNECTION: 7" OTIS Size 16.000 9.625 7.000 6.125 Top o o o 11075 Bottom 114 3075 11075 18915 TVD 114 3075 11075 18915 Bottom 10097 TVD 10097 I Wt I Grade I 12.60 L-80 Angle @ TS: deg @ Angle @ TD: deg @ Rev Reason: Last Update: Wt 62.50 36.00 26.00 0.00 CD3-108 Pull Ball, Rod, RHC, set OV. Drift TBG 4/29/2005 Grade H-40 J-55 L-BO Thread WELDED BTC BTCM Thread fBTM V Type I V 00 Latch I Port I TRO I Date I Vlv Run Cmnt OV 1,0 BK 0.250 0 4/12/2005 Description FMC 4.5" TBG HANGER CAMCO 'DB' LANDING NIPPLE BAKER PREMIER PACKER HALLIBURTON 'XN' NIPPLE @ 62.39 DEGREE HALLIBURTON WIRELlNE GUIDE I 10 4.500 3.812 3.875 3.725 3.875 3,875 ConocoPhillips Alaska, Inc. e Post Office Box 100360 Anchorage, Alaska 99510-0360 Telephone 907-276-1215 e ~ ConocoPhillips April 6, 2005 Alaska Oil and Gas Conservation Commission 333 West th Avenue, Suite 100 Anchorage, Alaska 99501 Re: Application for Permit to Drill CD3-109 Dear Sir or Madam: ConocoPhillips Alaska, Inc. hereby applies for a Permit to Drill an onshore production well from the Fiord CD3 drilling pad. The intended spud date for this well is 4/25/2005. It is intended that Doyon Rig 19 be used to drill the well. CD3-109 will be drilled to penetrate the Nechelik reservoir horizontally. After setting 7" intermediate casing, drilling operations will be temporarily shutdown, and the rig will be moved to C02 pad while an ice road is available. Doyon 19 will return to drill the horizontal section when an ice road is available in early 2006. At the end of the work program, the well will be closed in awaiting completion of well work and facilities construction that will allow the well to begin production fourth quarter 2006. Please find attached the information required by 20 ACC 25.005 (a) and (c) for your review. Pertinent information attached to this application includes the following: 1. Form 10-401 Application for Permit to Drill per 20 ACC 25.005 (a). 2. Fee of $100 payable to the State of Alaska per 20 ACC 25.005 (c) (1). 3. A proposed drilling program. 4. A proposed completion diagram. 5. A drilling fluids program summary. 6. Pressure information as required by 20 ACC 25.035 (d)(2). 7. Directional drilling / collision avoidance information as required by 20 ACC 25.050 (b). Information pertinent to the application that is presently on file at the AOGCC is: 1. Diagrams of the BOP equipment, diverter equipment and choke manifold layout as required by 20 ACC 25.035 (a) and (b). 2. A description of the drilling fluids handling system. 3. Diagram of diverter set up. If you have any questions or require further information, please contact Vern Johnson at 265-6081 or Chip Alvord at 265-6120. Sincerely, Vern Johnson Drilling Engineer Fïord (CD3) Colville River Field CD3e9 Suspension Schem. ';;¡';';'L ~I i:i!:;:£:: m¡wm W~jjm~ :'::;::::~ "::;j:¡:; :£::j:::i: HHm\~j ¡¡HWW fœmm ~ ;¡". 16" Conductor to 114' t· 4 W' 12.6#/ft 1ST-Mod Tubing set at 1645' MD !~mJim :=¡ 19~5/~'~~~::6~~~gSTC @ 2884' MD I 2498' TVD cemented to surface 9.6 ppg KCI Brine with 1500' MD diesel cap Displaced 4 W' and 7" with 55 Bbls diesel Top Nechelik at 9585' MD 17003' TVD 7" 26 ppf L-80 BTC Mod Production Casing @ 9685' MD I 7026' TVD @ 77° ConocoPhillips Alaska, Inc. e Post Office Box 100360 Anchorage, Alaska 99510-0360 Telephone 907-276-1215 e 1J./ ConocoPhillips March 14, 2005 Alaska Oil and Gas Conservation Commission 333 West ¡th Avenue, Suite 100 Anchorage, Alaska 99501 Re: Application for Permit to Drill CD3-11 0 Dear Sir or Madam: ConocoPhillips Alaska, Inc. hereby applies for a Permit to Drill an onshore injector well from the Fiord CD3 drilling pad. The intended spud date for this well is 4/14/2005. It is intended that Doyon Rig 19 be used to drill the well. CD3-110 will be drilled to penetrate the Nechelik reservoir horizontally. After setting 7" intermediate casing, drilling operations will be temporarily shutdown, and the rig will be moved to another location (likely CD3-1 09) in order to get another penetration in the Nechilik while the ice road is available. Doyon 19 will return to drill the horizontal section when an ice road is available in early 2006. The well will be drilled and the well completed as an open hole injector. At the end of the work program, the well will be closed in awaiting completion of well work and facilities construction that will allow the well to begin injection fourth quarter 2006. It is also requested that the packer placement requirement be relaxed to place the completion packer 250 ft TVD above the Nechelik formation. This will place the completion at a maximum inclination less than 65° and allow access to the completion with standard wireline tools for future intervention. Please find attached the information required by 20 ACC 25.005 (a) and (c) for your review. Pertinent information attached to this application includes the following: 1. Form 10-401 Application for Permit to Drill per 20 ACC 25.005 (a). 2. Fee of $100 payable to the State of Alaska per 20 ACC 25.005 (c) (1). 3. A proposed drilling program. 4. A proposed completion diagram. 5. A drilling fluids program summary. 6. Pressure information as required by 20 ACC 25.035 (d)(2). 7. Directional drilling / collision avoidance information as required by 20 ACC 25.050 (b). Information pertinent to the application that is presently on file at the AOGCC is: 1. Diagrams of the BOP equipment, diverter equipment and choke manifold layout as required by 20 ACC 25.035 (a) and (b). 2. A description of the drilling fluids handling system. 3. Diagram of diverter set up. Fior~~CD3) Colville River Field CD3., 0 Suspension Schem_c f· ¡¡¡illlll 16" Conductor to 114' 4 Yz" 12.6#/ft IBT-Mod Tubing set at 1695' MD 19-518" 36 ppf J-55 BTC II Surface Casing @ 2680' MD /2439' TVD cemented to surface L-.>. 9.6 ppg KCI Brine with 1500' MD diesel cap Displ¡;¡ced 4 Yz" and 7" with 50 Bbls diesel Top Nechelik at 8814' MD 16988' TVD 7" 26 ppf L-BO BTC Mod Production Casing @ 8,959' MD #6 . ~ ConocoPhillips . Chris Alonzo Development Supervisor. WNS ConocoPhillips Alaska 700 G Street Anchorage, AK 99501 Phone: 907.276.1215 RE("~" lCD " _...~. ''''':''''';\:,'IC,..,,'.i ;,,},' ~ January 11, 2006 J~ Aiì J1 lfl/]6 AJû,sk~l ::Ç.f"",... '/"Oh '. r, .. "'~I;' ~'\.~~ t;;\;~,~-S.. ~~ AFliCINra¡e. ..·..;Ii'Š Mr. John Norman, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage,AJC 99501 Re: Supplemental Information for the Proposed Fiord Oil Pool Colville River Field Dear Chairman Norman: ConocoPhillips Alaska, Inc. (CP AI) as operator of the Colville River Unit and on behalf of the Working Interest Owners, requested a conservation order for the proposed Fiord Oil Pool, and an area injection order (AIO) authorizing enhanced recovery operations in the proposed Fiord Oil Pool, dated November 22,2005. Attached to this letter are supplemental information for the proposed Fiord Oil Pool in the form of CP AI responses to AOGCC staff comments and questions provided electronically by Mr. Steve Davies. Weare very appreciative of the AOGCC efforts on recent Colville River Field activities. Please call me at 265-6822 or Jack Walker at 265-6268 with any questions. Very truly yours, q~¡µ~ ~: Development Supervisor, Western North Slope ConocoPhillips Alaska, Inc. Attachment . . Supplemental Information for the Proposed Fiord Oil Pool Colville River Field January 11, 2006 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 825 W. 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 Fiord Conservation Order & .Injection Order Supplemental Information . January II, 2006 Fiord Oil Pool Conservation Order and Area Injection Order Applications Questions for Operator The following list of questions and comments was compiled during review of the non- confidential portion ofCPAI's applications to the Alaska Oil and Gas Conservation Commission for the Fiord Conservation and Area Injection Orders, Colville River Field, dated November 22, 2005. Notice of Opportunity for Public Hearing has been submitted for publication in the Anchorage Daily News. Please provide responses to these questions and comments at least 5 working days prior to the tentative hearing date. ConocoPhillips Alaska, Inc., as operator of the Colville River Unit, offers the following responses the AOGCC questions and comments. The operator's responses, entered in bold/italics font, follow each of the AOGCC numbered remarks. 1. Please clarify the working interest ownership of Petro-Hunt in any leases within the affected area. Are there any other minor working interest owners within the affected area? Are Petro·Hunt and any other minor working interest owners agreeable to the current development plans? Are there any other ownership, surface ownership, or other issues outstanding concerning this development? Anadarko Petroleum Company, ConocoPhillips Alaska, Inc. (CPAI) and Petro-Hunt, LLC hold working interests within the area of the proposed Fiord Oil Pool. No others hold working interests in the proposed area. All three parties with a working interest in the proposed Fiord Oil Pool have approved the Colville River Unit Agreement and the Colville River Unit Operating Agreement. CPAI as operator has notified all working interest owners of the the Proposal to Develop the Fiord Nechelik Reservoir and no working interest owner has objected. Within the proposed Fiord Oil Pool area, Petro-Hunt holds 0.38% working interest in CRU Tracts 83, 110, 111, and 114 (ADL 384215 and 389725) toward the northwestern corner of the proposed Fiord Oil Pool (Figure 1); ConocoPhillips Alaska, Inc. holds 77.62% and Anadarko holds 22% working interests in these same tracts. The total area of these tracts is 1,568 acres. The area of these tracts within the future Fiord-Nechelik Participating Area comprise approximately 11.1% of the future Fiord-Nechelik Participating Area anticipated by the operator. Working interest of the remaining tracts in the proposed Fiord Oil Pool Area and future Fiord-Nechelik and Fiord-Kuparuk Participating Areas are 78% CPAI and 22% Anadarko. On behalf of the Alpine Production Facilities Owners, CPAI as Operator is developing an agreement for Alpine Production Facilities sharing for production participants with an ownership in production different than the Participating Interest in the Alpine Production Facilities. On behalf of Infrastructure Owners, CPAI as Operator is developing an appropriate infrastructure sharing agreement or agreements. These sharing agreements shall be consistent with the Colville River Unit Agreement and Colville River Unit Operating Agreement 2. Sections 13, 14, and 15 ofT12N, R5E, UM are currently governed by AlO 18B (Alpine Oil Pool) over a portion of the affected interval. These sections overlap with the proposed affected area for Fiord. Does CP AI propose contracting these ConocoPhillips Alaska, Inc. Page I of II Fiord Conservation Order & Atnjection Order Supplemental Information . January 11,2006 three sections from AIO 18B? If changes have been made to the proposed affected area for the Fiord applications, please provide an updated legal description to the Commission. The operator plans to propose contraction of the affected area for the Alpine Oil Pool and the associated Area Injection Order such that there is no overlap with the proposed Fiord Oil Pool. The proposed Fiord Oil Pool area is unchanged from the original request repeated below: T12N R4E sections 1, 2, 11-14 T12N R5E sections 1-18 T13N R4E sections 25, 34-36 T13N R5E sections 15-22, 26-36 3. Conclusion 3 of Area Injection Order 18B states that there are no underground sources of drinking water beneath the permafrost in the Colville River Unit area. The area affected by Area Injection Order 18B includes only three sections common to the proposed Fiord Oil Pool, Sections 13, 14, and 15 ofT12N, R5E, UM. Additional work should be done to support CPAI' s recommended finding of no potential USDWs within the proposed affected area. The Fiord 1, Fiord 4, Fiord 5 and Nigliq 1 exploratory wells in and around this area all have shallow openhole well logs. Please perform TDS calculations on these wells to determine presence of shallow aquifers and distribution of salinity within them. Please provide those results to the Commission. In connection with the Alpine Oil Pool expansion and its associated Area Injection Order (AIO), the AOGCC concluded that there are no underground sources of drinking water beneath the permafrost in the Colville River Unit Area (Area Injection Order No. 18B October 7,2004 Conclusion 3). However, the operator's application for the Alpine AIO (October 19, 1999) shows the CRUA did not include part of the proposed affected area for the Fiord Oil Pool. The TDS calculations will be provided to Mr. Steve Davies under separate cover. 4. Please provide a more detailed lithologic description of the Nechelik zone (grain size range, any cementation, and the presence of clay or other minerals that may affect reservoir performance). The Nechelik sandstone is lower fine-grained, quartz-rich, with 10-30% detrital matrix. Detrital matrix decreases up section in the coarsening upward sequence. The detrital matrix consists predominantly of clay minerals with local patches replaced by siderite cement. Mixed layer illite/smectite (7%), discrete illite (5%), and kaolinite (5%) are the main clays present in the matrix. The mixed layer illite/smectite consists of mostly illite with 20-30% smectite layers. Clay swelling is not expected to be significant based on experience with similar clays in the Alpine field and Nechelik core flood studies. Sandstone cementation is localized and patchy based on existing well and core control. 5. Please provide simplified, legible structure maps for the Kuparuk and the Nechelik zones for the public record? Please provide a "blob" map showing the approximate outline of the oil accumulations. Figures 2 and 3 respectively show the Nechelik and Kuparuk structure maps. Figure 4 shows a reservoir outline map. 6. In section 3.1 of the conservation order application on page 8, the type log presented for annual disposal is from Bergschrund No.1. On page 9, a north- ConocoPhillips Alaska, Inc. Page 2 of 11 Fiord Conservation Order & .Injection Order Supplemental Information . January 11, 2006 south cross section is presented that extends from Fiord to Nanuq. Bergschrund No. 1 is not on this cross section. Please reconcile this. The Fiord-to-Nanuq cross section was made with wells located on permanent pads (with actual annular injection) with shallow logs where available and was provided to demonstrate the continuity of the disposal interval over most of the CRU. Figure 5 shows a locator map of the cross section at the C30 marker and the Bergschrund No. 1 used for the type log. Figure 6 shows the cross section. 7. Original reservoir pressure is mentioned for the Nechelik reservoir, but no pressure information is presented for the Kuparuk. Is there any information on Kuparuk reservoir pressure from exploratory wells in the Fiord area? Kuparuk reservoir pressure was measured with a Repeat Formation Tester in the Fiord 5 PB1 well to be 3144 psig at 6762 feet subsea. Figure 7 shows pressure- depth data for measurements in the Fiord area. 8. What is the temperature of the reservoir? The reservoir temperature is 163°F at the proposed datum of 6850 feet subsea. 9. What is the minimum miscibility pressure of the reservoir? Simulated slim tube recovety results were used to design indicated a miscibility pressure of 2935 psia based on the post-2006 miscible injectant (MI) composition. 10. Were slim tube simulations conducted to show that proposed MI is miscible with Fiord crude oil? If so, what were the results? See response number 9. 11. If MI composition varies how will expected minimum miscibility pressure vary? (Please state the expected pressure range). The MI composition variation is expected to yield a miscibility pressure variation of 2400 to 3200 psi. 12. Page 14 of the AIO application mentions adding scale inhibitors. The application contains no statements about compatibility of seawater or produced water from other CRU oil pools with the proposed Fiord Oil Pool. Produced water from other CRU pools and seawater with proper treatment are expected to be compatible with the Fiord Oil PooL 13. On page 13, a waiver to the requirement of200-foot packer to perforation separation is requested. However, in the conservation order application, on page 10, section 3.2 it is stated that the angles of the well bores at the packer should not prevent wire line access. Please reconcile this. The tangent (sail) angles noted in section 3.2, page 10 refer to the long intermediate hole section drilled to the lower kick-off point (Figure 8). This angle must be 65 degrees or less to ensure wirellne access to the packer. Additional footage beyond the lower kick-off depth is drilled for "landing the well" horizontally into the target reservoir before running production casing. This interval involves increasing wellbore inclination up to 90 degrees and changing wellbore azimuth, which requires more than 200 feet measured depth to achieve, thus the waiver request to 20 AAC 25.412b (packer placed within 200 feet measured depth above the perforations). ConocoPhillips Alaska, Inc. Page 3 of 11 Fiord Conservation Order & .Injection Order Supplemental Infonnation . January 11, 2006 14. On page 20, area of review, six wells are identified, however, there are a total of8 penetrations due to sidetracks. While the wells are identified and completion reports are attached to the application, no "report" on the condition of the wells has been provided as required by the regulations. Six abandoned wells penetrate the proposed injection zones within ~ mile of the injection area: Fiord #1, Fiord #2, Fiord #4, Fiord #5, Nlgllq #1, and Nechelik #1. Two of these wells, Fiord #5 and Nigliq #1 have two penetrations each: the original branch and an openhole sidetrack from the intermediate hole below the surface casing. All penetrations associated with these six wells have been abandoned. Three new wells were drilled in early 2005 to develop the Nechelik zone: CD3-10B was completed as primarily a Nechelik horizontal injector with a thin Kuparuk sand open at the toe; CD3-109 and CD3-110 were drilled into the Nechellk zone where production casing was set and cemented above the Kuparuk zone. Review of the well files Indiates the mechanical condition of each penetration in the proposed Fiord 011 Pool Is as follows: Fiord #1 - Properly plugged and abandoned Fiord #2 - Properly plugged and abandoned Fiord #4 - Properly plugged and abandoned Fiord #5 (sidetrack from original branch) - Properly plugged and abandoned Fiord #5 PB1 (original well branch) - Properly Plugged original well branch with openhole plug Nigliq #1A - Plugged original well branch with openhole cement plug Nigliq #1 (sidetrack from original branch) - Properly plugged and abandoned Nechelik #1 - Properly plugged and abandoned CD3-10B - Completed with good mechanical integrity test CD3-109 - Shutdown after cementing and testing production casing pending drill out of production hole and completion, secured with good casing pressure test CD3-110- Shutdown after cementing and testing production casing pending drill out of production hole and completion, secured with good casing pressure test ConocoPhillips Alaska, Inc. Page 4 of 11 Developable Fiord Reservoir Area ~ I Colville Ri.ver Uniit --l J I Colville River Unit II ~ ,,1 I A CD3·108 j ¡ BERGSCHRlJND 1 TYPE LOG ALPINE 1 NANUK 1 þ¡ CD3 CD3-108 CD1 CD1-22 .. Fiord Cønservation Qrder & Area Injectiøn Order Supplemental Information January II, 2006 Fiord Formation Pressures 6600 tJ ~ 6700 6800 ~ 6900 - Q.. CJ.) c 7000 «I CJ.) IJ) -g 7100 (f) .. 7200 7300 7400 3100 3150 3200 3300 Pressure (PSIA) 3350 3400 Figure 7 Fiord Pressure ~ Depth Data 8 Upper Kick off point Tangent or sailsedion (up to 65· inclination) Top of reservQir Lower kick off au'" .,,¿. 65· to +1- 90· '" ~ Horizontal drilled in reservoir FigureS Fiord Well - Vertical Profile ConocoPhillips Alaska, Inc. #5 [Fwd: Re: [CRU: Fiord Pool Rules]] e e Subject: [Fwd: Re: [CRU: Fiord Pool Rules]] From: John Norman <john_norman@admin.state.ak.us> Date: Fri, 17 Mar 2006 17:21 :33 -0900 To: Jody J Colombie <jody_colombie@admin.state.ak.us> print for public inquiry file -------- Original Message -------- Subject:Re: [CRU: Fiord Pool Rules] Date:Fri, 17 Mar 2006 12:24:35 -0900 From:Stephen Davies <steve davies@admin.state.ak.us> Organization:State of Alaska To:Alfred James <aiiii88@hotmail.com> References:<BA Yl 0 I-F134 7701 OAI41239914BFD9ADEDO@phx.gbl> Dear Mr. James, <>According to the Alaska DNR's land records, the working interest owners in Tracts 113 and 115 are ConocoPhillips (78%) and Anadarko (22%). It is my understanding that you have an over-riding royalty interest in these two tracts. As you know, both of these tracts lie offshore, within lease ADL 388527, and inside of the second expansion of the Colville River Unit (see http://www.dog.dnr.state.ak.us/oil/programs/unitsI2002/CRU 2ndEXP finalF&D 11.08.02.pdf). Both ConocoPhillips and Anadarko have approved the Colville River Unit Agreement and the Colville River Unit Operating Agreement. ConocoPhillips, as Unit Operator, has two proposed wells near Tracts 113 and 115: CRU CD3-111 and CRU CD3-112. Public information concerning these wells has been published in the Commission's Weekly Drilling Report for March 5, 2005 and the Monthly Drilling Report for February 2006, available on the Internet at http://www.state.ak.us/local/akpages/ADMIN/ogcldrilling/dindex.htm. Both of these wells will lie inside the Colville River Unit and their closest approach to the Colville River Unit boundary will be about 1/2 mile. <> As proposed, CRU CD3-111 and CRU CD3-112 will conform to the 500-foot setback specified in State of Alaska regulation 20 AAC 25.055 (a)(I). Set-back requirements established by regulation 20 AAC 25.055 are based on property lines where ownership and landownership change. As defined in AS 31.05.170, neither of the terms "owner" or "landowner" encompass over-riding royalty interest owners. If anyone has concerns about correlative rights, the first step is always to address those concerns with the Unit Operator. Sincerely, Steve Davies Petroleum Geologist AOGCC 907-793-1224 Alfred James wrote: 1 of3 3/20/2006 9:32 AM [Fwd: Re: [CRU: Fiord Pool Rules]] e e Steve: I note in AS 31.05.110 ( Unitization and protection of correlative rights of owners), sec.(b)( 4) provides for commission order to create a unit to protect, safeguard, and adjust respective rights and obligations of the several perons affected including royalty owners, overriding royalty owners, oil & gas payments, carried interests, mortgages, lien claimants, and others, as well as the lessees. Looks like that might include us...if data supports it...right? Thanks, Fred James From: Stephen Davies <steve davies{á?admin.state.ak.us> To: aiiii88{á?hotmail.com CC: bodarrah{á?onemain.com Subject: Re: [CRU: Fiord Pool Rules] Date: Thu, 09 Mar 200616:31:47 -0900 Dear Mr. James, The Fiord Pool Rules are in progress, and are expected to be published in the next few weeks. As the Commission processes each permit to drill application, our staff closely monitors proposed well trajectories to ensure correlative rights are protected. Recently, permits to drill have been issued for wells CRU CD3-111 and CRU CD3-112. These proposed wells lie within the boundaries ofthe Colville River Unit and conform to the property line set-back requirements established by regulation 20 AAC 25.055. The term property line referenced in this regulation denotes a change in ownership and landownership, terms that are defined in section AS 31.05.170 of the Alaska Statutes. Commission regulations are available on line at http://www.aogcc.alaska.gov, and Alaska's oil and gas statutes and definitions can be found on line at http://www.legis.state.ak.us/cgi-bin/folioisa.dll/stattx05/query=* /doc/ {tI3188}? Reporting requirements are specified in regulation 20 AAC 25.537. Accordingly, the Commission makes the following information available to the public: 20f3 3/20/20069:32 AM [Fwd: Re: [CRU: Fiord Pool Rules]] e - surface and proposed bottom-hole location for a well after approval of the Permit to Drill; total depth, bottom-hole location, and status after the Well Completion or Recompletion Report and Log is filed; regular production data and reports; and regular injection data and reports. All other data and logs are held confidential by the Commission for 25 months from the date of completion, suspension or abandonment of a well. During this period, the Commission cannot release any confidential data unless the operator gives written and unrestricted permission to release all of the reports and information at an earlier date. You must discuss your request for confidential data directly with the operator. Please let me know if you have any additional questions, and please refer all inquires on this matter to me. Sincerely, Steve Davies Petroleum Geologist Alaska Oil and Gas Conservation Commission (907) 793-1224 John K. Norman <John Norman(â}admin.state.us> Chairman Alaska Oil & Gas Conservation Commission 30f3 3/20/2006 9:32 AM Lt<wa: KJ::: t<lOra 1'001 Kules - surveillance report ana pressure mOnItonngJ e iI¡f; e Subject: [Fwd: RE: Fiord Pool Rules - surveillance report and pressure monitoring] From: Jane Williamson <jane _ williamson@admin.state.ak.us> Date: rue, 14 Feb 2006 10:03:37 -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 Fiord CO file. -------- Original Message -------- RE: Fiord Pool Rules - surveillance report and pressure monitoring Tue, 10 Jan 2006 17:43:00 -0900 Walker, Jack A <Jack.A.Walker@conocophillips.com> Jane Williamson <jane wi1liamson@admin.state.ak.us> Subject: Date: From: To: It's probably best to have the same deadline for the pools; April 1 is fine. We tend to work those types of things at the same time, and one deadline will be more manageable. I really like the Prudhoe approach on pressure reporting and would prefer to have the annual report requirement in lieu of the 10-412 for Fiord - that's just one less administrative amendment for us to request and for the commission to decide. Thanks, Jack -----Original Message----- From: Jane Williamson [mailto:jane williamson@admin.state.ak.us] Sent: Tuesday, January 10, 2006 5:33 P~ To: Walker, Jack A Subject: Fiord Pool Rules - surveillance report and pressure monitoring Jack, We will require an annual surveillance report for Fiord as we have in all pools. We currently specify no later than April 1 for Colville pools. Is this deadline ok for you? In Prudhoe we're eliminating the use of the 10-412 form for reservoir pressure monitoring and instead use the surveillance report for reporting reservoir pressures. If this is preferable for you, I can write the rule that way for Fiord, and we can later administratively amend the Alpine and Nanuq rules to be consistent. It works either way for us but since you're required to report reservoir pressures within the surveillance report anyway, I just thought it might minimize your paperwork. Jane Jane Williamson, PE ~iane williamson(a?admin.state.ak.us> Reservoir Engineer Alaska Oil and Gas Conservation Commission of 1 2/22/2006 10:43 AM l' lord heanng e e Subject: Fiord hearing From: Jane Williamson <jane_williamson@admin.state.ak.us> Date: Fri, 13 Jan 2006 16:27:29 -0900 To: John Norman <john_norman@admin.state.ak.us>, Dan T Seamount <dan _ seamount@admin.state.ak.us>, Cathy P Foerster <cathy _ foerster@admin.state.ak.us> CC: Thomas E Maunder <tom_maunder@admin.state.ak.us>, Stephen F Davies <steve_davies@admin.state.ak.us>, Jody J Colombie <jody_colombie@admin.state.ak.us> I spoke with Mike Kotowski concerning Fiord. They are planning to go for 2 PAs but there has been no application. He doesn't see that there is a problem, however, with one pool. So, I think we can vacate the hearing, if you haven't already. Jane Williamson, PE <jane williamson(a?admin.state.ak.us> Reservoir Engineer Alaska Oil and Gas Conservation Commission of 1 1!l5/2006 4:18 PM e e Subject: TDS Calculations in Fiord Area From: "Walker, Jack A" <Jack.A.Walker@conocophillips.com> Date: Thu, 12 Jan 2006 13:57:02 -0900 To: Stephen Davies <steve_davies@admin.state.ak.us> CC: "Campaign, Wayne" <Wayne.Campaign@conocophillips.com>, "Knock, Douglas G" <doug.knock@conocophillips.com> Steve, Enclosed MS Word file is a summary report of Fiord TDS calculations for Nigliq 1, Fiord 1, Fiord 4, and Fiord 5. Also enclosed are compressed pdf files showing log displays for those wells. Also attached is a report referenced in the Fiord summary report. I expect to have a paper copy of this same report delivered to you today. If you have questions regarding the TDS calculations, please call Wayne Campaign at 265-1505. If you have any other questions regarding the proposed Fiord CO and AIO, please call me any time. Thanks, Jack Walker ConocoPhillips Alaska, Inc. North Slope Development 265-6268 «Fiord Shallow Salinities.doc» «Shallow SalinitLreference.zip» «Fiord1_Salinity.pdf.zip» «Fiord4_ Salinity. pdf.zip» «Fiord5pb _Salinity. pdf.zip» «Nig 1_ Salinity.pdf.zip» Content-Description: Fiord Shallow Salinities.doc Fiord Shallow Salinities.doc Content-Type: applicationlmsword Content-Encoding: base64 Content-Description: Shallow Salinity Jeference.zip Shallow Salinity Jeference.zip Content-Type: applicationlx-zip-compressed Content-Encoding: base64 Content-Description: Fiord1_ Salinity. pdf.zip Fiordl_ Salinity .pdf.zip Content- Type: applicationlx~zip-compressed Content-Encoding: base64 Content-Description: Fiord4 _ Salinity.pdf.zip Fiord4 _Salinity .pdf.zip Content-Type: applicationlx -zip-compressed Content-Encoding: base64 Content- Description: Fiord5pb _ Salinity.pdf. zip Fiord5pb _Salinity .pdf.zip Content-Type: applicationlx -zip-compressed Content-Encoding: base64 e e Content-Description: Nigl_ Salinity.pdf.zip Nigl_SaJinity.pdf.zip Content-Type: application/x-zip-compressed Content-Encoding: base64 Ke: 1-' lOrd Heanng e e Subject: Re: Fiord Hearing From: Jody Colombie <jody _ colombie@admin.state.ak.us> Date: Tue, 10 Jan 200609:48:10 -0900 To: "Walker, Jack A" <Jack.A.Walker@conocophillips.com> Jack, No one has requested a hearing. Jody Colombie Walker, Jack A wrote: Hi Jody! Has anyone requested a hearing on the proposed Fiord Oil Pool? Hearing tentatively is scheduled for January 19. Jack Walker ConocoPhillips Alaska, Inc. North Slope Development 265-6268 of 1 1/10/2006 11 :31 AM Re: [Fwd: RE: [FWd:[FWd:PUbliC_APPlication_'-iOrd_CO_and_A... e Subject: Re: [Fwd: RE: [Fwd: [Fwd:Public_Application_for_Fiord_CO _and_AIO.pdf1]]--#2 From: Rob Mintz <robert_mintz@law.state.ak.us> Date: Tue, 03 Jan 2006 15:18:55 -0900 To: cathy _foerster@admin.state.ak.us cc: dan_seamount@admin.state.ak.us, jody _colombie@admin.state.ak.us, john_ norman@admin.state.ak.us, steve _ davies@admin.state.ak.us, tom_ maunder@admin.state.ak.us I didn't realize that this is only an override. Yes, that makes my point and your point even stronger. Cathy Foerster <cathy foerster@admin.state.ak.us> 1/3/2006 3:13:07 PM »> Since AVCG is concerned about property for which they only have an override, shouldn't they be talking with the operator of the property first? I would think that the matter would be between them and the operator. In other words, they should learn what the operator think sabout the acreage? If he's concerned that it's being drained, then he should drill a well. If he's not concerned, he should calm his royalty owners down. I don't think we have any place at this table. And we certainly shouldn't be giving confidential info to these folks. Rob Mintz wrote: Is he aware that redetermination proceedings do not involve the AOGCC? If there were an adjudicatory proceeding before the AOGCC and he had anaffected property interest, he might well have the right to access relevant confidential information, subject to a protective order orconfidentiality agreement. Otherwise, I would think he would need toget the information from the other working interest owners or obtaintheir consent to get confidential data from us. Thomas Maunder <tom maunder@admin.state.ak.us> 1/3/2006 2:56:11 PM All,Here is companion message from Mr. James regarding his minor interest in the Fiord area. He is not calling for a hearing, but he is making arequest for access to confidential information relative to "histracts".Rob, any words of wisdom?Tom-------- Original Message -------- Subject: RE: [Fwd: [Fwd:Public Application for Fiord CO and AIO.pdf]]Date: Tue, 03 Jan 200617:26:39 -0600From:-Alfred James- - <ajiii88@hotmail.com>To:tom maunder@admin.state.ak.usCC: bodarrah@onemain.com Dear Tom, Steve: Thank you for sending the Fiord app. materials. AVCG and I each have ORI's in this app. area, close to recent drilling, details of which we have not seen. Mr. Darrah is in ANC and has spokenwith Mr. Norman requesting such information. He and I feel theredetermination process over the next years ought to protect correlativerights of offset lease owners. At this point, I do not have thenecessary information to formally request a hearing and so waive it. Ido, however, also request information relative to our interest in tractsin the rules and PA area, and will be amenable to signing aconfidentiality agreement if necessary. Alfred James III, Pingo O&GLP>From: Thomas Maunder ~~om maunder@admin.state.ak.us»To: Alfred James<ajiii88@hotmail.com>, Bo Darrah <bodarrah@onemain.com»Subject: [Fwd: [Fwd: Public Application for Fiord CO and AIO.pdf]]>Date: Tue, 03 Jan2006 10:40:48 -0900»»»»>Mr. James and Mr. Darrah,»As I indicated inmy earlier message, here is the pdf file of CPAl's>applications.»Pleasecontact Ms. Jody Colombie, the Commissioners' Special Assistant>at793-1221 with further questions.»Tom Maunder, PE»AOGCC»»--------Original Message --------»» Subject:> [Fwd:Public Application for Fiord CO and AlO.pdf]»> Date:> Tue,03 Jan 2006 10:10:36--0900»> - - From:> Stephen Davies<steve davies@admin.state.ak.us»» Organization:» Stateof Alaska»> To:> Tom Maunder<tom maunder@admin.state.ak.us»»»»»>-------- Original {)f7 1/5/20064:08 PM Re: [Fwd: RE: [Fwd: [FWd:PUbliC_APPlication_+.iord_co_and_A... e Message-------->Subject: Public Application for Fiord CO and AIO.pdf>Date: Thu, 15Dec 2005 16:26:45 -0900>From: Scephen - - - Davies<steve davies@admin.state.ak.us»Organization: State ofAlaska>To: knelson@petroleumnews.com>CC: Jody Colombie<jody cOlombie@admin.state.ak.us»»>Kristen,»Apologies for takingso long to get this to you today.»Attached is a "pdf" file of thecombined applications for the Fiord>conservation order and areainjection order. There were some documents>included within the originalapplication that were not marked>confidential, and I am concerned that the operator wouldn't want them>released to the public. What I amproviding you is the bulk of both>applications, but I have removed pagesconcerning computer modeling of>reservoir fracture and reports relatedto recent, confidential wells.>Information for the older Fiord, Nechelikand Nigliq exploration wells>have been released to the publicdomain.»Please read through the application, and if for some reason, you need>the sections that I removed, let me know and we will discussreleasing>them with the operator.»Thanks,»Steve Davles»»»»>«rublic_Applicatlon for Fiord_CO and_AlO.pdf » of2 1/5/2006 4:08 PM Ke: ltwa: Kt: ltwa: It'wa:t'ubllc ApplicatIOn' tlora LU ana ... -e - - - e Subject: Re: [Fwd: RE: [Fwd: [Fwd:Public_Application_for_Fiord_CO_and_AIO.pdfj]]--#2 From: Cathy Foerster <cathy_foerster@admin.state.ak.us> Date: rue, 03 Jan 2006 15:13:07 -0900 To: Rob Mintz <robert_mintz@law.state.ak.us> CC: dan_seamount@admin.state.ak.us, john _ norman@admin.state.ak.us, tom _ maunder@admin.state.ak.us, jody _ colombie@admin.state.ak.us, steve _ davies@admin.state.ak.us Since A VCG is concerned about property for which they only have an override, shouldn't they be talking with the operator of the property first? I would think that the matter would be between them and the operator. In other words, they should learn what the operator think sabout the acreage? If he's concerned that it's being drained, then he should drill a well. If he's not concerned, he should calm his royalty owners down. I don't think we have any place at this table. And we certainly shouldn't be giving confidential info to these folks. Rob Mintz wrote: Is he aware that redetermination proceedings do not involve the AOGCC? If there were an adjudicatory proceeding before the AOGCC and he had an affected property interest, he might well have the right to access relevant confidential information, subject to a protective order or confidentiality agreement. Otherwise, I would think he would need to get the information from the other working interest owners or obtain their consent to get confidential data from us. Thomas Maunder <tom maunder@admin.state.ak.us> 1/3/2006 2:56:11 PM All, Here is companion message from Mr. James regarding his minor interest in the Fiord area. He is not calling for a hearing, but he is making a request for access to confidential information relative to "his tracts". Rob, any words of wisdom? Tom -------- Original [vIes sage -------- Subj ect: RE: [Fwd: [Fwd: Public_Application_for_Fiord_CO_and_AIO.pdfJ]Date: Tue, 03 Jan 2006 17:26:39 -0600From: Alfred James <ajiii88@hotmail.com>To: tom maunder@admin.state.ak.usCC: bodarrah@onemain.com Dear Tom, Steve: Thank you for sending the Fiord app. materials. AVCG and I each have ORI's in this app. area, close to recent drilling, details of which we have not seen. Mr. Darrah is in ANC and has spoken with Mr. Norman requesting such information. He and I feel the redetermination process over the next years ought to protect correlative rights of offset lease owners. At this point, I do not have the necessary information to formally request a hearing and so waive it. I do, however, also request information relative to our interest in tracts in the rules and PA area, and will be amenable to signing a confidentiality agreement if necessary. Alfred James III, Pingo O&G LP>From: Thomas Maunder <tom maunder@admin.state.ak.us»To: Alfred James of2 1/4/2006 10:49 AM Re: [Fwd: RE: [Fwd: [Fwd:Public_Application eFiord_co_and_... e <ajiii88@hotmail.com>, Bo Darrah <bodarrah@onemain.com»Subject: [Fwd: [Fwd: Public Application for Fiord CO and AlO.pdf]]>Date: Tue, 03 Jan 2006 10:40:48 -0900»»»»>Mr. James-and-Mr. Darrah,»As I indicated in my earlier message, here is the pdf file of CPAl's>applications.»Please contact Ms. Jody Colombie, the Commissioners' Special Assistant>ac 793-1221 with further questions.»Tom Maunder, PE»AOGCC»»-------- Original Message --------»» Subject:> [Fwd: Public Application for Fiord CO and AlO.pdf]»> Date:> Tue, 03 Jan-2006 10:10:36 -0900»> - -From:> Stephen Davies <steve davies@admin.state.ak.us»» Organization:» State of Alaska»> To:> Tom Maunder <tom maunder@admin.state.ak.us»»»»»>-------- Original Message -------->Subject: Public Application for Fiord CO and AlO.pdf>Date: Thu, 15 Dec 2005 16:26:45 -0900>From: - Stephen-DavIes <steve davies@admin.state.ak.us»Organization: State of Alaska>To: knelson@petroleumnews.com>CC: Jody Colombie <jody colombie@admin.state.ak.us»»>Kristen,»Apologies for taking so long to get this to you today.»Attached is a "pdf" file of the combined applications for the Fiord>conservation order and area injection order. There were some documents>included within the original application that were not marked>confidential, and I am concerned that the operator wouldn't want them>released to the public. What I am providing you is the bulk of both>applications, but I have removed pages concerning computer modeling of>reservoir fracture and reports related to recent, confidential wells.>lnformation for the older Fiord, Nechelik and Nigliq exploration wells>have been released to the public domain.»Please read through the application, and if for some reason, you need>the sections that I removed, let me know and we will discuss releasing>them with the operator.»Thanks,»Steve Davies»»»»>« Public_Application for_fiord_CO and_AlO.pdf » Cathy Foerster Commissioner Alaska Oil and Gas Conselvdtiol1 Commission 20f2 1/4/2006 10:49 AM ltwa: Kt: ltwa: ltwa: PUbliC_AppliCatiOn_tor "lOrCl_LU_anCl_AIU... e e Subject: [Fwd: RE: [Fwd: [Fwd: Public_Application_for_Fiord_CO_and_AIO.pdf]]]--#2 From: Thomas Maunder <tom_maunder@admin.state.ak.us> Date: Tue, 03 Jan 2006 14:56:11 -0900 To: John Norman <john_norman@admin.state.ak.us>, Daniel T Seamount JR <dan _ seamount@admin.state.ak.us>, Cathy Foerster <cathy ~ foerster@admin.state.ak.us>, Robert Mintz <robert _mintz@law.state.ak.us> CC: Jody J Colombie <jody _ colombie@admin.state.ak.us>, Steve Davies <steve _ davies@admin.state.ak.us> All, Here is companion message from Mr. James regarding his minor interest in the Fiord area. He is not calling for a hearing, but he is making a request for access to confidential information relative to "his tracts" . Rob, any words of wisdom? Tom -------- Original Message -------- Subject:RE: [Fwd: [Fwd: Public_Application_for_Fiord_CO_and_AIO.pdf]] Date:Tue, 03 Jan 2006 17:26:39 -0600 From:Alfred James <ajiii88~hotmail.com> T û :tOt11 maunder(â}admin.state.ak. us CC: bodarrah(í~UlleD1ain.com Dear Torn, Steve: Thank you for sending ~;:o. Fiord app. materials. AVCG and I each have ORI's in this app. area, close to r¿~~~t drilling, details of which we have not seen. Mr. Darrah is in ANC and has Spu~2~ with Mr. Norman requesting such information. He and I feel the redetermination pr0~e~s over the next years ought to protect correlative rights of offset lease owners. At this point, I do not have the necessary information to formally request a hearing and so waive it. I do, however, also request information relative to our interest in tracts in the rules and PA area, and will be amenable to signing a confidentiality agreement if necessary. Alfred James III, Pingo O&G LP >From: Thomas Maunder <torn maunder@admin.state.ak.us> >To: Alfred James <ajiii88@hotn¡ail.com>, Bo Darrah <bodarrah@onemain.com> >Subject: [Fwd: [Fwd: Public_Application_for_Fiord_CO_and_AIO.pdfJJ >Date: Tue, 03 Jan 2006 10:40:48 -0900 > > > > > > > > >Mr. James and Mr. Darrah, > >As I indicated in my earlier message, here is the pdf file of CPAI's >applications. > >Please contact Ms. Jody Colombie, the Commissioners' Special Assistant >at 793-1221 with further questions. > of3 1/4/2006 10:48 AM Lrwu. ~. Lrwu. Lrwu: rUUIII.:_J-\pplIl.:i:lLLUn_1Ur "!UrU_L-U_anU_J-\lU... e It >Tom Maunder, PE > >AOGCC > > > >-------- Original Message -------- > > > > > > > > > > > > > > > > > > > > > > > > > > > > > > > >-------- Original Message -------- >Subject: Public Application for Fiord CO and AIO.pdf >Date: Thu, 15 Dec 2005 16:26:45 =0900 >From: Stephen Davies <steve davies@admin.state.ak.us> >Organization: State of Alaska >To: knelson@petroleumnews.com >CC: Jody Colombie <jody colombie@admin.state.ak.us> > > > >Kristen, > >Apo10gies for taking so long to get this to you today. > >Attached is a "pdf" file of the combined applications for the Fiord >conservation order and area injection order. There were some documents >included within the original application that were not marked >confidential, and I am concerned that the operator wouldn't want them >released to the public. What I am providing you is the bulk of both >applications, but I have removed pages concerning computer modeling of >reservoir fracture and reports related to recent, confidential wells. >Information for the older Fiord, Nechelik and Nigliq exploration wells >have been released to the public domain. > >Please read through the application, and if for some reason, you need >the sections that I removed, let me know and we will discuss releasing >them with the operator. > >Thanks, Subject: [Fwd: Public_Application_for_Fiord_CO_and_AIO.pdf] Date: Tue, 03 Jan 2006 10:10:36 -0900 From: Stephen Davies <steve davies@admin.state.ak.us> Organization: State of Alaska To: Torn Maunder <torn maunder@admin.state.ak.us> ~ of3 1/4/2006 10:48 AM lrwu; Kt; lrwu; lrwu: t'UDIlC_AppIlCanOn_IOr I'JQro_,",V_anO_AlV... It e > >Steve Davies > > > > > > > > >« Public_Application_for Fiord_CO and_AIO.pdf » 3 of3 1/4/2006 10:48 AM [r WU. l'.£. [r WU. [r WU.rUUlll; _1-\.fJfJlI\.:ällUIl_1U! _ r" 'I U_ L,V _ ällU _ 1-\.lV.... e e Subject: [Fwd: RE: [Fwd: [Fwd:Public_Application_for_Fiord_CO_and_AIO.pdf]]]--#2 From: Rob Mintz <robert_mintz@law.state.ak.us> Date: Tue, 03 Jan 2006 14:59:58 -0900 To: cathy _ foerster@admin.state.ak.us, dan _ seamount@admin.state.ak.us, john _ norman@admin.state.ak.us, tom _ maunder@admin.state.ak.us CC: jody _ colombie@admin.state.ak.us, steve_davies@admin.state.ak.us Is he aware that redetermination proceedings do not involve the AOGCC? If there were an adjudicatory proceeding before the AOGCC and he had an affected property interest, he might well have the right to access relevant confidential information, subject to a protective order or confidentiality agreement. Otherwise, I would think he would need to get the information from the other working interest owners or obtain their consent to get confidential data from us. Thomas Maunder <tom maunder@admin.state.ak.us> 1/3/2006 2:56:11 PM All, Here is companion message from Mr. James regarding his minor interest in the Fiord area. He is not calling for a hearing, but he is making a request for access to confidential information relative to "his tracts". Rob, any words of wisdom? Tom -------- Original Message -------- Subj ect: RE: [t'rJd: [F',.¡d: Public Application for Fiord CO and AIO.pdf]]Date: Tue, 03 Jan 2006 17:26:39 -0600From: Alfred James <aJiii88@hotmail.com>To: tom maunder@admin.state.ak.usCC: bodarrah@onemain.com Dear Tom, Steve: Thank you for sending the Fiord app. materials. AVCG and I each have ORI's in this app. area, close to recent drilling, details of which we have not seen. Mr. Darrah is in ANC and has spoken with Mr. Norman requesting such information. He and I feel the redetermination process over the next years ough~ to protect correlative rights of offset lease owners. At this point, I do not have the necessary information to formally request a hearing and so waive it. I do, however, also request information relative to our interest in tracts in the rules and PA area, and will be amenable to signing a confidentiality agreement if necessary. Alfred James III, Pingo O&G LP>From: Thomas Maunder <tom maunder@admin.sta~e.ak.us»To: Alfred James <ajiii88@hotmail.com>, 80 Darrah <bodarrah@onemain.com»Subject: [Fwd: [Fwd: Public Application for Fiord CO and AIO.pdf]]>Date: Tue, 03 Jan 2006 10:40:48 -0900»»»»>Mr. James-and-Mr. Darrah,»As I indicated in my earlier message, here is the pdf file of CPAI's>applications.»Please contact Ms. Jody Colombie, the Commissioners' Special Assistant>at 793-1221 with further questions.»Tom Maunder, PE»AOGCC»»-------- Original Message --------»» Subject:> [Fwd: Public Application for Fiord CO and AIO.pdf]»> Date:> Tue, 03 Jan-2006 10:10:36 -0900»> - -From:> Stephen Davies <steve davies@admin.state.ak.us»» Organization:» State of Alaska»> To:> Tom Maunder <tom maunder@admin.state.ak.us»»»»»>-------- Original Message -------->Subject: Public Application for Fiord CO and AIO.pdf>Date: Thu, 15 Dec 2005 16:26:45 -0900>From: - Stephen-DavIes <steve davies@admin.state.ak.us»Organization: State of Alaska>To: knelson@petroleumnews.com>CC: Jody Colombie <jody colombie@admin.state.ak.us»»>Kristen,»Apologies for taking so long to get this to you today.»Attached is a "pdf" file of the combined applications for the Fiord>conservation order and area injection order. There were some documents>included within the original application that were not marked>confidential, and I am concerned that of2 1/4/2006 10:48 AM It'Wd: Kl::,: ltwd: ltWd:PUblIC ApplICatlOn tor' ^'ra LU and A1U.... - - -e - - - e the operator wouldn't want them>released to the public. What I am providing you is the bulk of both>applications, but I have removed pages concerning computer modeling of>reservoir fracture and reports related to recent, confidential wells.>Information for the older Fiord, Nechelik and Nigliq exploration wells>have been released to the public domain.»Please read through the application, and if for some reason, you need>the sections that I removed, let me know and we will discuss releasing>them with the operator.»Thanks,»Steve Davies»»»»>« Public_Application_for_Fiord_co_and_AIO.pdf » of2 1/4/2006 10:48 AM l' WU. ,"-'-'. l'·WU. l'-WU. rUU1I\. 11.pplll.<1l1Vll 'UI !'IUIU ~V <111U 11.1V... - - e - - - e Subject: [Fwd: RE: [Fwd: [Fwd: Public_Application_for_Fiord_CO_and_AIO.pdt]]]--#l From: Thomas Maunder <tom_maunder@admin.state.ak.us> Date: Tue, 03 Jan 2006 14:48:33 -0900 To: John Norman <john_norman@admin.state.ak.us>, Daniel T Seamount JR <dan _ seamount@admin.state.ak.us>, Cathy Foerster <cathy _ foerster@admin.state.ak.us> CC: jody J Colombie <jody _colombie@admin.state.ak.us> All, Here Mr. Darrah's reply to our conversation this morning and his receipt of the CP AI applications. It appears that his concern is satisfied. Tom -------- Original Message -------- Subject:RE: [Fwd: [Fwd: Public_Application_for_Fiord_CO_and_AIO.pdt]] Date:Tue, 03 Jan 2006 17:12:57 -0600 From:Bo Darrah <bodarrah~onemain.com> To:'Thomas Maunder' <tom maunder(a¿admin.state.ak.us> Tom. Thanks for this information I spoke with Mike Kolcawski some more about the "circle and tangent" method for determination of revenue sharing with in a PA, the method is the one used in the Colville River Unit. After that conversation, AVCG LLC is comfortable with our correlative right issues that I was discussing with you this morning. Bo Darrah From: Thomas Maunder [mailto:tom maunder@admin.state.ak.us] Sent: Tuesday, January 03, 2006 1:41 PM To: Alfred James; Bo Darrah Subject: [Fwd: [Fwd: Public_Application_forJiord_CO_and_AIO.pdf]] Mr. James and Mr. Darrah, As I indicated in my earlier message, here is the pdf file of CP AI's applications. Please contact Ms. J ody Colombie, the Commissioners' Special Assistant at 793-1221 with further questions. Tom Maunder, PE AOGCC -------- Original Message -------- Subject: [Fwd: Public _Application_for _Fiord_CO _ and _AIO.pdt] Date:Tue, 03 Jan 2006 10:10:36 -0900 From:Stephen Davies <steve davies(2ì!admin.state.ak.us> Organization:State of Alaska To:Tom Maunder <tom maunder(ã?admin.state.ak.us> of2 1/4/2006 10:49 AM r 1V1 U \...-V ällU ¡-\.IV \...-VllläLl e e Subject: Fiord CO and AIO Contact From: Thomas Maunder <tom_maunder@admin.state.ak.us> Date: Tue, 03 Jan 2006 11: 13 :00 -0900 To: John Norman <john_norman@admin.state.ak.us>, Daniel T Seamount JR <dan _ seamount@admin.state.ak.us>, Cathy Foerster <cathy _ foerster@admin.state.ak.us> CC: Jody J Colombie <jody_colombie@admin.state.ak.us> This is a note for the record. This morning I received a message from Mr. 80 Darrah (316-253-3097) requesting a return call with regard to CPAI's application for pool rules at Fiord in the Colville River Unit. I had previously been contacted by a Mr. Alfred James who owns an overriding interest in two leases proposed for inclusion in the PA. I referred Mr. James' question to Mike Kotoski at DNR since PA's are their purview and I gathered the CPAI applications to send him. Copies of the messages exchanged with Mr. James are in the file. When I returned Mr. Darrah's call, I learned he is an associate of Mr. James. They are concerned about the development or non-development of their leases and that due to regulatory well confidentiality requirements, they cannot gain access to CPAI's well information in a "timely" manner "to assure" their lease is or is not being drained. He is interested in protecting their correlative rights and wondered if that would be a matter for this hearing. I responded that correlative rights were the Commission's purview and if he felt he had an issue to raise that it was his option to request the hearing (by 4:30 pm today) or submit a written comment (by 4:30 pm, January 17). He wondered how his/their concerns would affect the final order. Would the Commission issue an order allowing them to examine new well information "within a few weeks" of drilling being completed? I responded that I could not predict how the Commissioners would ultimately rule on this or any matter, however they would properly consider any information presented. He continued attempting to draw a parallel between their lease/ORI issue and the Donkel case and the desire to avoid such. My response was that if he had concerns regarding his rights, the proper way to voice those concerns would be either to request the hearing or submit comTT1.e;--/t.:s. 'The cOllvcrsation then finished. Since then I have sent both Mr. JdffiCS and Mr. Darrah a pdf copy of the CPAI application. The document is the same previouslý sent to Ms. Kristin Nelson at Petroleum News by Steve Davies. I will keep you informed if I receive further contacts. Tom . of 1 1/3/2006 11:42 AM Ltwa: Ltwa: t'UDllC_AppllCanon_IOr_tlOra_ LU _ana_A1U.parJJ e e Mr. James and Mr. Darrah, As I indicated in my earlier message, here is the pdf file of CP AI's applications. Please contact Ms. Jody Colombie, the Commissioners' Special Assistant at 793-1221 with further questions. Tom Maunder, PE AOGCC -------- Original Message -------- Subject:[Fwd: Public_Application_for _Fiord_CO _and _ AIO.pdt] Date:Tue, 03 Jan 2006 10:10:36 -0900 From: Stephen Davies <steve davies(ã}admin.state.ak.us> Organization:State of Alaska To:Tom Maunder <tom maunder(~~admin.state.ak.us> -------- Original Message -------- Subject: Public_Application_for_Fiord_CO_and_AIO.pdf Date: Thu, 15 Dec 2005 16:26:45 -0900 From: Stephen Davies <steve davies@admin.state.ak.us> Org ani z at ion: S tat e 0 £..··-AI·a's1<a··Oho.--m........-................................... ............................................. .....n'_ To: knelson@petrol:::.~~~~.~~.§...:...q_?m CC: Jody Colofnbie <jody colombie@admin.state.ak.us> Kristen, Apologies for taking so long to get this to you today. Attached is a "pdf" file of the combined applications for the Fiord conservation order and area injection order. There were some documents included within the original application that were not marked confidential, and I am concerned that the operator wouldn't want them released to the public. What I am providing you is the bulk of both applications, but I have removed pages concerning computer modeling of reservoir fracture and reports related to recent, confidential wells. Information for the older Fiord, Nechelik and Nigliq exploration wells have been released to the public domain. Please read through the application, and if for some reason, you need the sections that I removed, let me know and we will discuss releasing them with the operator. Thanks, Steve Davies 10f2 1/3/200610:41 AM It'wa: It'wa: J:'UOllC _ AppllCanOn _ ror _t'lOra_ LU_ ana_A1U.parJJ e e Content-Type: applicationlpdf Public_Application_for_Fiord_ CO _and _AIO.pdf Content-Encoding: base64 20f2 1/3/2006 10:41 AM r lUlU .t\.PP¡¡l;dllU¡¡~-lVlt:~~dgt: l e e Mr. James and Mr. Darrah, Shortly, I will be sending you both a message containing CPAl's application for CO and AlO at Fiord. I am sending this message in advance in case the next one doesn't come through. The pdf file size is 3 meg. Please let me know if you have problems receiving the file. Tom Maunder, PE AOGCC -------- Original Message -------- Subject: Public_Application_for_Fiord_CO_and_AlO.pdf Date: Thu, 15 Dec 2005 16:26:45 -0900 From: Stephen Davies <steve davies@admin.state.ak.us> Organization: State of Alaska To: knelsoIJ.',CYpetrol.eumnews. COT, CC: Jody Colombie ejody colombíe@admin.stat:e.ak.us> Kristen, Apologies for taking so long to get this to you today. Attached is a "pdf" file of the combined applications for the Fiord conservation order and area injection order. There were some documents included within the original application that were not marked confidential, and I am concerned that the operator wouldn't want them released to the public. What I am providing you is the bulk of both applications, but I have removed pages concerning computer modeling of reservoir fracture and reports related to recent, confidential wells. I~for~Q~ìo~ f~r the ~l~er Fiord, Nechelik and Nigliq exploration wells have been released to the public domain. Please read through the application, and if for some reason, you need the sections that I removed, let me know and we will discuss releasing them with the operator. Thanks, Steve Davies 1 of 1 1/3/2006 10:41 AM .1.'-""'. .1 J.Vl U J.J.""'IU 1 un....;> e e Yes, Tom, I did get in touch with Mike, and he gave me good information, but said most of process is in hands of AOGCC. He said two tracts in which I own ORI are included in proposed PA (113, 115) so I will be interested in seeing whatever is not proprietary in the application. Thank you, and Happy New Year. Fred James From: Thomas Maunder <l:om 1Tlaunder@admin.sLate.ak.us> To: Alfred James::éJ:t.~~~?ªg¡}.1:'?!:!Tl9..!:J.::c::?rr:,>. Subject: Re: Fiord field rules Date: Fri, 30 Dec 2005 12:44:51 -0900 Mr. James, I did forward your message to Mike Kotoski at DNR. Have you received a reply?? I intend to scan and send copies of ConocoPhillips order applications to you, however I cannot physically access the files today since some of the staff are on leave. I should be able to get the documents scanned on Tuesday and I will email them to you. Thanks much. Best regards for the holidays. Call or message with any questions. Tom Maunder, PE AOGCC Alfred James wrote, On 12/27/2005 2:38 PM: This is in regard to lease ADL 388527, Colville River Unit tracts 112,113,115 in which I own, through my trust and partnership, an ORI. I am requesting lnfu£ffiatian as to the tracts to be included in the preliminary PA for Fiord pool, and any other informatiun "elative to the application that is not proprietary. Thank you. Alfred Jan~s III (Alfred James III Revocable Trust, Pingo Oil & Gas, LP) suite 525, 200 w. Douglas, Wichita, KS 67202, ph 3 16 2 6 7 7 592 , éJ:j.~.~~ª?~Þ:<::Ji::_rI1éJ:~.J.:.:.C:(?1!1 1 of 1 1/3/200610:01 AM 1'...e. r tvt u uetu t ute~ e e Hi Mike, We have noticed the Conservation and Area Injection Order hearing for 9 am January 19. Tom Mike Kotowski wrote, On 12/28/2005 1 :30 PM: Tom, When's the Public Hearing on this application? Mike K. -----Original Message----- From: Thomas Maunder [¡f:..éJ._~;_t::\:):.t::<?_\l1_Y11aunder@adm~:r!::_§~éJ.t::? .éJ.k. us] Sent: Wednesday, December 28, 2005 7:48 AM To: Michael D Kotowski Cc: Alfred James Subject: Re: Fiord field rules Mike, I got a call from this gentleman yesterday. I can copy CPAI's application and send it to him, however I don't have information regarding the PA. Can you help him or if not would you please forward on in DNR to someone who can? Call or message with any questions. Thanks, Tom Maunder, PE AOGCC Alfred James wrote, On 12/27/2005 2:38 PM: This is in regard to lease ADL 388527, Colville River Unit tracts 112,113,115 in which I own, through my trust and partnership, an ORI. I am requesting information as to the tracts to be included in the preliminary PA for Fiord pool, and any other information relative to the application that is not proprietary. Thank you. Alfred James III (Alfred James III Revocable Trust, Pingo Oil & Gas, LP) suite 525, 200 W. Douglas, Wichita, KS 67202, ph 316 267 7592, ajiii88@hotmail.com 1 of 1 1/3/2006 10:04 AM #4 Fiord Applications - Additional Questions from AOGCC . . Jack, Attached are questions compiled by AOGCC senior staff during review of the non-confidential portions of the Fiord applications. The Commission has tentatively scheduled a public hearing on these applications for January 19,2006 at 9:00 am. Your response to these questions five business days in advance ofthat meeting would be helpful. Thank you. Sincerely, Steve Davies Petroleum Geologist AOGCC 793-1224 Content-Type: application/msword 051220 _Fiord _ o iI_ Pool_Questions jor _ Operator.doc Content-Encoding: base64 1 of 1 3/13/200612:16 PM . . Fiord Oil Pool Conservation Order and Area Injection Order Applications Questions for Operator The following list of questions and comments was compiled during review of the non- confidential portion of CPAI' s applications to the Alaska Oil and Gas Conservation Commission for the Fiord Conservation and Area Injection Orders, Colville River Field, dated November 22,2005. Notice of Opportunity for Public Hearing has been submitted for publication in the Anchorage Daily News. Please provide responses to these questions and comments at least 5 working days prior to the tentative hearing date. 1. Please clarify the working interest ownership of Petro-Hunt in any leases within the affected area. Are there any other minor working interest owners within the affected area? Are Petro-Hunt and any other minor working interest owners agreeable to the current development plans? Are there any other ownership, surface ownership, or other issues outstanding concerning this development? 2. Sections 13, 14, and 15 ofT12N, R5E, UM are currently governed by AIO 18B (Alpine Oil Pool) over a portion of the affected interval. These sections overlap with the proposed affected area for Fiord. Does CP AI propose contracting these three sections from AIO 18B? If changes have been made to the proposed affected area for the Fiord applications, please provide an updated legal description to the Commission. 3. Conclusion 3 of Area Injection Order 18B states that there are no underground sources of drinking water beneath the permafrost in the Colville River Unit area. The area affected by Area Injection Order 18B includes only three sections common to the proposed Fiord Oil Pool, Sections 13, 14, and 15 ofT12N, R5E, UM. Additional work should be done to support CPAI's recommended finding of no potential USDWs within the proposed affected area. The Fiord 1, Fiord 4, Fiord 5 and Nigliq 1 exploratory wells in and around this area all have shallow openhole well logs. Please perform TDS calculations on these wells to determine presence of shallow aquifers and distribution of salinity within them. Please provide those results to the Commission. 4. Please provide a more detailed lithologic description of the Nechelik zone (grain size range, any cementation, and the presence of clay or other minerals that may affect reservoir performance). 5. Please provide simplified, legible structure maps for the Kuparuk and the Nechelik zones for the public record? Please provide a "blob" map showing the approximate outline of the oil accumulations. 6. In section 3.1 ofthe conservation order application on page 8, the type log presented for annual disposal is from Bergschrund No.1. On page 9, a north- south cross section is presented that extends from Fiord to Nanuq. Bergschrund No.1 is not on this cross section. Please reconcile this. . . 7. Original reservoir pressure is mentioned for the N eche1ik reservoir, but no pressure information is presented for the Kuparuk. Is there any information on Kuparuk reservoir pressure from exploratory wells in the Fiord area? 8. What is the temperature ofthe reservoir? 9. What is the minimum miscibility pressure of the reservoir? 10. Were slim tube simulations conducted to show that proposed MI is miscible with Fiord crude oil? If so, what were the results? 11. If MI composition varies how will expected minimum miscibility pressure vary? (Please state the expected pressure range). 12. Page 14 ofthe AIO application mentions adding scale inhibitors. The application contains no statements about compatibility of seawater or produced water ftom other CRU oil pools with the proposed Fiord Oil Pool. 13. On page 13, a waiver to the requirement of200-foot packer to perforation separation is requested. However, in the conservation order application, on page 10, section 3.2 it is stated that the angles ofthe well bores at the packer should not prevent wireline access. Please reconcile this. 14. On page 20, area of review, six wells are identified, however, there are a total of8 penetrations due to sidetracks. While the wells are identified and completion reports are attached to the application, no "report" on the condition of the wells has been provided as required by the regulations. AOGCC West Team December 13, 2005 #3 STATE OF ALASKA . NOTICE TO PUBLISHER . ADVERTISING ORDER NO. ADVERTISING ORDER 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-02614022 F AOGCC AGENCY CONTACT DATE OF A.O. R 333 W 7th Ave, Ste 100 o Anchorage, AK 99501 M Jody Colombie PHONE December 14, 2005 peN (907) 793 -1271 DATES ADVERTISEMENT REQUIRED: ~ Anchorage Daily News PO box 149001 Anchorage, AK 99514 December 16, 2005 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Type of Advertisement X Legal D Display Advertisement to be published was e-mailed Classified DOther (Specify) SEE ATTACHED REF TYPE 1 VEN 2 ARD 3 4 J:1t.J 4Mnllt.JT NUMBER I AOGCC, 333 W. 7th Ave" Suite 100 Anchonu!e. AK 99:'i01 AMOUNT DATE I I TOTAL OF I PAGE 1 OF ALL PAGES$ 2 PAGES COMMENTS 02910 !::V f".f". Pf::M If". 4f".f".T J:V NMR DIST LlQ 05 02140100 73451 2 3 ~, 1 R:QUISITIONEE:~ /~ (¡--; , IDIVISION APPROVAL: . . Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Proposed Fiord Oil Pool, Colville River Field Application for Pool Rules ConocoPhillips Alaska, Inc., by letter and application dated November 22, 2005, and received by the Alaska Oil and Gas Conservation Commission ("Commission") on November 25,2005, requests the Commission issue an order defining a new oil pool within the Colville River Unit and to prescribe rules governing development and operation of that pool. This proposed pool, and the proposed development area, are located within portions ofTI2N-R4E, TI2N-R5E, T13N-R4E, and T13N-R5E, Umiat Meridian. The Commission has tentatively scheduled a public hearing on this application for January 19, 2006 at 9:00 am at the offices of the Alaska Oil and Gas Conservation Commission at 333 West ih 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 January 3, 2006. 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 January 17,2006 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 January 19, 2006 hearing. If you are a person with a disability w to comment or to attend the public hear' g, Assistant Jody Colombie at 79. e r may need a special modification in order ase contact the Commission's Special ary 17,2006. Published Date: December 16, 2005 AO# 02614022 . . . ".CO ." Anchorage Daily News Affidavit of Pu1)licatíon 1001 Northway Drive, Anchorage, AK 99508 PRICE OTHER OTHER OTHER OTHER OTHER GRAND AD# DATE PO ACCOUNT PER DAY CHARGES CHARGES #2 CHARGES #3 CHARGES #4 CHARGES #5 TOTAL 683692 12/16/2005 02614022 STOF0330 $153.52 $153.52 $0.00 $0.00 $0.00 $0.00 $0.00 $153.52 Notice of Public Hearine STATE OF ALASKA Alaska Oil and Gas Conservation Commission Subscribed and sworn to me before this date: Re: Proposed Fiord 011 Pool. Colville River Field ApPlication for Pool Rules ConocoPl\illips ··Aldskq. Inc.. by letter cmdappll- cation dated November 22. 200S.and received by tl\eAlaska Oil and Gas Con.servatlon Commis- sion ("Commission') on' November 2S. 200S. re- qUests tl\e, Commissi,on Issue an order defininlJ a new oil pool )Nlthin the Colville River Unit and to prescribe rules gOVern- ing the' development and operation of that pool. Tl\is proposed pool. and the proposed develop- ment area, are locat,ed within portions 'of T12N-R4E. T12N-RS,E. T1 3 N - R 4 E. and T13N-RSE... Umiat Merid- ian. The Commission has tentativelY scheduled a, )ubllc hearing on this ap- plication for January 19. 2006 at 9:00 am at the qf- fices.ofthe Alaska Oil and >9as Conservñtl,an Coml11i!lsionat333 Viest 7th Avenue. .suite .100. Anchórì:lgè, Ala$ka995(11. A perso-nmay request that thetel)tatlvelY' scheduledheadnè. be MId . bY fi ling o' wf!ttenre- quest witll fhe(:ommis- sian no latør than 4:30 pm on January 3. 2006. If a request far Ù, hearin9 is not timely filed. tM Commission may con- ~ider the issuance of an order witl\out a !learing. To learn if the Commis- sion will hold tl\e public hearing. please call 793-1221. STATE OF ALASKA THIRD JUDICIAL DISTRICT Christine Clark, 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 peri . That the full amount of the fee charged for the foregoing 8 liFation is not in excess of the rate charged private mdiVid~' ~ --l. ~ \\l{({{((/fr¡: \.\.\~-o{ ~:.~-jll.. r,.-,.-,... ~~., ..-- "<~~ ~~:~OTARj;.G>~ ~ ~ --- .- § PUB\..\C ':::.~ '.~ --- .ff:¡g32 ~ Q . :VÅ.. ~ .' ~::::: ~~ -:~"OF þ.\..t:. IO':\, ~;:,~.. . . . . . ,,\ ~¿ 1Or¡ &pireb'''\~ ".Ill}}))}))}\) ..... ..... In alj.dition. a person may ~ue~~ i:e;'~~1~: ~hfso riP: plication to the·Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue. Suite 100. Anchorage. Alaska 99S01. Written comments. must be received no later tl\an '4:30 pm øn January 17. 2006 except tl\at if the Commission decides to hold a public hearing. written protests or com- ments must be rE!ceived no later than at the con- clusion of the January 19. 2006 hearing. I f YOu are a person with o disabUity who may need a special modifica- tions in order to com- ment or to, attend the public hearing. please contact the Commission's Special Assistant Jody Colombie at 793-1221 be- fore January·17.2006. John K. Norman Chairman .10 ~ .QcrO s Notary Public in and for the State of Alaska. Third Division. Anchorage, Alaska MY COMMISSION EXPIRES: fo ~ :J..J5lJ <c Published: Dec. 16.2005 A.O.o2614022 Re: Public Notice . . Subject: Re: Public Notice From: "Ads, Legal" <legalads@adn.com> Date: Thu, 15 Dec 2005 15 :25 :06 -0900 <jody _colombie@admin.state.ak.us> Hello, 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: STOF0330 Legal Ad Number: 683693 Publication Date(s): Dee, 16,2005 Your Reference or POi: AO-02614022 Cost of Legal Notice: $153.52 Additional Charges: Web Link: E-Mail Link: Bolding: Total Cost To Place Legal Notice: $153.52 Your Legal Notice Will Appear On The Web: www.adn.com:xxx Your Legal Notice Will Not Appear On The Web www.adn.com:xxx Thank You and Happy Holidays, Christine Clark Anchorage Daily News Legal Classified Representative E-Mail: legalads@adn.com Phone: (907) 257-4296 Fax: (907) 279-8170 On 12/15/05 10:20 AM, "Jody Colombie" <jody colombie@admin.state.ak.us> wrote: Please publish in the Anchorage Daily News tomorrow. Jody Colombie 1 of 1 12/15/20053:40 PM I 02-902 (Rev. 3/94) Pub';'h"ginal Cop;'" D'pa"",,' ......1, D,p'''''''''Mn. AO.FRM STATE OF ALASKA ADVERTISING ORDER NOTICE TO PUBLISHER 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-02614022 F AOGCC 333 West 7th Avenue. Suite 100 A n('hnr~uf' A K QQ'iO 1 907-793-1221 AGENCY CONTACT DATE OF A.O. R o M lodv Colombie December 14. 2005 PHONE peN (907) 793 -1221 DATES ADVERTISEMENT REQUIRED: T o Anchorage Daily News PO box 149001 Anchorage, AK 99514 December 16, 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 he/she 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 Public Notice . . Subject: Public Notice From: Jody Colombie <jody _ colombie@admin.state.ak.us> Date: Thu, 15 Dec 2005 10:20:27 -0900 To: Legal Ads Anchorage Daily News <legalads@adn.com> Please publish in the Anchorage Daily News tomorrow. Jody Colombie Content-Type: application/msword Ad Order form.doc Content-Encoding: base64 Content- Type: application/msword CO Fiord Public Notice.doc - - - Content-Encoding: base64 1 of 1 12/15/2005 11:08 AM Public Notice Fiord Oil Pool, Pool Rules . . .IT.com>, stwf <John. Tower@eia. <scott.cran . <lamb <james. <Tim 10f2 12/15/200511:08AM Public Notice Fiord Oil Pool, Pool Rules . . hur Copoulos <Arthur_Copoulos@dnr.state.ak.us>, Ken teve Lambert unoca1.com>, Joe Nicks <news@radiokenai.com>, nahydrono ahoo.com>, aul Todd <paulto@acsalaska.net>,Bill Walker 's Matthews <Iris Matthews ·s.state.ak.us> Content- T pe: application/pdf Public Notice.pdf . b 64 - dmg: ase 20f2 12/15/2005 11 :08 AM Citgo Petroleum Corporation PO Box 3758 Tulsa, OK 74136 Mona Dickens Tesoro Refining and Marketing Co. Supply & Distribution 300 Concord Plaza Drive San Antonio, TX 78216 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 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 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 . Mary Jones XTO Energy, Inc. Cartography 810 Houston Street, Ste 2000 Ft. Worth, TX 76102-6298 . Robert Gravely 7681 South Kit Carson Drive Littleton, CO 80122 Richard Neahring NRG Associates President PO Box 1655 Colorado Springs, CO 80901 Samuel Van Vactor Economic Insight Inc. 3004 SW First Ave. Portland, OR 97201 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 North Slope Borough PO Box 69 Barrow, AK 99723 David McCaleb IHS Energy Group GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 John Levorsen 200 North 3rd Street, #1202 Boise, ID 83702 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 \. cY·O 0 V1 . 'I..· (-' \(\\u\1 \v ) \" r:t. \ \ \ '. #2 · - DATE \a-i-OS;- RECEIPT 389058 RECBVED FROM fh ~ ~ tLJ) ~ ""Poo( !t.u 0 -..0" Address ~~~ð" S '({,l;~;¡ (Pc) DOLLARS $ I q . FOR 7(0 f'~ e 11 ~~-U/Á--1 ACCOUNT BEGINNING BALANCE AMOUNT PAID BALANCE DUE HOW ~A~~ X CASH ~. l) ~~b BY ~~~ #1 " . . Conocó'Phillips Chris Alonzo Development Supervisor, WNS ConocoPhillips Alaska 700 G Street Anchorage. AK 99501 Phone: 907.276.1215 November 22, 2005 RECEIVED NOV 2 5 Z005 AInu m& &ø &aM. C,QIDffitssion ~. Mr. John Norman, Chair Alaska Oil and Gas Conservation Commission Alaska Department of Revenue 333 West 7th Avenue, Suite 100 i\nchorage,AJe 99501 Re: Proposed Fiord Oil Pool Conservation Order and Area Injection Order Colville River Field Dear Mr. Norman: In accordance with 20 AAC 25.520, ConocoPhillips Alaska, Inc. (CPAI) as operator of the Colville River Unit, requests a conservation order by the commission regarding the classification of the Fiord reservoirs as an oil pool and prescription of rules to govern the proposed development and operation of the pool. CP AI also requests an area injection order authorizing enhanced recovery operations for the proposed Fiord Oil Pool in accordance with 20 AAC 25.460. Attached to this letter is an information package supporting the classification and rules for the proposed Fiord Oil Pool and an application for the Fiord area injection order. I am available to discuss this requests with you and your staff if needed. Please call me at 265-6822 or Jack Walker at 265-6268 if you have questions. n Chri Alonzo Development Supervisor, Western North Slope ConocoPhillips Alaska, Inc. Attachments # , . . 'v Proposed Fiord Oil Pool Conservation Order and Area Injection Order Colville River Field Page 2 November 22, 2005 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 825 W. 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 Petro-Hunt, L.L.C. Attention: Joe Lucas 1601 Elm Street, Suite 3500 Dallas, Texas 75201 (214) 880-8400 Fax: (214) 880-7101 , , " . . I nformation for the Alaska Oil and Gas Conservation Commission for the Classification and Rules for the Proposed Fiord Oil Pool Colville River Field ConocoPhillips Alaska, Inc Anadarko Petroleum Corporation November 14, 2005 Information for proPoS!iord Oil Pool Colville River Field . November 14,2005 Table of Contents I NTROD U CTION ................. ............................................................ ............................1 1.0 RESERVOIR STRUCTURE AND TRAP ..........................................................3 2.0 RESERVOIR FLUID PROPERTIES .................................................................5 3.0 DRILLING, COMPLETION, AND WELL OPERATIONS .................................6 3.1 Drilling Plan......... .................................................. .................. ................. .............. ............. ......6 3.2 Drilling and logg i ng .............. ...... ................................ ......... ................... ................ ............ ....1 0 3.3 Well Spacing................................................. ...... .................................................. ............ .......1 0 3.4 Well Work Plan .. ................................................. ......... .................... ..................... ............ .......1 0 4.0 FACILITIES SCOPE AND DESIGN ...............................................................11 5.0 AGREEMENTS AND PRODUCTION ALLOCATION ....................................12 PROPOSED CONSERVATION ORDER ..................................................................13 List of Fiaures Figure 1 Proposed Affected Area for the Fiord Oil Pool .............................................2 Figure 2 Fiord Oil Pool Type Log ......... .................... ..... ........... ...... ............................4 Figure 3 Proposed Fiord Oil Pool Development Wells and Existing Wells .................6 Figure 4 Well Schematic..................................................... ......... ............................... 7 Figure 5 Annular Disposal Interval Type Log: Bergschrund 1 ....................................8 Figure 6 Annular Disposal Interval Cross Section .......................................................9 Attachment Fiord NO.5 Well Test 2 (Nechelik + Kuparuk) Composition of Prepared Reservoir Fluid Page i ConocoPhillips Alaska, Inc. Information for proPoS.iord Oil Pool Colville River Field . November 14, 2005 INTRODUCTION This document includes information for the Alaska Oil and Gas Conservation Commission to classify two hydrocarbon zones in the Colville River Field as the Fiord Oil Pool and to prescribe rules to govern development of the pool in accordance with 20 AAC 25.520. The proposed Fiord CD3 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 Fiord Oil Pool. The proposed Fiord Oil Pool includes the Nechelik sand within the Kingak Formation and Kuparuk C sand in the Kuparuk River Formation. The Fiord-Kuparuk and Nechelik zones have sand-on-sand contact and ,¡ hydraulic communication in the oil column in the northern portion of the accumulation. A common oil accumulation exists in the Nechelik and Kuparuk zones, but due to substantially different permeabilities and the limited area of sand-on-sand contact of the Nechelik and Kuparuk zones, dedicated wells are planned for each zone with completions limited to a single zone, except where the zones have direct sand-on-sand contact of the Nechelik and Kuparuk zones. One well is known to have sand-on-sand contact, but other wells are not expected to encounter contiguous reservoir sand-on-sand in the Nechelik and Kuparuk zones. See section 6 for more on reservoir description. Concurrent with this request, ConocoPhillips Alaska, Inc. (CPAI), as operator of the Colville River Unit (CRU) and on behalf of the working interest owners (WIOs), is seeking an Area Injection Order by the Commission to endorse and authorize the proposed Fiord CD3 Miscible Water Alternating Gas Project. The project is located in the Colville Delta area approximately 6 miles north of the Alpine Central Facility. The project is comprised of a single drill site served by ice roads in the winter and airstrip. It will be connected to the existing Alpine Central Facility (ACF) by pipelines and electric power lines. Seventeen horizontal wells are planned to develop the two zones: 5 wells for Fiord-Kuparuk and 12 wells for Nechelik. Implementation of miscible water alternating gas operations from field start-up is planned. For each zone in the proposed Fiord Oil Pool, the working interest owners plan to form a separate participating area within the CRU. Preliminary boundaries for the future participating areas are shown on Figure 1 with the present CRU Boundary. CPAI as operator and on behalf of the WIOs, plans to apply to the State of Alaska and Arctic Slope Regional Corporation, to form a Fiord-Nechelik Participating Area and a Fiord-Kuparuk Participating Area in early 2006. Development drilling and facilities construction started in early 2004 at Drill Site CD3, and Fiord production start up is planned in 2006, creating the need to establish pool rules and complementary area injection order for the proposed oil pool. 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. Page 1 ConocoPhilllps Alaska, Inc. Information for Prop Colville River Pield I'd Oil Pool November 14. 2005 ¥ '" .... .., t ., I .... .... .... ..... r Figure 1 Proposéd Affected Area for the Fiord Oil Pool ConocoPhillips Alaska. Inc. Information for prOPOS.iord Oil Pool Colville River Field . November 14, 2005 1.0 RESERVOIR STRUCTURE AND TRAP The proposed Fiord Oil Pool is comprised of two reservoir sands, Nechelik and Fiord- Kuparuk. The proposed pool is defined from the top of Kuparuk C sand at 6,876 feet measured depth (MD) to the base of the Nechelik sand at 7,172 feet MD in Fiord 5 as shown on Figure 2. Original oil in place is estimated at 60 to 130 MMSTBO for the Nechelik sand, and 20 to 60 MMSTBO for the Kuparuk sand. The Nechelik sand is an Upper Jurassic (Oxfordian) sandstone within the Kingak Fonnation. The Nechelik, Nuiqsut, and Alpine zones are informal names for three Upper Jurassic sand bodies present within the CRU. The Nechelik lies stratigraphically below the Nuiqsut and Alpine. Conventional cores in the Fiord #1, Fiord #5, and Nigliq #1 wells help define both the vertical and lateral extent of the Jurassic facies. The Nechelik interval was deposited in a progradational to aggradational shallow marine setting. The best reservoir quality sands occur near the top of the interval. The erosion of the Nechelik by the Lower Cretaceous Unconfonnity (LCU) forms the updip trap, on the northern flank of this stratigraphically trapped reservoir. The Kuparuk C interval is a shallow-marine transgressive sandstone deposited on the LCU. Over most of the CRU, the Kuparuk C is present as a thin transgressive lag, generally less than 5 feet thick. Locally, the Kuparuk C sand thickens on the downthrown side of normal faults which created accommodation space during Lower Cretaceous time. The 'Fiord' fault is a northwest trending normal fault, down to the west, which provided accommodation space for the Kuparuk C reservoir in the CD3 area. The Fiord #1 well has 23 feet of Kuparuk C sand and is located approximately 2700 feet west of the 'Fiord' fault. The lateral extent of Kuparuk C reservoir sands west of the 'Fiord' fault is defined by Fiord #1, #2, and #5 and the CD3-108, -109 and -110 wells. The Nechelik sand is underlain by interbedded mudstone, siltstone, and very fine-grained sandstone of the Kingak Formation. The underlying Kingak sequence is over 1,100 feet thick in the Fiord #1 well. At total depth, the Fiord #5 well penetrated 330 feet of Kingak below the Nechelik zone. Overlying the Kuparuk sand is approximately 90 feet of shale-rich lithology. Directly overlying the Kuparuk C sand is roughly 50 feet of Kuparuk D shale and 40 feet of Kalubik shale. Between the Kuparuk and Nechelik sands in the Fiord #5 and Fiord #1 wells, there is a wedge of non-reservoir shale and sandstone of the Kingak Fonnation which thickens to the south. The top of the non-reservoir wedge is the LCU which dips to the north. The base of the non-reservoir wedge is the top of the Nechelik which dips to the south. In the northern part of the proposed pool, the LCU intersects and cuts into the Nechelik zone. In the southern portion of the proposed Fiord Oil Pool at Fiord #1, there exists 376 feet TVD of non- reservoir Kingak interval between the LCU and the Nechelik zone. In the Fiord #5 well, roughly 10,000 feet north-northwest of Fiord #1, the Nechelik and Kuparuk zones are separated by 131 feet TVD of non-reservoir Kingak. At the heel of the horizontal well, CD3- 108, there is approximately 190 feet TVD of non-reservoir Kingak separating the Kuparuk and Nechelik zones, but at the toe of CD3-108, almost 8000 feet north-northwest lateral distance from the heel, Kuparuk sand and Nechelik sand are contiguous in the oil column. ,/ Kuparuk sand is not always present on top of the LCU, but at the CD3-108 toe location approximately 22 feet MD (5 feet TVD) of Kuparuk C Sand exists with sand-on-sand contact ./ with the Nechelik zone. The Kuparuk reservoir trap is fanned by the Fiord Fault to the east with stratigraphic pinchouts elsewhere. The Kuparuk structure generally dips to the north, and the sand thins westward from the Fiord Fault. The Nechelik zone is truncated by the LCU to the north of the development area and the sand quality degrades to the south and west. Page 3 ConocoPhilllps Alaska, Inc. Information for proPoS.iord Oil Pool Colville River Field 0 ~ Q ~ ~ 2'¡ roE !~ a.LL ::IS ~ ~.5 ~ Kuparuk e - -- ::I", ø~ .2"s ::I c z_ E LL ~ CO C) c: ~ ~- =fO CD ~ .cCD u_ CD c z- - Fiord 5 Gr LWD Depth DeepRes LWD ISO MD 1 100 Figure 2 Fiord 011 Pool Type Log Page 4 . November 14, 2005 6816 Top Kuparuk e 6892 Base Kuparuk e (LeU) 6943 Base Nuiqsut 1021 Top Nechelik 1112 Base Nechelik ConocoPhlllips Alaska, Inc. Information for proPoS.iord Oil Pool Colville River Field . November 14, 2005 2.0 RESERVOIR FLUID PROPERTIES Fiord CD3 project fluids were characterized with samples from the Fiord #1, Fiord #5, and CD3-108 production tests, augmented with subsurface RFT samples acquired in Nigliq #1. Separate samples were collected from the Kuparuk and Nechelik zones in some cases and commingled samples were collected in some cases as shown in Table 1. Table 1 Fiord Crude Sample Summary Well Zone(s) Viscosity (cp) Solution GOR (SCF/STB) Relative Oil Volume (RB/STB) Oil Gravity (degrees API) Fiord #1 Kuparuk 0.889 609 1.333 31.3 Fiord #5 Nechelik 0.891 538 1.299 28.6 Fiord #5 Commingled 0.786 556 1.310 29.4 Nigliq #1 Nechelik 0.92 556 1.307 30.9 Solution GOR, relative oil volume, and oil gravity date in Table 1 were taken from the differential vaporization tests run at 165°F, except for Fiord #1 which was run at 158°F. Only oil gravity data is available for the CD3-108 sample: 28.6°API. Additional results of the Fiord #5 pressure-volume-temperature behaviour of the Fiord #5 KuparuklNechelik commingled sample are shown in Table 2. Table 2 Fiord #5 PVT Summary (RFL 990089) Temperature: 165°F Saturation pressure: 2395 psig Single phase compressibility: 8.64 x 10-6 v/v/psi (average 5000 to 2395 psig) Thermal expansion: 1.05234 v at 165°F I v at 60°F Density of reservoir fluid: 0.7534 glcc Analysis of the reservoir fluid from the Nechelik and Kuparuk zones is shown in the attached report on Composition of Prepared Reservoir Fluid for the Fiord No.5 Well - Test 2 (Nechelik + Kuparuk) RFL990089. Page 5 ConocoPhillips Alaska. Inc. Information for Propo Colville River Field rd Oil Pool November 14, 2005 3.0 DRILLING, COMPLETION, AND WELL OPERATIONS Seventeen horizontal wells are planned at the Fiord CD3 development. The Nechelik development is planned with 12 wells (6 producers and 6 injectors), and the Kuparuk development is planned with 5 dedicated wells (3 producers and 2 injectors). Nechelik wells are planned with open hole completions and Kuparuk wells are planned with slotted liner completions. The surface and intermediate holes will be directionally drilled with water based mud systems and cased. The horizontal intervals will be drilled with a reservoir drilling fluid. With the exception of the production/injection hole liners for Kuparuk, the well plans for the Fiord Oil Pool are almost identical to the standard development well design used in the Alpine Oil Pool. For both Nechelik and Fiord-Kuparuk, producers are planned with surface-controlled subsurface safety valves and injectors are planned with differential pressure-operated, subsurface-controlled subsurface safety valves. Surface safety valves are planned for all wells. 3.1 DRILLING PLAN Hole and casing sizes, mud systems, directional profile and departure, drilling techniques, and geologic section drilled to reach the Fiord Oil Pool targets are similar to those for the Alpine Oil Pool. Existing wells and future development wells are shown in Figure 3. Drillíng began at Alpine in 1999 and 102 horizontal wells have be completed as of October 12, 2005. Fiord Oil Pool wells will be drilled from 20-foot centers. N N FIORD 4 II / NIGUQ 1/" 'r/ NECHEUK 1 . \ \ \\\ \ \ \ \ ALPÎ\ \. \ N Future Nechelik Producer N Future Nechelik Injector K IHH>........-~- Future Kuparuk Producer Future Kuparuk Injector ~~~... Existing Nechelik Penetration --~.. Existing Kuparuk Penetration 1 !72000 FIORD 2 \ \\ "\\ \ :s M Ii) MI Figure 3 Proposed Fiord Oil Pool Development Wells and Existing Wells Primary, secondary, and general well control for drilling and completion operations will be performed in accordance with 20 AAC 25 Articles 01 and 06. Casing and cementing will be performed in accordance with 20 MC 25.030. Surface casing, cemented to surface, is Page 6 ConocoPhillips Alaska. inc. Information for Propo rd Oil Pool Colville River Field November 14,2005 planned at approximately 2400 feet true vertical depth. Intermediate hole will be drilled to the target formation and production 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. Nechelik wells will be cemented such that the Kuparuk zone is protected. Zones above Kuparuk will also be evaluated on a well-by-well basis. If a significant hydrocarbon zone(s) is indicated by logging discussed in the following section 3.2, the cementing program will be designed for that well to protect that zone(s). Either leak-off or formation integrity tests are planned after drilling 20 to 50 feet beyond the respective surface casing shoe and the production casing shoe. The horizontal sections will be drilled with a reservoir drilling fluid. The Kuparuk wells will completed with a 4%-inch slotted liner across from sands and blank liner across from shales. Nechelik wells will be completed openhole. A packer and tubing will be run for both Kuparuk and Nechelik wells. A proposed producing well schematic is shown in Figure 4. CD3 - Kupafuk/Nechelik Sand Producer 16" Insulated Conductor to 114' I Surface-controlled, subsurface safety valve at +/·2000' TVD 9-518" 40 ppf L·I)O STeM Surface Casing at +/-2400' TVD, cemented to surface 3-y," 9.3 ppfor 4-y," 12.6 ppf L-80 1ST Mod. tubIng / QL , Gas lift mandrels and valves Liner top hanger Top ReservoIr at +/- 6800' TVD Kuparuk 6900' TVD Nechelik Hortzontal 7" 26 opf L-80 aTC Mod Produclion Casing @ +/-85' ~ interval: 4-:Xt 12.6 ppf L;;aO SLHT hangerJfiner wi hlank acro$:s shale and slo1.5 across sand ~ interval: open ho1e completion (no hangerltiner) Figure 4 Well Schematic Page 1 ConocoPhillips Alaska. Inc. Information for Pr Colville River Field November 14, 2005 Injection wells wiHhavesimilarcompletions, sliding sleeve wiWbe omitted from the differential pressure...controlled. Disposal of drilling wastes· will be proposed 25.080 in. annuli of wells with surface sources of drinking. water Injection Order No. 18B, will be the Upper PERMAFROST (1500ft) Fig\.ire 5 Annular Disposal I ntefVa I Type I-óg: Bergschrund 1 This interval contains over 1800 feet of interbedded upper part of the has been successful at will be 10-20 feet above the Page 8 ConocoPhillips Information for Prop Colville River Field November 14, 2005 shale and siltstone of the Upper Cretaceous Schrader Bluff Formation. Approximately 1500 feet of permafrost overlies the Schrader Bluff. The lower Barrier is composed of 1900 feet of shale and siltstone ofthe Torok Formation. r : :¡ CD3 CD3-108 21M ,." '2500 "'" 2700 ''''' CD1 CD1-22 CD2 ALPINE 1 CD4 NANUK 1 OR 1 OR ~ ~ ~ C-40 '"'' "00 22QiI 2300 2100 2300 C-30 ,." Annular '4<JO Disposal 2400 Interval 2500 1500. "'" '000 "00 "00 2.3 C..20 5.3 Milas 77Qo. "00 Miles --- lJðß Figure 6 Annular Disposal Interval Cross Section Page 9 ConocoPhillips Alaska, Inc. Information for proPoS.iord Oil Pool Colville River Field . November 14, 2005 3.2 DRilliNG AND lOGGING Preliminary slot assignments and directional plans for the 17 wells have been generated. Drilling from 2Q-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 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 Fiord CD3 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 Fiord Oil Pool 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. The surface and intermediate holes in the CD3-108 well were logged with gamma ray/resistivity/neutronldensity logs. 3.3 WEll SPACING Well spacing requirements under 20 AAC 25.055 should be waived because the horizontal well development will yield greater recovery than a conventional well development with a minimum spacing rule. The average Nechelik horizontal well will contact roughly 200 times more reservoir than a conventional well. Reservoir simulation of conventional wells and horizontal wells indicated Kuparuk sand ultimate recovery can be maximized with horizontal wells. 3.4 WEll WORK PLAN Well service operations are planned in accordance with 20 AAC 25 Article 03. Drillsite CD3 is planned with winter-only road access to the ACF, and air access at other times. 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. Page 10 ConocoPhilllps Alaska, inc. Information for propoAiord Oil Pool Colville River Field . November 14, 2005 4.0 FACILITIES SCOPE AND DESIGN The Fiord CD3 surface facilities scope includes a gravel airstrip connected to a 12.6-acre gravel pad. The drilling rig will be moved to and from Drill Site CD3 on ice roads. Drillsite CD3 will be connected to the ACF with pipelines, power lines, and communications. Drillsite facilities include the following: · Production, test, artificial lift, gas injection, and water injection headers; · Tie-in slots for 17 wells with wellhead shelters and space for 7 additional wells; · Wellhead hydraulic panels (in well house); · Fuel gas conditioning · Electrical and instrumentation module with transformers, switch gear, and telecommunications; · Instrument air compressor package; · Test separator; · Emergency shut down (ESD) skid; · Water injection line pig receiver; · Production heater; · Warm and cold storage buildings; · Gravel maintenance equipment, slickline unit, pad vehicle, etc.; · Chemical injection and storage; · Waste handling containment facility; · Emergency living quarters; · Emergency power generator; · Lighting, surveillance, and communication equipment; · Powerlines (13.8 kV) suspended by messenger cable below the pipelines; · 16-inch diameter production pipeline; · 8-inch diameter water injection pipeline; · 6-inch diameter MI pipeline; · 6-inch diameter gas-lift pipeline; and · 2-inch products line for freeze protection. The Fiord CD3 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 major river channels as CD 1 and CD2, thus simplifying road access to the new drillsite · Minimizes disturbance of bird nesting area · Consideration of hydrolology study results Page 11 ConocoPhillips Alaska, Inc. Information for proposaiord Oil Pool Colville River Field . November 14, 2005 5.0 AGREEMENTS AND PRODUCTION ALLOCATION All lands within the Fiord CD3 project area are leased and within the CRU. Most leases in the area have the same working interest as the Alpine Field (78 percent CPAI and 22 percent Anadarko Petroleum Company), but three tracts include a 0.38% working interest owned by Petro-Hunt. Discussions with Petro-Hunt on participating in the project are being initiated. The CRU Agreement among the royalty interest owners, State of Alaska and Arctic Slope Regional Corporation, and the working interest owners prescribes a methodology for establishing participating areas and equity determination. The operations of the Fiord CD3 project are subject to the CRU Operating Agreement. Development of the proposed Fiord Oil Pool is planned with development wells solely dedicated to a single zone with no subsurface commingling, except where sand-on-sand contact exists such as the existing injector well CD3-108. Unitized substances produced from the Fiord Oil Pool will be commingled on the surface with substances from the other oil pools in the Colville River Field. 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: V ti = Theoretical volume for well i V tCRU = Total theoretical volume for CRU VtCRU = Vt1 + Vt2. + ... VIII 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 = AFVti Page 12 ConocoPhillips Alaska, Inc. Information for proPoS.iord Oil Pool Colville River Field . November 14, 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 T12N R4E sections 1,2,11-14 T12N R5E sections 1-18 T13N R4E sections 25, 34-36 T13N R5E sections 15-22, 26-36 Rule 1. Field and Pool Names The field is the Colville River Field and the pool is defined as the Fiord Oil Pool. Rule 2. Pool Definitions The Fiord Pool is defined as the accumulation of oil and gas common to and correlating to the interval found in the Fiord No.5 well between the depths of 6876 and 7172 feet measured depth. Rule 3. Well Spacing The requirements of 20 AAC 25.055 are waived for development wells in the Fiord Oil Pool. Without prior notification, development wells may not be completed closer than 500 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 Fiord 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 MC 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, 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. (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. 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 Fiord Page 13 ConocoPhillips Alaska, Inc. Information for proPoS.iord Oil Pool Colville River Field . November 14, 2005 Oil Pool. (c.) The reservoir pressure datum shall be 6850 feet subsea. (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 Fiord 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 Fiord Oil Pool may be commingled on the surface with production from other Colville River Field pools 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 Casing Pressure (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 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 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 require the operator to take emergency corrective action before 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 Page 14 ConocoPhlllips Alaska, Inc. Information for proposaiord Oil Pool Colville River Field . November 14, 2005 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 (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 15 ConocoPhillips Alaska, Inc. Information for proPoS.iord Oil Pool . November 14, 2005 Colville River Field ARCO Technology & Operations Services Fiord No.5 Well - Test 2 (Nechelik + Kuparuk) RFL 990089 Composition of Prepared Reservoir Fluid (by Low Temperature Distillation/Extended Chromatography) Component Name Mol % Wt% Density MW (gm/cc) Hydrogen Sulfide 0.00 0.00 0.8006 34.08 Carbon Dioxide 0.34 0.12 0.8172 44.01 Nitrogen 0.32 0.07 0.8086 28.013 Methane 35.71 4.64 0.2997 16.043 Ethane 4.83 1.18 0.3562 30.07 Propane 6.04 2.15 0.5070 44.097 iso-Butane 1.36 0.64 0.5629 58.123 n-Butane 3.19 1.50 0.5840 58.123 iso-Pentane 1.34 0.78 0.6244 72.15 Total Sample Properties n-Pentane 2.10 1.22 0.6311 72.15 Hexanes 3.69 2.51 0.6850 84 Molecular Weight ....... ...... ....... ...... .......... ...... 123.68 Heptanes 3.36 2.61 0.7220 96 Theoretical Liquid Density, gm/scc ................ 0.7732 Octanes 4.47 3.87 0.7450 107 Nonanes 3.27 3.20 0.7640 121 Decanes 2.91 3.16 0.7780 134 Undecanes 2.42 2.87 0.7890 147 Dodecanes 2.14 2.79 0.8000 161 Tridecanes 2.16 3.06 0.8110 175 T etradecanes 1.89 2.90 0.8220 190 I Mol% I I Density I Pentadecanes 1.82 3.03 0.8320 206 Cyclic Compounds Wt% MW Hexadecanes 1.52 2.72 0.8390 222 (included in individual hydrocarbon fractions) Heptadecanes 1.29 2.48 0.8470 237 Octadecanes 1.23 2.51 0.8520 251 Methylcyclopentane 0.48 0.33 0.7529 84.16 Nonadecanes 1.10 2.33 0.8570 263 Benzene 0.06 0.04 0.8836 78.11 Eicosanes 0.92 2.06 0.8620 275 Cyclohexane 0.47 0.32 0.7826 84.16 Heneicosanes 0.81 1.92 0.8670 291 Methylcyclohexane 1.39 1.10 0.7732 98.19 Docosanes 0.73 1.79 0.8720 305 Toluene 0.36 0.27 0.8710 92.14 T ricosanes 0.65 1.67 0.8770 318 Ethylbenzene 0.15 0.13 0.8708 106.17 T etracosanes 0.56 1.50 0.8810 331 meta & para Xylenes 0.38 0.33 0.8664 106.17 Pentacosanes 0.52 1.44 0.8850 345 ortho-Xylene 0.21 0.18 0.8838 106.17 Hexacosanes 0.42 1.22 0.8890 359 iso-Propylbenzene 0.13 0.13 0.8656 120.20 Heptacosanes 0.40 1.21 0.8930 374 n-Propylbenzene 0.23 0.22 0.8656 120.20 Octacosanes 0.37 1.16 0.8960 388 1,2,4- Trimethylbenzene 0.28 0.27 0.8798 120.20 Nonacosanes 0.33 1.07 0.8990 402 T riacontanes 0.29 0.98 0.9020 416 Mol% I I Density I Hentriacontanes 0.26 0.92 0.9060 430 Plus Fractions Wt% MW Dotriacontanes 0.24 0.84 0.9090 444 T ritriacontanes 0.21 0.76 0.9120 458 T etratriacontanes 0.19 0.72 0.9140 472 Hexanes plus 44.77 87.70 0.8841 242 Pentatriacontanes 0.17 0.66 0.9170 486 Heptanes plus 41.08 85.19 0.8917 256 Hexatriacontanes plus 4.43 27.74 1.0626 774 Decanes plus 29.98 75.51 0.9148 312 Pentadecanes plus 18.46 60.73 0.9481 407 Eicosanes plus 11.50 47.66 0.9811 513 Pentacosanes plus 7.83 38.72 1.0105 612 Triacontanes plus 5.79 32.62 1.0363 697 Pentatriacontanes plus 4.60 28.40 1.0587 764 Totals 100.00 100.00 Page 16 ConocoPhillips Alaska, Inc. . . Application to the Alaska Oil and Gas Conservation Commission for the Fiord Area Injection Order Colville River Field ConocoPhillips Alaska, Inc Anadarko Petroleum Corporation November 22, 2005 Application to the AOa for the Fiord Area Injection Order . Colville River Field November 22, 2005 Table of Contents Introduction ...................................................................................................................................... 3 20 AAC 25.402 (c){1) Plat of Wells Penetrating Injection Zone....................................................... 4 20 AAC 25.402 (c){2) Operators and Surface Owners within One Quarter Mile of Injection Operations....................................... ... .................................................. ....................... ..................... 5 20 AAC 25.402 (c){3) Affidavit of Jack A. Walker Regarding Notice to Surface Owners ................ 6 20 AAC 25.402 (c){4) Description of the Proposed Operation ........................................................ 7 20 AAC 25.402 (c){5) Description and Depth of Pool to be Affected............................................... 9 20 AAC 25.402 (c){6) Description of the Formation....................................................................... 11 20 AAC 25.402 (c){7) Logs of the Injection Wells.......................................................................... 12 20 AAC 25.402 (c){8) Casing Description and Proposed Method for Testing ............................... 13 20 AAC 25.402 (c){9) Injection Fluid Analysis and Injection Rates ............................................... 14 20 AAC 25.402 (c){10) Estimated Pressures.................................................................................15 20 AAC 25.402 (c){11) Fracture Information ................................................................................. 16 20 AAC 25.402 (c){12) Quality of Formation Water....................................................................... 17 20 AAC 25.402 (c){13) Aquifer Exemption Reference................................................................... 18 20 AAC 25.402 (c){14) Incremental Hydrocarbon Recovery ......................................................... 19 20 AAC 25.402 (c){15) Mechanical Condition of Wells Within y.. Mile of Proposed Area.............. 20 List of Fiaures Figure 1 Proposed Affected Area for Fiord Area Injection Order.................................................. 21 Figure 2 Proposed Fiord Oil Pool Development Wells and Existing Wells................................... 22 Figure 3 Fiord Type Log.............................................................. ........... .............. .................... ..... 23 Figure 4 Typical Fiord Injector Well Schematic ............................................................................24 Attachments Fiord Area Fracture Containment Modeling Fiord #1 Well Completion Report (AOGCC Form 10-407) Fiord #1 P&A Schematic Fiord #2 Well Completion Report (AOGCC Form 10-407) Fiord #2 Plug and Abandon Schematic Fiord #4 Well Completion Report (AOGCC Form 10-407) Fiord #4 P&A Schematic Fiord #5 Well Completion Report (AOGCC Form 10-407) Fiord #5 P&A Schematic Nechelik #1 Well Completion Report (AOGCC Form 10-407) Nigliq #1 Well Completion Report (AOGCC Form 10-407) Nigliq #1 P&A Schematic CD3-108 Well Completion Report (AOGCC Form 10-407) CD3-108 Well Schematic CD3-109 Application for Permit to Drill CD3-109 Suspension Schematic CD3-110 Application for Permit to Drill CD3-110 Suspension Schematic Page 2 ConocoPhillips Alaska, Inc. Application to the AO. for the Fiord Area Injection Order . Colville River Field November 22, 2005 Introduction This area injection order application seeks Alaska Oil and Gas Conservation Commission endorsement and authorization for the proposed Fiord CD3 Miscible Water Alternating Gas Project in the CRU. This project involves the development of two zones from Drill Site CD3: Nechelik and Fiord-Kuparuk. This application has been prepared in accordance with 20 AAC 25.402 (Enhanced Recovery Operations) and 20 AAC 25.460 (Area Injection Orders). The proposed Fiord CD3 Miscible Water Alternating Gas Project is an enhanced oil recovery project employing the cyclic injection of miscible gas (MI) and water to be implemented for the development of the proposed Fiord Oil Pool, which is located within the Colville River Field on the North Slope of Alaska. The proposed Fiord Oil Pool includes both the Nechelik zone within the Kingak Formation and the Kuparuk zone in the Kuparuk River Formation. The Kuparuk and Nechelik zones have sand-on-sand contact and hydraulic communication in the oil column in the northern portion of the common accumulation. A common oil accumulation exists in the Nechelik and Kuparuk zones, but due to substantially different permeabilities and the limited area of sand-on-sand contact of the Nechelik and Kuparuk zones, dedicated wells are planned for each zone with completions limited to a single zone, except where the zones have direct sand-on-sand contact of the Nechelik and Kuparuk zones. One well is known to have sand-on-sand contact, but other wells are not expected to encounter contiguous reservoir sand-on-sand in the Nechelik and Kuparuk zones. See section 6 for more on reservoir description. Concurrent with this application for an Area Injection Order, ConocoPhillips Alaska, Inc., as operator of the CRU and on behalf of the w()rking interest owners (WIOs), is seeking a Conservation Order by the Commission regarding the classification and rules to govern the development of tht:t proposed Fiord Oil Pool. For each proposed zone, the working interest owners plan to form a separate participating area within the CRU. Preliminary boundaries for the future participating areas are shown on Figure 1 with the prel;ent CRU Boundary. ConocoPhillips Alaska, Inc., as operator and on behalf of the WIOs, plans to apply to the State of Alaska and Arctic Slope Regional C:orporation to form a Fiord-Nechelik Participating Area and a Fiord-Kuparuk Participating Area in early 2006. Development drilling started March, 2005 at Drill Site CD3 and Fiord production start up is planned in 2006, creating the need to establish pool rules and complementary area injection order for the proposed oil pool. Page 3 ConocoPhillips Alaska, Inc. Application to the AO. for the Fiord Area Injection Order . Colville River Field November 22, 2005 20 AAC 25.402 (c)(1) Plat of Wells Penetratina Iniection Zone The attached map (Figure 2) shows all existing wells penetrating the injection zones in the proposed injection area. The maps also show the areal extent of the injection zone relative to preliminary participating areas within the CRU, and the location of all proposed Fiord Oil Pool development wells (injection wells and development wells). Page 4 ConocoPhillips Alaska, Inc. Application to the AoA for the Fiord Area Injection Order . Colville River Field November 22, 2005 20 MC 25.402 (c)(2) Operators and Surface Owners within One Quarter Mile of Injection Operations Operator: ConocoPhillips Alaska, Inc. Attention: Matt Elmer P. O. Box 100360 Anchorage, AK 99510-0360 Surface Owners: State of Alaska Department of Natural Resources Attention: Mike Kotowski P. O. Box 107034 Anchorage, AK 99510 Kuukpik Corporation Mr. Isaac Nukapigak PO Box 187 Nuiqsut, Alaska 99789-0187 Page 5 ConocoPhillips Alaska, Inc. Application to the AOa for the Fiord Area Injection Order Colville River Field . November 22, 2005 20 MC 25.402 (c)(3) Affidavit of Jack A. Walker Reoarding Notice to Surface Owners Jack A. Walker, on oath, deposes and says: 1. I am the Fiord Production Engineer for ConocoPhillips Alaska, Inc., the operator of the Colville River Unit. 2. On November 22, 2005, I caused copies of the application for the Fiord Area Injection Order to be provided to the surface owner and operator of all land within a quarter mile of the proposed injection wells as listed below: a. State of Alaska Department of Natural Resources Attention: Mike Kotowski P. O. Box 107034 Anchorage, AK 99510 b. Kuukpik Corporation Mr. Isaac Nukapigak PO Box 187 Nuiqsut, Alaska 99789-0187 c. ConocoPhillips Alaska, Inc. Attention: Matt Elmer ATO-1750 P.O. Box 100360 Anchorage. Alaska 99510-0360 lw ~ckA.wal~ STATE OF ALASKA ) ) ss. THIRD JUDICIAL DISTRICT ) SUBSCRIBED AND SWORN to before me this 22nd day of November, 2005. /{yfiL}ß ~~. NOT~~UBLlC IN A:¿ ;t~SKA My Commission Expires: ~ . /Ý'/ ej>oO/5 - STATE OF ALASKA /\í~ NOTARY PUBLlC:-' '::'-:' ~J Carol Kelly . ~ My Commission Expires Aug. 16, 2008 Page 6 ConocoPhillips Alaska. Inc. Application to the AoA for the Fiord Area Injection Order . Colville River Field November 22, 2005 20 MC 25.402 (c)(4) Description of the Proposed Operation An Area Injection Order is needed to develop the proposed Fiord Oil Pool. The scope of the development project includes drilling 17 wells from a new CRU Drill Site, CD3. Five wells are planned to develop the Kuparuk zone and twelve wells are planned to develop the Nechelik zone. Development of the proposed Fiord Oil Pool is planned with development wells solely dedicated to a single zone, except where the Nechelik and Kuparuk zones have contiguous sand-on-sand contact. Unitized substances produced from the proposed Fiord Oil Pool will be commingled on the surface with substances from the existing Alpine Oil Pool and proposed Nanuq and Nanuq-Kuparuk Oil Pools. Similar to the existing allocation of unitized substances for the Alpine Oil Pool, production allocation for the proposed pool will be based on periodic well tests and producing conditions, e.g. up time; and injection allocation for the proposed pools will be based on meters on each injection well. Water alternating with MI injection is the proposed recovery mechanism for both zones. The project scope includes injection of water and enriched hydrocarbon gas from the Alpine Central Facility ("ACF"), also located within the CRU. At the end of the Fiord CD3 Project MI phase, lean gas and/or water may be injected to recover the remaining mobilized oil and injected hydrocarbons. Injection of water is scheduled to begin in 2006, followed by MI injection beginning in 2007. Five injection wells for the Nechelik zone and two injection wells for the Fiord-Kuparuk zone and one NecheliklKuparuk commingled injection well are included in the scope of the Fiord CD3 Project. Surface facilities will be installed at the CD3 drillsite to deliver and meter both MI and water to each injection well. Horizontal development wells will be drilled from Drill Site CD3. For both zones, well layout is a direct line drive pattern configuration with alternating injectors and producers. Planned interwell spacing is 2,100 feet for the Nechelik and 4,500 feet for the Fiord-Kuparuk. Different well spacing may be implemented after analysis of reservoir performance. Horizontal production and injection holes are planned at approximately 8,000 feet in the Nechelik zone and approximately 4000 feet for the Kuparuk zone. The Fiord CD3 surface facilities scope includes a gravel airstrip connected to a 12.6-acre gravel pad located north of the ACF. The drilling rig will be moved to and from Drillsite CD3 on ice roads. The project includes produced oil, water injection, MI, and gas lift pipelines and electric powerline between the ACF to the Fiord CD3 drillsite. Drillsite facilities include the following: Production, test, artificial lift, gas injection, and water injection headers; Tie-in slots for 17 wells with wellhead shelters and space for 7 additional wells; Wellhead hydraulic panels (in well house); Fuel gas conditioning; Page 7 ConocoPhillips Alaska, Inc. Application to the AoA for the Fiord Area Injection Order . Colville River Field November 22, 2005 Electrical and instrumentation module with transformers, switch gear, and telecommunications; Instrument air compressor package; Test separator; Emergency shut down (ESD) skid; Water injection line pig receiver; Production heater; Warm and cold storage buildings; Chemical injection and storage; Waste handling containment facility; Emergency living quarters; Emergency power generator; Lighting, surveillance, and communication equipment; Powerlines (13.8 kV) suspended by messenger cable below the pipelines; 16-inch diameter production pipeline; 8-inch diameter water injection pipeline; 6-inch diameter MI pipeline; 6-inch diameter gas-lift pipeline; and 2-inch products line for freeze protection. Page 8 ConocoPhillips Alaska. Inc. Application to the AOa for the Fiord Area Injection Order . Colville River Field November 22, 2005 20 MC 25.402 (c)(5) Description and Depth of Pool to be Affected Location The proposed Fiord Oil Pool is located in the CRU approximately 6 miles north of the Alpine Central Facility. As shown on Figure 1, the affected area proposed for the Fiord Area Injection Order is: Umiat Meridian T12N R4E sections 1,2, 11-14 T12N R5E sections 1-18 T13N R4E sections 25, 34-36 T13N R5E sections 15-22, 26-36 Pool Definition The proposed Fiord Oil Pool is the hydrocarbon-bearing interval between 6,876 and 7,172 feet measured depth in the Fiord #5 well (Figure 3) and its lateral equivalents. Pool Description The proposed Fiord Oil Pool is comprised of two reservoir zones, Nechelik and Kuparuk. The Nechelik zone is an Upper Jurassic (Oxfordian) sandstone within the Kingak Formation. The Nechelik, Nuiqsut, and Alpine zones are informal names for three Upper Jurassic sand bodies present within the CRU. The Nechelik zone lies stratigraphically below the Nuiqsut and Alpine zones. Conventional cores in the Fiord #1, Fiord #5, and Nigliq #1 wells help define both the vertical and lateral extent of the Jurassic facies. The Nechelik interval was deposited in a progradational to aggradational shallow marine setting. The best reservoir quality sands occur near the top of the interval. The erosion of the Nechelik by the Lower Cretaceous Unconformity (LCU) forms the updip trap, on the northern flank of this stratigraphically trapped reservoir. The Kuparuk zone is a shallow-marine transgressive Cretaceous (Hauterivian) sandstone deposited on the Lower Cretaceous Unconformity (LCU). Over most of the CRU, the Kuparuk C is present as a thin transgressive lag, generally less than 5 feet thick. Locally, the Kuparuk C sand thickens on the downthrown side of normal faults which created accommodation space during Lower Cretaceous time. The 'Fiord' fault is a northwest trending normal fault, down to the west, which provided accommodation space for the Kuparuk C reservoir in the CD3 area. The Fiord #1 well has 23 feet of Kuparuk C sand and is located approximately 2700 feet west of the 'Fiord' fault. The lateral extent of Kuparuk C reservoir sands west of the 'Fiord' fault is defined by Fiord #1, #2, and #5 and the CD3-108, -109 and -110 wells. Page 9 ConocoPhillips Alaska, Inc. " . . Application to the AOGCC for the Fiord Area Injection Order November 22, 2005 Colville River Field The Nechelik zone is underlain by interbedded mudstone, siltstone, and very fine-grained sandstone of the Kingak Formation. The underlying Kingak sequence is over 1 ,100 feet thick in the Fiord #1 well. At total depth, the Fiord #5 well penetrated 330 feet of Kingak below the Nechelik zone. Overlying the Kuparuk sand is approximately 90 feet of shale-rich lithology. Directly overlying the Kuparuk C sand is roughly 50 feet of Kuparuk D shale and. 40 feet of Kalubik shale. Between the Kuparuk and Nechelik sands in the Fiord #5 and Fiord #1 wells, there is a wedge of non-reservoir shale and sandstone of the Kingak Formation which thickens to the south. The top of the non-reservoir wedge is the LCU which dips to the north. The base of the non-reservoir wedge is the top of the Nechelik which dips to the south. In the northern part of the proposed pool, the LCU intersects and cuts into the Nechelik zone. In the southern portion of the proposed Fiord Oil Pool at Fiord #1, there exists 376 feet TVD of non-reservoir Kingak interval between the LCU and the Nechelik zone. In the Fiord #5 well, roughly 10,000 feet north-northwest of Fiord #1, the Nechelik and Kuparuk zones are separated by 131 feet TVD of non-reservoir Kingak. At the heel of the horizontal well, CD3-108, there is approximately 190 feet TVD of non-reservoir Kingak separating the Kuparuk and Nechelik zones, but at the toe of CD3-108, almost 8000 feet north-northwest lateral distance from the heel, Kuparuk sand and Nechelik sand are contiguous in the oil column. Kuparuk sand is not always developed on top of the LCU, but at the CD3-108 toe location approximately 22 feet MD (5 feet TVD) of Kuparuk C Sand exists with sand-on-sand contact with v Nechelik zone. The Kuparuk reservoir trap is formed by the Fiord Fault to the east with stratigraphic pinchouts elsewhere. The Kuparuk structure generally dips to the north, and the sand thins westward from the Fiord Fault. The Nechelik zone is truncated by the LCU to the north of the development area and the sand quality degrades to the south and west. Page 10 ConocoPhillips Alaska, Inc. Application to the AOGI for the Fiord Area Injection Order Colville River Field 20 AAC 25.402 (c)(6) Description of the Formation . November 22, 2005 The Nechelik zone sands are a coarsening upward (becoming more sand rich) sequence with the best reservoir quality sandstone near the top of the interval (equivalent to deposition in the shallowest water). Nechelik sandstones are bioturbated and analysis of the trace fossils shows that near the base of the interval most of the deposition is in the shelf setting while at the top of the interval the sediments were deposited in upper lower to middle shoreface settings. Neither water-oil nor gas-oil contacts have been observed in the Nechelik zone. Porosity averages approximately 16% and permeability to air averages approximately 8 md. Average water saturation is approximately 34% in the Fiord #4 and Fiord #5 wells. Original Nechelik reservoir pressure is 3200 psi at 6900 feet true vertical depth (TVD) subsea. The Kuparuk is a fine- to medium-grained, quartz-rich sandstone that contains variable amounts of glauconite and siderite cement. Porosity averages approximately 22% and permeability to air averages approximately 110 md. Average water saturation is approximately 22% in the Fiord #5 well. Geochemical analysis on the reservoir fluids in Fiord #5 (well tests) and Fiord #4 (RFT) indicated that the Nechelik oil and Kuparuk oil are likely the same oil and 0/ were derived from the same source rocks. The Kuparuk oils in Fiord #1 and Fiord #5 are essentially identical and indicate reservoir continuity between Fiord #1 and #5 in the Kuparuk zone. The similarity between the Kuparuk and the Nechelik oils suggests that the two reservoirs are in communication. Pressure-Volume-Temperature test results are summarized in Table 1 for reservoir fluid samples collected in the development area. Gas-oil ratio, relative oil volume, and API gravity data are reported for differential vaporization tests. Table 1 PVT Summary Well Zone(s) Viscosity (cp) Solution GaR (SCF/STB) Relative Oil Volume (RB/STB) Oil Gravity (degrees API) Fiord 1 Kuparuk 0.889 609 1.333 31.3 Fiord 5 Nechelik 0.891 538 1.299 28.6 Page 11 Fiord 5 Commingled 0.786 556 1.310 29.4 Nigliq 1 Nechelik 0.92 556 1.307 30.9 ConocoPhillips Alaska, Inc. . Application to the AOGCC for the Fiord Area Injection Order Colville River Field 20 AAC 25.402 (c)(7) Loas of the Injection Wells . November 22, 2005 A typical well log for proposed injection wells is shown in Figure 3. Page 12 ConocoPhillips Alaska. Inc. · . Application to the AOGCC for the Fiord Area Injection Order November 22, 2005 Colville River Field 20 MC 25.402 (c)(8) Casinq Description and Proposed Method for Testing All underground injection into the proposed Fiord Oil Pool will be through wells permitted as service wells for injection in conformance with 20 MC 25.005, or approved for conversion to service wells in conformance with 20 MC 25.280. A typical well schematic is included as Figure 4. The proposed Fiord Oil Pool will be accessed from wells directionally drilled from a gravel pad utilizing drilling procedures, well designs, casing and cementing programs consistent with current practices in other North Slope fields. For proper anchorage and to divert an uncontrolled flow, 16-inch conductor casing will be drilled and cemented at least 75 feet below pad. Cement returns to surface will be verified by visual inspection. A diverter system compliant with the Commission requirements may be installed on the conductor. Primary, secondary, and general well control for drilling and completion operations will be performed in accordance with 20 MC 25 Articles 01 and 06. Casing and cementing will be performed in accordance with 20 MC 25.030. Surface casing, cemented to surface, is planned at approximately 2400 feet true vertical depth. Intermediate hole will be drilled to the target zone and production casing will be cemented with the shoe in the target zone. Either leakoff or formation integrity tests are planned after drilling 20 to 50 feet beyond the respective surface casing shoe and the production casing shoe. The production casing will be cemented with such a volume to protect any significant hydrocarbon zones. Production and injection holes will be drilled beyond the casing shoe horizontally in the target zone. Slotted liners are planned in the production and injection holes for the Kuparuk zone. The Nechelik zone will be completed with open holes. Except where Kuparuk and Nechelik sands are contiguous, e.g. the toe of CD3-108, operating wells with the Kuparuk and Nechelik zones open in the same well are not planned. Tubing and packer, or other equipment, will be run to isolate pressure to the injection interval consistent with 20 MC 25.412, but the maximum spacing of 200 feet measured depth between the pressure isolation equipment and the top of the injection zone should be waived to accommodate efficient wireline operations down to the pressure isolation equipment. Casing-tubing annulus pressures will be monitored and reported during injection operations in accordance with 20 MC 25.402(e). Automated monitoring of injection rates, tubing and casing-tubing annulus pressures is planned. Prior to commencement of injection, each injection well will be pressure tested in accordance with 20 MC 25.412(c). In the event pressure observations or tests indicate communication or leakage of any tubing, casing, or packer, ConocoPhillips will notify the Commission within 24 hours of the observation to obtain Commission approval of appropriate corrective actions. Commission approval will be received prior to commencement of corrective actions unless the situation represents a threat to life or property. Page 13 ConocoPhillips Alaska. Inc. · . Application to the AOGCC for the Fiord Area Injection Order November 22, 2005 Colville River Field 20 MC 25.402 (c)(9) Iniection Fluid Analvsis and Iniection Rates The water injection plan for the Fiord Oil Pool is based on a single water pipeline between the Alpine Central Facility (ACF) and Drill Site CD3. Seawater will initially be used for water injection followed by produced water or mixed produced water I seawater later in the field life. Production commingling 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. Small amounts of non-hazardous fluids (NHF) occasionally may be blended with seawater and produced water for injection. These NHF include: sump fluid, hydrotest fluid, rinsate generated from washing mud hauling trucks, excess well work fluids, and treated camp waste water. These NHF will normally be injected into the WD-02 Class I disposal well, but will be blended with injection water for enhanced oil recovery (EOR) when WD-02 is unavailable. NHF blended in the entire stream of Colville River Field EOR injection water will yield a concentration of 0.02% of the EOR injection water. Because the Fiord development is a roadless drill site, mixing of fluids collecting in well cellars and secondary containment, almost entirely from snow or rain, and glycol and treated waste water from emergency living quarters and warm storage building with Fiord injection water may be necessary. Normal disposition of these fluids is planned in WD-02, but injection of these fluids into the Fiord Oil Pool will provide EOR. The volume is expected to be less than 2400 barrels per year, or a concentration of 0.04 %. This concentration is not expected to affect the EOR efficiency in the Fiord Oil Pool. The anticipated MI composition available from the ACF is: Component Mol Fraction H2O 0.0001 CO2 0.0056 Nitrogen 0.0098 Methane 0.6276 Ethane 0.1106 Propane 0.1560 i-Butane 0.0271 n-Butane 0.0517 Pentanes 0.0095 C6+ 0.0020 Injection rates will be managed based on voidage for both zones. Individual well injection rates will vary according the reservoir properties encountered. Injection of M I and water will alternate in each injection well. The maximum expected and average injection rates are: Maximum MI Rate Average MI Rate MaxImum Water Rate Average Water Rate (MSCFD) (MSCFD) (BPD) (BPD) Nechelik 10,000 6,300 10,000 1,900 Fiord-Kuparuk 10,000 6,500 10,000 2,200 Page 14 ConocoPhillips Alaska, Inc. · . Application to the AOGCC for the Fiord Area Injection Order November 22, 2005 Colville River Field 20 MC 25.402 (c)(10) Estimated Pressures The MI pressure available from the ACF is expected to be approximately 4000 psi. Due to pressure losses in the distribution system, wellhead injection pressures are expected to be 3800 psi with MI. Injection wells may be choked to lower wellhead pressures to manage injection rate. The seawater injection pressures from the ACF pump discharge are expected to average approximately 2500 psi. Due to pressure losses in the distribution system, wellhead injection pressures are expected to be 2400 psi with water. Injection wells may be choked to lower wellhead pressures to manage injection rate. Page 15 ConocoPhillips Alaska, Inc. , . . Application to the AOGCC for the Fiord Area Injection Order November 22, 2005 Colville River Field . 20 MC 25.402 (c}(11) Fracture Information Modeling of the proposed Fiord Pool indicated injection fluids will remain within the injection zones. Digital log data from the Fiord #5 well were processed to estimate elastic properties and in-situ stress. Actual fracturing pressure of the Fiord #5 well Nechelik zone indicated a 0.69 psi/ft fracture gradient. Maximum water injection pressure will exceed the parting pressure of both the Kuparuk and Nechelik zones. The fracture model indicated that fracturing due to long term water injection will be arrested in the confining zones above and below the Kuparuk and Nechelik. Fractures initiated in the Kuparuk sand could potentially grow down into the Nechelik sand if the interval between the two zones is very thin. However, hydraulic fracturing of the Kuparuk interval is not expected at the planned injection rates. Maximum gas injection pressure could exceed the parting pressure of the Nechelik zone, but is not expected to exceed the parting pressure of the Kuparuk zone. Nechelik zone fracturing due to gas injection is not expected to grow throughout the entire interval. A report on Fiord fracture modeling is attached. Page 16 ConocoPhillips Alaska, Inc. · . Application to the AOGCC for the Fiord Area Injection Order November 22, 2005 Colville River Field 20 AAC 25.402 (c)(12) Quality of Formation Water Water has not been produced from wells in the proposed Fiord Oil Pool area, nor have water-oil contacts been observed in the Nechelik or Kuparuk zones within that area. Salinity was calculated for the Nechelik #1 well in the proposed Fiord Oil Pool area in zones deeper than the proposed injection zones. Using the standard Archie correlation and open hole log data, the salinities in the Sag River (8432- 8480 feet MD) and Ivishak (9420-9460 feet MD) Formations were calculated to be 18,000 and 17,000 parts per million (ppm) NaCI equivalent, respectively. Approximately 10 miles south of the Fiord area, the Nanuk #2 well produced water from the Torok Formation above the proposed Fiord Oil Pool stratigraphic interval. From perforations at 7,048 to 7,108 feet MD, the Nanuk #2 well produced formation water with the following composition: Sodium 7,000 ppm Potassium 150 ppm Calcium 200 ppm Magnesium 0 ppm Bicarbonate 800 ppm Sulfate 0 ppm Chloride 10,600 ppm Page 17 ConocoPhillips Alaska, Inc. · . Application to the AOGCC for the Fiord Area Injection Order November 22, 2005 Colville River Field 20 MC 25.402 (c)(13) Aauifer Exemption Reference No underground sources of drinking water exist beneath the permafrost in the CRU area. See Area Injection Order 188 (October 7, 2004) conclusion 3. The proposed Area Injection Order has an affected area entirely within the CRU area. Wells in the proposed Fiord Oil Pool are planned with surface casing set below the base of permafrost. Annular disposal of drilling waste is planned at Drill Site CD3 after authorization under 20 AAC 25.080. Page 18 ConocoPhillips Alaska. Inc. · . Application to the AOGCC for the Fiord Area Injection Order November 22, 2005 Colville River Field 20 AAC 25.402 (c)(14) Incremental Hydrocarbon Recovery The Fiord CD3 Project will employ a miscible water-alternating-gas (MWAG) process to maximize ultimate oil recovery by miscible displacement of reservoir fluids. This process consists of a multiple-contact miscible displacement of reservoir oil. The MI contacts oil not swept by water injection, and mixes with that oil so that it becomes mobile. This mobilized oil is then pushed to production wells by subsequent alternating slugs of injected MI and water. Through this miscible displacement process, the residual oil saturation is reduced to very low levels in the swept pore volume, with the mobilized oil displaced to the producing wells. By alternating between the injection of MI and water, gas and water interaction in the pore space improves reservoir sweep efficiency by reducing the effective mobility of the MI. The injected water helps maintain reservoir pressure, retards gravity segregation of the MI, and controls gas channeling. By combining the mobilization of unswept oil by the miscible displacement process with the sweep efficiency enhancement of alternating gas and water injection, the MWAG displacement process results in more than an insignificant increase in ultimate crude oil recovery, compared with waterflood alone. For the Nechelik zone, incremental waterflood recovery is expected to be 8 to 12% of original oil in place (OOIP) above primary recovery of 15 to 20%, and numerical compositional simulation supports an incremental recovery factor over waterflood of 12% to 18% OOIP for the MWAG process. Nechelik OOIP is estimated at 60 to 130 MMSTBO. For the Kuparuk zone, incremental waterflood recovery is expected to be 35 to 52% OOIP above primary of 5 to 10%, and numerical compositional simulation supports an incremental recovery of 13 to 19% OOIP for the MWAG process. Kuparuk OOIP is estimated at 20 to 60 MMSTBO. Numerical simulation, tuned to laboratory experiments and PVT modeling, demonstrated that the ACF MI design composition is miscible with Fiord crude oil at initial reservoir conditions, and will significantly reduce residual oil saturations below waterflooding. An equation-of-state (EOS) fluid model was created and validated against laboratory measurements of the Nechelik and Kuparuk crude oil PVT properties. This EOS was tuned to predict the phase behavior of mixtures of crude oil with a variety of hydrocarbon gas compositions. Annualized peak production rates for the Nechelik is expected to be between 10,000 and 25,000 barrels of oil per day (BOPD). Annualized waterflood injection rates are estimated to peak between 18,000 and 40,000 barrels of water per day (BWPD) and MI rates are expected to peak at 12 to 29 million standard cubic feet of gas per day (MMSCFD). Annualized peak production rates for the Kuparuk are expected to be between 4,400 and 15,700 BOPD. Annualized waterflood injection rates are estimated to peak between 5,300 and 18,900 BWPD and MI rates are expected to peak at 3.7 to 13 MMSCFD. Page 19 ConocoPhillips Alaska, Jnc. · . Application to the AOGCC for the Fiord Area Injection Order November 22, 2005 Colville River Field 20 MC 25.402 (c)(15) Mechanical Condition of Wells Within % Mile of Proposed Area Six abandoned wells as shown in Figure 2 penetrate the proposed injection zones within % mile of the injection area: Fiord #1, Fiord #2, Fiord #4, Fiord #5, Nigliq #1, and Nechelik #1. Well Completion Reports (AOGCC form 10-407) and schematics are attached for the five abandoned wells. Three new wells were drilled in early 2005 to develop the Nechelik zone: CD3- 108 was completed as primarily a Nechelik horizontal injector with a thin Kuparuk sand open at toe; CD3-109 and CD3-110 were drilled into the Nechelik zone where production casing was set and cemented above the Kuparuk zone. Well schematics and drilling permit cover letter or Well Completion Report (form 10- 407) are attached for the new wells. Page 20 ConocoPhillips Alaska, Inc. Application to the AOGCC for the Fiord Area Injection Order Colville River Field .~ l ., I - Figure 1 Proposed Affected Area for Fiord Area Injection Order 21 .... Application to the AOGCC for the Fiord Colville River Field !II !II FIORD 4 ,. NECHELlK 1 .. .. ( ~\\\ \ \ ALP~.E \ \. \ \. ~----. MI Figure 2 ProPQsedFiord Oil Pool DeveloþmentV\leUs and ExistingWeHs Page 22 . . Application to the AOGCC for the Fiord Area Injection Order Colville River Field November 22, 2005 Fiord 5 Gr LWD Depth Deep R8$ LWD 0 150 MD 1 100 ~ Q :J .¥ 6840 ~- s... E :;¡~ ro c.u. Cl.G) 6860 ~.. :J ~.5 6876 Top Kuparuk C ~ Kuparuk C 6880 - 6892 Base Kuparuk C (LCU) 6900 .. - ~ ca ~~ 6920 .- G) ~.. z.5 6940 6943 Base Nuiqsut 6960 6980 E 7000 U. ~ 7n~n 7021 Top Nechelik ro C> 7040 C S2 7060 .¥ - =ca 7080 G) c: oCG) u.. G) C 7100 z- 7120 7140 7160 ! 7172 Base Nechelik - 7180 Figure 3 Fiord Type Log Page 23 ConocoPhillips Alaska, Inc. Applica.tion tathe AOGCC for the Fiord Area Injection Order Colvme River Field CD3 - KuparuklNechelik Sand Injector Completion 1 Insulated Conductor to 114' II 4-Y." DB Nipple wI differential pressure-operated injection valve at +/-2000' TVD 9-5/8" 40 ppf L-BO STeM Surface Casing at +/-2400' TVD, cemented to surface 4·%" 12.6 ppf L-80 1ST Mod. tubing Circulating mandrel normally with w/ dummy valve above Packer Production Packer Top Reservoir at +/- 6800' TVD Kuparuk 6900' TVD Nechelik 7" 26 ppf L-BO STC Mod Production Casing @ +1-85° 4":Y:i" ~ interval: open Typical FiordlnjectorWeUSchematic Page 24 . . Fracture Containment Modeling in the Fiord Area Jack Walker September, 2005 . Fiord Area Fracture Containment Modeling . September 2005 Summary Modeling fracture growth in the Nechelik and Kuparuk intervals in the Fiord area with Mfrac software 1 indicated that fractures caused by water and miscible gas injection will be arrested in confining zones above and below the injection intervals. The Alpine injection system has the capability of exceeding the parting pressures of the Nechelik and Kuparuk sands. However, insitu stress contrast is adequate to confine fractures initiated in the sands. Procedure Mechanical properties were calculated from Fiord #5 well logs (VanDeVerg 2005)2 and tuned to the actual Nechelik fracture data collected in Fiord #5. Based on mechanical property trends, 22 intervals between 6147 and 7206 feet subsea were identified including the productive sands. Mechanical properties were averaged over these intervals and used for fracture simulation. Figure 1 shows the mechanical properties plotted with depth. At a depth of approximately 6940 feet (subsea), the Nechelik fracture gradient was 0.69 psilft in Fiord #5 (Braden 1999)3. Mechanical properties logs indicated the Kuparuk sand fracture gradient is slightly higher (0.005 psilft) than the Nechelik sand fracture gradient. Maximum surface delivery pressures are expected to be 2400 psi for water and 3800 psi for miscible injectant. Ignoring friction pressure drop in the wells, these maximum surface pressures translate into bottom hole injection pressures of approximately 5500 psi and 4800 psi for water and gas, respectively. The injection system will be capable of delivering water at pressures exceeding the fracture pressures of Nechelik and Kuparuk sands. The gas injection pressure may barely exceed the Nechelik fracture pressure, but will likely not exceed the Kupaurk fracture pressure. Mfrac was run using 1 % KCI water as a substitute for seawater. Miscible injectant properties were created and named MGAS in the Mfrac fluid library. Leakoff was manually calculated based on reservoir and fluid properties4. Permeability, relative permeability and reservoir fluid viscosity were taken from Fiord #5 core and fluid studies. High injection rates (15,000 BPD for water, 15 MMCFD for MI) were chosen to model greater than planned injection pressure and greater stress on confining layers than that likely to be encountered during planned operations. The modeled rates are 150% of the maximum planned rates. The specific injection rate per foot of interval for the vertical well fracture model was more than an order of magnitude greater than the expected specific injection rates in the planned horizontal injectors. The much higher than expected rate was modeled as a conservative approach to ensure induced fractures will be confined. 2 Fiord Area Fracture Containment.l\Ilodeling Perforations with large flow capacity were vertical well frac was modeled with 1000 perforations (1" injection interval. The perforatedintørval Nechelik sand, and over the entire Kuparuk sand. Kupaurk sands were individually modeled with injection into only one sands. Figure 1 Mechanical Properties Fiord #5 Results Fracturing caused by water injection Nechelikinterval would by the zones immediately above and below the Nechelik induced by water injection may grow throughout the though only the highest quality sands are open at the top of the NecheHik. Nechelik fracturing was modeled injection rate of >100 BPDper foot of much higher than the foot of to 3 Fiord Area Fracture Containment Modeling September 2005 specific injection rate of 2 BPD per foot would yield a much more narrow fracture than the case with >100 BPD per foot specific injection rate. 99 Figure:2 Nechelik Water Injection Case Fracture Geometry Fracturing caused by gas injection into the Nechelik interval will likely be confined to a subset of the NecheHk interval because the delivery pressure is too low to part the lower portion of the Nechelik. Figure 3 shows the Nechelik gas injection case plotted with an expanded depth scale. Gas injection into the Kuparuk sand will likely have insufficient pressure to propagate fractures. Water injection into the Kuparuk sand will be arrested in the zones above and below the Kuparuk sand as shown in Figure 4. Kuparuk water injection would be confined to a height of approximately 90 feet height for the 15,000 BPD case based on the vertical well model, or a specific injection rate of more than 800 BPD per foot of open interval. However, water injection at the planned specific rate of 5 BPD per foot of interval open will not propagate a fracture in the Kuparuk sand. If the Nechelik and Kuparuk sands are less than 40 feet apart, injection into the Kuparuk via a vertical well at maximum delivery pressure and extremely high injection rate could potentially break into the Nechelik. 4 Fiord Area Fracture Containment Modeling Figure 3 Nechelik Miscible Injectant Case Fracture Geometry September 2005 Figure 4 Kuparuk Water Injection Fracture Geometry 5 . Fiord Area Fracture Containment Modeling . September 2005 Conclusions 1. Fracturing the Nechelik sands is possible with the delivery pressure and rate expected to be available at Drill Site CD3. 2. Fracture growth caused by injection into the Nechelik sands will be confined to the Nechelik sands. The fracture model indicated that fracturing induced by miscible injectant will not grow throughout the Nechelik interval. 3. Fracturing the Kuparuk sands is not expected at the planned injection rate. Fracturing the Kuparuk sands is possible with extremely high injection water rates at the maximum delivery pressure. 4. Miscible gas injection pressure is not expected to exceed the Kuparuk minimum horizontal stress. 5. Fractures initiated in the Kuparuk interval by extremely high water injection rate would be arrested in the Kuparuk D Shale above the Kuparuk C Sand. Fractures initiated in the Kuparuk sand could potentially grow into the Nechelik sands if the interval between the Kuparuk sands and Nechelik sands is much thinner than that interval at the Fiord #5 well. 6 . . Fiord Area Fracture Containment Modeling September 2005 References 1 Meyer & Associates, Version 5.2.1209, Natrona Heights, PA 2 VanDeVerg., fiord_5pb1_tops_model.xls 3 Braden, J., "Fiord #5 Testing and Stimulation Summary", April 10, 1999 4 Gidley, et. aI., Recent Advances in Hydraulic Fracturina SPE Monograph Volume 12, 1989, pp. 147-157 7 STATE OF AlASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG I " . '. . , 1 Slatus of W" . ( ClassJicalion of Service W" OIL D GAS D 2 Name 01 Operator ARCO Alaska. 100 3 Address P.O. Box 100360, Anchorage, AK 99510-0360 .. Location of we. at surface ABANDONED [!] SERVICE D SUSPENDED D 526' FSl, 420' FWL. SEC 2. T12N, R5E, UM AI. Top Producing Interval !>VA AI. T oIal Depth 625' FSL 1105' FEL, SEC 3, T12N. R5E. UM 5 Elevation in feet (Indicate KB. DF. etc.) 16 lease Designation and Serial No. ADL 372104 14 Dale ColTt/. . Susp. or Aband. 04/18192. 19 D~onalSwvey YES ŒJ RKB 38' ABOVE SEA LEVEL 12 Dale Spudded 13 Date T.D. Reached 02104192. 03/18192. 17 ToIal Depth (MD+ TVO) 18 Plug Back Depth (MD+TVO) 10,250' MD. 9973' TVD SURFACE NOD 22 Type Electric or Other Logs Run MLUDLUGRlCHT ZDUCNlDEL 2ISL 7 permi NI6róer 91-147 8 API Nurm. 50-103-20162 9 Unit or Lease Name NA 10 We. Nurrber FIORD '1 11 Field and Pool EXPLORATION 1'5 Water Depth. iolfshote It6 No. of~ NA feel MSL NA /20 Depth where SSSV set /21 Thickness of pennafrœt NONE feet MO MAJ. DlPlOG. VSP. SBTICBTIGR. USI CASING. UNER AND CEMENTING RECORD SETTING DEPTH MD 23 CASING SIZE 20" WT. PER FT. 91.5# 72# I GRADE H-4O L-BO 17-112· HOLE SIZE 26" OOITOM 108' 2388' TOP SURF SURF 13-318· 9-518· 47# SURF 7981' 12-1/4· L·BO 24 Perforations open to Production (MD+ TVD of Top and Bottom and intelVaf. size and nurrber) 25 SIZE N/A !>VA CEMENTING RECORD PERMAFROST GROUT 1075 SX PF "E",500 SX CLASS G 100 SX TYPE C TOP JOB 4000 SX CLASS G TUBING RECORD DEPTH SET (MD) PACKER SET (MD) AMOUNT PUllED 26 ACID. FRACTURE. CEMENT SQUEEZE. ETC DEPTH INTERVAL (MD) I AMOUNT & KI~ OF MATERIAl.. USED · ... ._hod ..~..ons sur"'" 27 Date First Production PRODUCTION TEST I Method of Operation (Flowing. gas ill. ete.) PRODUCTION FOR OfL·BBL GAS-MCF TEST PERIOD .. CALCULATED OIL-BBL GAS-MCF 24·HOUR RATE.. Date of Test Hours Tested Flow Tubing Press. Casing Pressure 28 CORE DATA Brief descrþlion of lithology. porosity. fractures. apparent dips and presence of oil. gas or water. Submit core ch~. " Core data and fog Information to be submitted by Exploration Department Form 1 G-407 Rev. 7-1-80 cc:uTN.E)OO REVERSESœ WATER-BBL CHOKE SIZE I GAS-OIL RATIO OILGRAVIìY-API (con) WATER-BBL SuIJmi in duplicate '(;;,' MRY-21- 92 12: 51 I~U/CI/NV/DRILLI~G TEL NO: 88e. r "898 P02 ...,.,~ ~..'~ ,. ,."._,.\_" '...···r...'..........,··.·"'.... '. .. ~ .. t. ... . . œa a.:.;a.wNM FOfU.1I:W 1ES1I HME t.EAS. ŒPTH 11u: 'IERT. œ:P1H ~ InttmJ telMd. þ!'Man data, .. ..... NCCWI'd and~. GOFf. and fIlM of tldl phaM. 'FCftIIIIon....... be .....,b¡~~ .... AllIIOhØ 11. USTcFÄTT~ ,., A 8C1Ø1AtIC:. GmO,fØ'óÀtŒ OÆAf.mNf It. . f ht"'br'Qirfi~ that ""f(Jr~ II IIUt ãnd corrICIlO .,. Nil 01 mi ~ .- J1øl!!i~----- fll" ~.nA,IJ'IG$"~ 0&1. ¥¥f2 INSTRUCTIONS General: This form Is designed for submitting 8 complete and correct wen completion report and fog on aft types of lands and leases in Alaska. Item 1: CrassrflCStion of Service WeDs: Gas In¡setion. water Injection. steam iniectIon, ait Injection. saft wafer disposal, water supply for inJection, observation. Injection for in-situ combustion. Item 5: Indicate which elévation is used as reference (where not othelWise shown) for depth measurements given in other spaces on this form and in any attachments. . Item 18 and 24; It this wen Is completed for separate production from more than one interval (multiple completion), so stafe In item 16. and in item 24 show the producing Intervals for only the Interval reported '" Ilem 27. Submit a separate fonn for each additional interval to be separately produced, showing the data pertinent to sooh intelVal. Item 21: rndioata whether from ground lever (GL) or other elevation (DF. KB. etc.). ftem 23: Attached supplemental records for this well should show the deraifs of åny multiple stage cement- Ing and the Socation of the comenting tool. Item 27: Method of Operation: Flowing, Gas lift, Rod Pump, Hydraulic Pump, Submersible. Water In- jectlon. Gas Injection, Shut-In, Other-exp/ain. 'tem 28: If no cores taken, inc:Øoate -no.,,-. FotM 10.407 . . ( '- FIORD #1 PIA SCHEMATIC (All depths RKB, 31' above ground level) :1.........................~ ............................ .......:.:.:.:.:.:.:.:.:.:.:.:.:.:.:.:.:....~.... ................. ................. ~ ;i~~~r~:,'á;·~~~; TOC ~ 170' (12 bbls cmt) :~<~<~c~c~~ ~ ~ ~. ~ ~~:~:~l 4- Cmt retainer @ 250' . d '1"1"1"1"1"A~" ~ '1'1~1~1~1~11 11 12 bbls emt ; 'II' yo( yC yc.,c yo( yo( ~ Gravel 20- Csg shoe @ 108' 9-5/8- csg cut off @ 260' CBL indicates TOC in 9-5/8- X 13-3/8- annulus @ 350' , 0.2 ppg brine 1 bbl cmt 11.3 bbls emt 10.2 ppg brine 10.2 ppg brine 2.2 bbls emt 18.2 bbls emt 10.6 ppg brine 2.3 bbls emt 25.2 bbls emt 10.2 ppg mud Balanced plug Isolates gas- bearing interval 9830' - 9950' 10.2 ppg mud þ .. I . fA'rirA'riririr~ i"~"r"~' .(. èotC è'" èA è":roC é" . 'I~1~1~1~I~lr~ ~~~~~~~~l~~~~ . ~"''''''-i.. . .c C.& c"" c'" èot; «,oil; c~ ·1:1~1~1rl:1~~ .(~~ '.t "A ..1..1..Þl..... . ':c~:c~~~1~1~1~.- A~"'~A~ ~ ~ ~ . ·¡c~l~j~j~j~l~: . 1:,1~1~1~1~1~J (~¡~ñ;' . '.i ~.a~i:i:.t~.-~~; ~·1'!:1..1..1..1..1.. . ~ lf1f1flf; . ¡C~lrl~1~~ 1:-1rl:-1:,~ ~~~r~:-~r~ . I Þ 1 I I ~c.cc""c..c.c; . 1~lr1~1~~ . "~rl~lrl~; lr1r1r~r~ '}r~'Y~Y') ~: . I k____1 . Ground Level (31' RKB) 13-3/8- & 20- cut off @ 50' ......~ 13-3/8- Csg shoe @ 2388' · TOC @ 6786' · Cmt retainer @ 6800' · Perfs 6876'-6906' · · · Bridge Plug @ 6940' Casing leak @ 6951' TOC @ 727rJ I · Cmt retainer @ 7300' Perfs 7325'-7362' · TOC @ 7898' Cmt retainer @ 7930' 9-518- Csg shoe @ 7981' SOC @ 8287' TOC @ 9618' BOC @ , 0,050' . TD @ 10,250' ·... ( . STATE OF ALASKA .- ALASKA OIL AND GAS CONSERVATION COMMíSSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG ~\ 1 Status of Well ClasSIfication of Service Well OIL 0 GAS 0 2 Name of Operator ARCO Alaska, foe 3 Address P.O. Box 100360, Anchorage, AK 99510-0360 4 Location of well at surface SUSPENDED 0 ABANDONED !KI SERVICE 0 7 Pennlt Number 94-09 Permitf94-()61 SA 8 API Number 50·103-20201 9 Unit or Lease Name 2126' FNL, 1314' FWL. SEC 24. T 12N. R 5E. UM At Top Producing Interval NA At Total Dep1h 934' FSL, 835' FEL. SEC 14, T12N, R5E, UM _ 5 Elevation In feet (indicateKB. DF. etc.) RKB 42' 12 Date Spudœd 11-Feb-94 17 Total Depth (MD+TVD) 8400' MD, 7214' TVD NIA 10 Well Number FIORD #2 11 Field and Pool WILDCAT 13 Date T.D. Reached 02-Mar-94 18 Plug Back Depth (MD+ TVD) SURF /6 Lease Designation and Serial No. ADL 372106 14 Date Comp., Susp. or Aband. 03/07194(P & A) 19 Directional Survey YES ŒJMWD NO 0 115 Water Depth. If offshore /16 No. of Completions NA feet MSL NA 120 Depth where SSSV set 121 Thickness of pennafrost NA feet MD NA APPROX 22 Type Electric or Other Logs Run DIUGR. SOT. DIUMSFL.DSIIGR. FMIIGR. SWC 23 CASING. UNER AND CEMENTING RECORD SETTING DEPTH MD CASING SIZE 16' 9.625' wr 62.58# 53.5# GRADE B L-SO TOP SURF'. SURF 81M 110' 2231' HOLE SIZE ceÆNrFEOORD 20' 250SX AS I 12.25' 259 SX AS III, 447 SX CLASS G 24 Perforations open to Production (MD+ TVD of Top arid Bottom and interval. size and number) NA 25 SIZE TUBING RECORD DEPTH SET (MD) PACKER SET (MD) NA' 26 ACID. FRACTURE, CEMENT SQUEEZE. ETC DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED 27 Date First Production PRODUCTION TEST "'MethodofOperation (Flowing, gli$lift, etc.) PRODUCTION FOA OIL·BBL GAS-MCF TEST PERIOD Ë .... '" CALCULATED 24~HOUR RATEË Date of Test Hours Tested WATER-BBL Flow Tubing Casing Pressure Press. 28 CORE DATA Brief desCription of lithology. porosity. fractures. apparent dips and presence of oil. gas or water. Submit core chips. "To be sent under sepal'lltll cover by Exploration Geology Form 10-407 Rev. 7-1-80 coNnNUED ON REVERS~SlI5E Submltln.dlJ!l"c::a~.. \: ..... . e-- ( .... Casing cut and backfilled 3' below ground level per 20 AAC 25.105 (k) ~A ^ A A A A A A ^ A A A A A A A 4 4 4 A A A A A 1 ~4 4 4 ^ A A ^ A ^ ^ 4 4 A ^ 4 ^ A ^ A A 4 A A 41 ..\:":-:':Ç.~.~.~ ,. ,. ,... .. ,. ,. ,.,. ,. ,. .~.~..~,:~:":-\. P&A Cap Marker 3' below ground level ~t~~t~~~~~~~~;~~; ·:~~t~~~?if~~ per 20 AAC 25.105 (i1) @~~~~~~l~lt:~ i~~~~~@~i~~ s~rface Plug ................ ......"....... Sndge Plug @ 300' . ~~&i:~ritf@ :::~i~{t~~~}~g 16 , 62.58#, PES .....~.......... .........~..... (110' R~) Ä/ ¡II! ~ll '?~; .;.;.;. "..: ". . 1''¡'1''¡'1''¡'~ 11.2 ppg . 1''¡'1''¡'1''¡'~ M U d ...~....!\ .~. ·t~ ~. ~ CON FIDENTIA: TOC @ (2075') Cement Retainer @ 2175' per 20 AAC 25.105 (g2) Casing Shoe Plug BOC @ (approx.2331') per 20 AAC 25.105 (k) 11.2 ppg Mud per 20 AAC 25.105 (12) 20 AAC 25.105 (I) waived TOC @ (approx.2400') 20 bbls Hi-Vis Abnormal Pressure C30 (2890'-3200') BOC @ (3300') per 20 AAC 25.105 (k) 11.2 ppg Mud 20 bbls Hi-Vis TOC @ (7436') Hydrocarbon Kuparuk/J4 (7794'.7994') BOC @ (8044') Show ARCO FIORD #2 PLUG AND ABANDON SCHEMATIC [ill = Lead Cement ~ = Tail Cement . = Cement Plugs E:1 = Gravel Fill per 20 AAC 25.105 (f1,1) per 20 AAC 25.105 (k) I : 11.2 ppg I Mud !._-------------~ TD @ 8400' MD WLM 4/4/94 , , ,KA OIL AND GAS CONSERVATION COM'ION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1. status of well Classification of Service Well Oil 0 Qas 2. Name of Operator ARCO Alaska, Inc. 3, Address P. O. Box 100360, Anchorage, AK 99510-0360 4. location of well at surface o Suspended o Abandoned 0 Service 0 7. Permit Number 99-016 8. API Number 50-103-20289 9. Unit or lease Name 254' FSL, 842' FWL. Sec. 22, T13N. R5E..UM At Top Producing Interval N/A 10. Well Number 572'FSL, 102S'FWL, Sec. 22, T13N, R5E, UM At Total Depth 572' FSL, 1025' FWL. Sec. 22. T13N, R5E, UM 5. Elevation in feet (indicate KB, OF, etc.) 16. lease Designation and Serial No. KB 28'. Pad 1.6' ADl 364472 ALK 4544 12. Date Spudded 13. Date T.D. Reached 14. Date Comp.. Susp. Or Aband. 115. Water Depth, if offshore March 2, 1999 March 9, 1999 March 13, 1999 (P&A'd) N/A feetMSL 17. Total Depth (MD + TVD) 18. Plug Back Depth (MD + TVD) 19. Directional Survey /2. O. Depth where SSSV set 7171' MD/7138' TVD P&A YES 0 No 0 na feetMD 22. Type Electric or Other logs Run MWD GR/Resistivity, Platform Express/CMR, Dipole Sonio, RFT, Sidewall Cores 23. CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD' TOP BOTTOM FIORD #4 11. Field and Pool Colville River Unit 16. No. of Completions na 21. Thickness of Permafrost 1195' MD/TVD CASING SIZE 16" 9.1$25" WT. PER FT. 62.5# 40# GRADE HOLE SIZE CEMENTING RECORD AMOUNT PUllED H~40 L-80 Surface Surface 108' 1973' 24" ApproX. 200 cF 410 sx AS 1.11 plus 230 Sx Class G + additives na na na na 12-114" 8-112" o 24. Perforations open to Production (MD + TVD of Top and Bottom and' interval, size and number) 25. SIZE TUBI NG RECORD DEPTH SET (MD) PACKER SET (MD) . Plugged & Abandoned all mud logged sho~- no perforations 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC: DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED P&A procedures approved by Blair Wondzell 3/11/99, See P&A Addendum for specifics. 27. Date First Production N/A Date ofT est Hours Tested PRODUCTION TEST Method of Operation (Flowing, gas lift, etc.) Plugged & Abandoned Production for OlkBBl GAS-MCF Test Period> Calculated Oll-BBl WA TER-BBl CHOKE SIZE IGAS-OILRATIO Oil GRAVITY -API (corr). N/A .Row Tubing Press. 28. Casing Pressure GAS-MCF WA TER-BB.l 24-Hour Rate> CORE DATA Brief description of lithology, porosity, fractures, apparent" dips and pressence òf oil. gàs or water. Submit core chips. See attached information Form 10-407 Rev. 7-1-80 , 29. GEOLOGIC MARKERS NAME MEAS.[)EPTH Albian B 5732' Albian C 6201' Albian D 6280' Base HRZ 6545' K1 6609' Kuparuk C 6686' Nechelik 6695' CONTINUED ON RÈVERSE SIDE . (--> Submit in duplicate 30. FORMATION TESTS TRUE VERT. DEPTH Include interval tested, pressure data. all fluids recovered and gravity. GOR, and time of each phase. 5672' 6140' 6320' See Attachments 6482' 6549' 6622' 6631' 31. LIST OF ATTACHMENTS Logs, Core descriptions, geologic tops, daily summary, mud I<>g, & directiomil survey 32. I hereby certify that the following is true and correct to the best of my knowledge. Signe~ rr¡~ Title ExolorationlTarnlTabasco Team Leader 4/13/'i'1 Date Prepared by Sharon Allsup-Drake 4/8/99 INSTRUCTIONS General: This form is designed for submitting a complete and oorrect well completion report and log on all types of lands and leases in Alaska. Item 1: Classification of Servioe wells: Gas injeotion, water injeotion, steam injeotion, air injeotion, salt water disposal, water supply for injection, observation, injeotion for in-situ combustion. Item 5: Indioate whioh elevation is used as reference (where not otherwise shown) for depth measurements given in other spaoes on this form and in any attaohments. Item 16 and 24: If this well is completed for separate produotion from more than one interval (multiple oompletion), so state in item 16, and in item 24 show the produoing intervals for the interval reported in item 27. Submit a separate form for eaoh . additional interval to be separately produoed, showing the data pertinent to suoh interval. Item 21: Indicate Whether from ground level (GL) or other elevation (DF, KB, eto.). Item 23: Attaohed supplemental records for this well should show the details of any multiple stage oementing and the looation' of the cementing tool. Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulio Pump, Submersible, Water Injeotion, Gas Injeotion, Shut-in, Other-explain. Item 28: If no oores taken, indicate "none", Form 10-407 I¡mmm ~!!¡\!I!'i¡ :mmm¡ J:I¡,I!I!I .,i,·:,,',,':,.'I.',I.:,'.:,.',i, ><,mmm :__:~ j1i@¡¡¡ :immm 'J:::;):,:: I .rd #4 P & A Schemati. ';¡'¡"I!L ....'..,. mmm, 16" Conductor to 115' ~!!!,(~': 33' - 300' 21 Bbls of 15.7 ppg AS1 slurry 1920' EZSV Retainer 9-5/8" 40 ppf, L-80, BTC Surface Casing @ 1973' MD I 2440' TVD cemented to surface 'J;;:!:):; Jllllill!J Iwmm Iliill!!!i .....,"" ',-,J. ".J Squeezed 10.7 Bbls below the retainer and dumped 3.8 Bbls on top of retainer utilizing 15.8 ppg Class G Cement · 2850' - 3100' 23 Bbls 15.8 ppg Class G Cement · 3100' - 3385' 25 Bbls Hi Vis 10.6 ppg mud pill · 4000' - 4300' 30 Bbls. 15.8 ppg Class G Cement · 4300' - 4585' 20 Bbls Hi Vis 10.6 ppg mud pill · 5500' - 630Q' 67 Bbls. 15.8 ppg Class G Cement · 6300' - 6500' 14 Bbls Hi Vis 10.6 ppg mud pi,lI . 6500' - 71"(0',53 Bbls. 15.8 Class G Cement . TO @ 7171' MO/7138' TVO »- STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG . .- , 1. Status of well Classification of Service Weli Oil 0 Gas 2. Name of Operator ARCO Alaska, Inc. 3. Address o Suspended o Abandoned ø Service 0 P. O. Box 100360, Anchorage, AK 99510-0360 4. location of well at surface 739' FNL, 437' FEL, Sec. 32; T13N, R5E, UM At Top Producing Interval 353' FNL, 177' FWL, Sec. 33, T13N, R5E, UM AtTotal Depth 353' FNL, 177' FWL, Sec. 33, T13N, R5E, UM 5. Elev~tion in feet (indicate KB, DF, etc.) 16, lease Designation and. Serial No. ~KB 28', Pad 6.. feet ADL 364471 ALK 4480 12. Date Spudded 13. Date ToO. Reached 14. Date Comp., Susp. Or Aband. March 14, 1999 March 31,1999 April 23,1999 17. Total Depth (MD + TVD) 18. Plug Back Depth (MD + TVD) 19. Directional Survey 7490'MDI7400'TVD surface YES ø No 0 22. Type Electric or Other Logs Run LWD GRlResistivity plus SWS Platform ExpresslCMR, Dipole Sonic, RFT's, Sidewall Cores 23. CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD TOP BOTTOM Surface 112' Surface 1981' Surface 7484' 7. Permit Number 99-020 8. API Number 50-103-20292 9. Unit or lease Name NIA 10. Well Number FIORD #5. 11. Field and Pool Colville River Unit 115. Water Depth, if offshore NI A feetMSL 120. Depth where SSSV set NI A feet MD 16. No. of Completions 1 21. Thickness of Permafrost 1250' MD CASING SIZE 16' 9.625' 'NT. PER FT. 62.5# 40# 26# GRADE H-40 L-80 L-80 HOLE SIZE CEMENTING RECORD AMOUNT PUllED 24' 9 cu yds High Early 480 sx AS3 plus 230 sx CI G 400 SX 13.0 ppg ci G plus 245 sx 15.8 ppg CI G 7' 12-1/4' 8-112' ~--,._---- 24. Perforations open to Production (MD + TYD of Top and Bottom and interval, size and number) Wellbore has been P&A'd NecheJik Interval wI 4-1/2" 5 spf 7024' to 7044' MD (6934' to 6954' TVD) 7044' to 7064' MD (6954' to 6974' TVD) Kuparuk Interval w/2-1/8' Enerjets @ 4 spf 6880' to 6900' MD (6790' to 6800' TVD) 25. TUBING RECORD SIZE DEPTH SET (MD) 3~1/2' 9.3# 8 rd EUE 6830' MD TT I 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED PACKER SET (MD) 6713' MD 7024' to 7064' MD 248,000 Ibs 16/20 ISP Proppant 27. Date First Production .April11,1999 Date of Test Hours Tested' PRODUCTION TEST Method of Operation (Flowing, gas lift, etc.) Without lift and with nitrogen lift from annulus. First test with Nechelik only, second test with Nechelik & Kupanik Production for Oll-BBl GAS-MCF WATER-BBl CHOKE SIZE ¡GAS-Oil RATI.O Test Period> 10,053 4657 561 128 (open) 463 Calculated Oll-BBl GAS-MCF WATER-BBl Oil GRAVITY - API (corr) 24-Hour Rate> 1227/2475 55111165166/40 30.5 deg API CORE DATA 4/11-4120 Flow Tubing 180 to 540 28. 65.5 hrs & 65 hrs Casing Pressure 400 to 870 Brief description of lithology, porosity, fractures, apparent dips and pressence of oil, gas or water. Submit core chips. See Attachment Form 10-407 Rev. 7-1-80 CONTINUED ON REVERSE SIDE Submit in duplicate ... .~ ¡ . .. e· 30. GEOLOGIC MARKERS FORMATION TESTS MEAS. DEPTH TRUE VERT. DEPTH Include interval tested, pressure data, all fluids recovered and gravity. GOR. and time of each phase. NAME See Attachments 31. LIST OF ATTACHMENTS 32. I hereby certify that the following is true and correct to the best of my knowledge. signed "?~ Y1cvp~ Paul M~~,{¡ . Title. DrillinCl Team Leader Date 6,íZ4/qq Prepared by Sharon Allsup-Drake INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Item 1: Classification of Service wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion. Item 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other spaces on this form and in any attachments. Item 16 and 24: If this well is completed for separate production from more than one interval (multiþle completion), so state in item 16, and in item 24 show the producing intervals for the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. Item 21: Indicate whether from ground level (GL) or other elevation (OF, KB, etc.). Item 23: Attached supplemental records for this well should show the details of any multiple stage cementing arid the location of the cementing tool. Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Watèt Injection, Gas Injection, Shut-in, Other-explain. . 'tern 28: If no cores taken, indicate "none". Form 10-407 :' . ARCa <> Subject rT () I? f).:#-. ç-. P fA ....C~P~~_ L/ r I By TJ ß . . Calculations Cha e File Sheet number @ of (Í) . .~.'~ ~... " I¿ ·C~dlAc~ e k ~~~.. . J I tJ ;' j21t1j "..""',,,<. " ""~"- D Î J ..'" "'" ',- " 1.Q~",^~l""S / ~ }lÇ?:l J#;J ...'...... '-''-. ~"'~.; ...., . . ". '- -', ',-- "- . 'f 7i S;.'Þ7:2:~;Y {2r,'"'5 .e. J1~¡ ht¿; C¡,.. t ,,¡e¡ 80 rx, If>:] I'lkJ -alO.r~ CI (;) Date . 'I1~/1t .' / // / . / ' / ! ./ ;/ ,. />,/,...... ~ ] V,: 1.1. "" O.OOh}- iy . J'/2.;I.'1- '1J~,;,ke ().02f,.V, ?'- ^ r~' 4/11",k"r!. a)o 2.&2.', ) ";>{o Ate.. O~O.J&?. l:,,,f ~"~ fJ/ì e JIO¡ i I ! , ---J " 9 r;( Jl ì- "JtÞ\I.o-lç .x" . i.··· h /(?X1<,:::_ '1:3 loiolJ vI-. If S I Gw..t=v.l ./ GLlM.e 21f'17- / e ~ '\ ;' . 7 t) c L\~Je .J ro.O þt ¡J IJ (J '.'; ¡-.{J.T. de ~.~l.æ jn.~(). . . "~~'>: . ." ..... .'..., 6 u~. <!. ?tP2t '. ',~~ .'-, " , '- ", "'),. . '. >~~·X· . . ~. .' ;' '. '\ ~L lA1.e ¡. ~I(}Z '; :\~ 1.:--, . q.L~<! ç; ~~3"" ';':~ <~. ~~~ / ./ L x' Nly.,-k.. @. ~,¡,. ...... ',/ . I',/'~ ./ 7VLT'-;~G... ,c,Ø'/ "'ð \" r"" TtX.@dno/X ~ ;. /J-Iß~lv e'· G' r/2//I(¡) i ¡f'~O.q b~/ ~....., .'1-......"-".... I...., .. . .... .... .' . ,/ IJ " ." r~'r¿'J( ~ (,;&JO'Þt\() /' ,. . ./) . {'j j' ,., i . /, r~Y'~;\r-L . 7<J2Y· . n ,"}o~. 't¥!J It (~f j .-. -.. -,,- ~ ,. ,,_. .... . ~ ~tl.l~~ ".-.- '-'''...~.'.. . ,"... ..' ---,-~." '. .." . '.' . .:,~.:...;-~------,-_.._-,-;-,--.. ".'. ,~;..:,,:l/ ~~_'?~~i -~~~t'¡ #~l ;~\tj """'1 ,n- ,',. '-' .'".~ ",- '~;k'~ f~if~ ~:~~~ ~ÞJ~:1 " . ,,', ". .'" Jf:j'~í .".,'j ;:;~~'.f '....,,] ./! ,..,. :tð ~~K::t ;;(~~y~ .,.' :. .~ ...-. ;f;:}j , ''''1 ~~:,:¿ 1 r~i . ·.·.·f \~ ~';" .,,'. :.':-;¡ '. '1 ;(i~ :)~{ ~:I.;j .:';," ii?~ ~} .:~ ."... ! 'fif~ ,J:t ~-;,j ::::i1 >,1 1 '. ~ ~. i:"" ;oj A ;":i . ~"I , ¡ .. j ~ " j I .¡ ¡ , ,j ) '.j ì . .. ¡ > ~ ..i . ~ ·i. .~_~u,_~u "~'~~ll~ffi;,:~t~ .~ .STATEOF ALASKA . ~~>;::,~ ' . ~ ALASKA¡f,;;JAND GAS CONSERVATION¡91:~;;Ûf1ISSI0N . VI ELL COMpLEïIO'ltJ OR RECOf¡'PLETIO'I?F~r:PORT AND LOG ~ ~ ! . Ie -.----..--- ----- --_._~---- ----~----- - ._._- - ._- .-.--- - -_. - - -- --- . 1. Status of Well Classification of Service Well OllO SUSPENDED 0 GASO ABANDONED 5è SERVicE 0 r 2. Name of Operator 7. Permit Number ~ohio Alas_ka Petroleum Company· 3. Address 81-149' 8. API Number 50- 101-?OO?O ' 9. Unit or lease Name P ou clL.6=61.1.. .-Anchor age, 4. location of well a1 surface 814' WET... 1<'2340' El{f ' At Top Producing Interval A1;¡ska-:....99502 NSL, Sec. 18, T12N, R5E, UPM LOCATIONS VERIFIED At Total Depth Surf.~ vertical well B.H._ 5. Elevation in feet (indicate KB. OF. etc.) /6. lease Designation and 'Serial ~o. KBE = 43.82' AMSL ADL 25538 ' 12. Date Spudded 13. Date T.D. Reached 14. Date Comp.. Susp. or Aband. 115.: Water Depth, if offshore 116. No. of Completions ~7 /82 3/7/82 3/17 /82 ~ n/a feet MSl n/a 17. Total Depth (MD+TVD 18.Plug Back Depth (MD+1VD 19. Directional Survey I 20. Depth where SSSV set 121. Thickness of Permafrost' 10018' MD&TVD Surface YES 0 NO Gè . n/ a feet MD . 1150' , . 22. Type Electric or Other logs Run VSP, Borehole Graviometer, sidewall cores SP/DIL/GR/BHCS. FDC/CNL/GR/CAL. HDT. DIL/GR. BHCS/GR. FDC/CNL/GR. NGT. RFT, BHCS/GR/DIL, 23. CASING. LINER AND CEMENTING RECORD 'SETTING DEPTH MD GRADE TOP BOTTOM ConductorSllrf;¡ce 91' L-80 Surface 2700' T~80 Surface 8559' 10. Well Number Nechelik III 11. Field and Pool Wildcat (exploration) CASING SIZE WT. PER FT. 20" 104/1 13 3/8" 72/1 9 5/8" 4711 CEMENTING RECORD AMOUNT PUllED 371 cu. ft. Permafrost II 2352 cu. ft. Permafrost II 1150 cu. ft. Class G; 130 cu.ft. Permafrost C HOLE SIZE 26" 17 1/2" '12 1/4" 24. Perforations open to Production (MD+TVD of Top a,"!d Bottom and intèrval, size and number) TUBING RECORD DEPTH SET (MD PACKER SET (MDI 25. SIZE N/A 1 ¡ ¡ ! ·i ¡ ¡ N/A . ;- :" : ~ 26. ACID. FRACTURE. CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MOl AMOUNT & KIND OF MATERIAL USED, See Well History . .' --- . . ¡ 1 27. PRODUCTION TEST I Metho<;! of Operation (FIO~i:,9.. g~S Ii~t, etc.). '. .~. PRODUCTION FOR Oll-BBl GAS-MCF WATER-BBl TEST PERIOD":. CALCULATED '.... Oll-HBl. 24-HOUR RATE .,... i· t.' l' ~ Date First Production .. r.· Date of Test Hours Tested CHOKE SIZE GA;S-~Il R.ATIO Oil GRAVITY·API !corr) Flow Tubing· Press. Casing Pressure . GAS·MCF WATER-BBl ,. . 28. CORE DATA -Brief description of lithology. porosity. fractures, apparent dips and presence of oil. gas or water. Submit core chips~ See enclosed Well Data Sheet .(' .~ r~' . : :rJ ~H)~..~~~ I. Of ~r Ußt~~'~ 'I;J TiAl·, I f I!!'<>. fi"'" .".. "òI; 'iI!> ". ~..,.. L ~. APR 1 6 19'82 ' \ ~!1 ~., ~ ~ ~ \ ~ ß !! -~ . " "~Ui:tiJ~~:I· t. 1\!3S~Oi/&GasCon$.comm¡SSI6" , '.' " .' . '. t..nchorage . 11_ , , "t r ¡ RECEIVEP Form 10-407 Rev. 7-1-80 Submit in d~plicate f CONTINUED ON REVERSE SIDE r: --;~' '·1 ' ";1 '~ ~i , , /1~ '1 _,"1 :';t "."! ,.41 ~'~1 ~t 1';,] ~ :' ~ .~ .;. :rl ~:,ì .} }~ .'~ ,. ¡~ /~. ~\ ~~¡¡ ~j ti -i ;~~ ".1 :.1 "-Ì ~ m l ;~ ~~ ~ ,. '. f ; , ~1 ~ ~ . 1 j ~ j I , I ~ i I '~',' ¡ ~ - .,.~Yl - \ - \ . GEOLOGIC MAÀKÈ~ '" '~:"'" ':;: ,C"." '1:;:,:i'~}'~;'f:IT-:. ~ .~.......,~, """~*'-~;:':;;"~~~;;~:"\: , ' FORMATION TESTS 30. NAME Include interval tested, pressure data, all fluids recovered and gravity. GOR, and time of each phase. MEAS. DEPTH TRUE VERT. DEPTH Lower Cretaceous 6590' . 6590' '. No DST's run in well Permo-Trias. ¡' 8436' , 9908' ; 8436' Carboniferous .9908! ~ :' ¡.. ~ , - LO~AIl.:glr\r~ IT 'I Ö' t· .~ - ~ g G ~ ...1SÕ ~\ , . .;~~,; { o.!~ ~~.j II.'. .. . £.l 1j ~ ~ ~~ ::·,·"a \Ii l1,i . ~ ~ r'\ r IF r~: ~ g ":-' fr" I \(" ~i.~~J ~r'l"'~I' \!~ I,: L . . r;, 1 _ ~. " . I J i ~- It.... ~ ," ~ ,-.. .'~ ~ 4' ,/ 31. LIST OF ATTACHMENTS Well 32. History, Logs. Core Data Sheet. Dry Cuttings I hereby certify that the foregoing is true apd correct to the best of my knowledge Si9"~'~"~,,'-,"~~ .~' /~Ti'" District DrillingD'" R. H. R~~l~y . ¡f ~. Engineer . 1- -I (pI '""t--: INSTRUCTIONS ,General: This, form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. . , . '-' ..'. Item 1:' Classification of Service Wells: Gas injection, water injection, steam injection, air injection, salt water disppsa,l, water s~pply for,injection, observation,_ injection for in-situ combustion. Item 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other spaces on this form an~ in any attachments. .< ; Item 16 and 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the producing intervals for only the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to sùch interval. . . . Item 21: Indicate whether from ground level (GL) or other elevation (OF, KB, etc.). Item 23: Attached suppiemental records for this well should show the details of any multiple stage cement- ing and the location of the cementing tool. Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water In- jection, Gas I njection, Shut-in, Other-explain. Item 28: If no cores taken, indicate "none". .' -------- .-, --~.".. . . , , . ~, ~;;':7" ~ " WELL HISTORY NECHELIK III Spudded well at 1500 hours. January 17. 1982. Installed & tested diverter system. Drilled 17 1/2" hole to 2710'. Ran open hole logs. Ran 70 j ts. 13 3/8" nil L-80 Buttress casing to ,2700'. Cemented with 2352 cu. ft. Permafrost Ü cement; Nippled down diverter. installed and tested BOPE. Cleaned out to 2662'. tested casing to 3000 psi. okay. Drilled out to 2732', performed leak-off test to 0.82 psi/ft. gradient (no leak-off obtained). Drilled and cored 12 1/4" hole to 74.50'. Cut 3 cores from 6338-7230'; total cut 179.75'. total recovered 150.5'. Ran open hole logs and RFT. Drilled 12 1/4" hole to 8527' and ran open hole logs. RFT. and side- wall cores. Drilled 12 1/4" hole to 8559'. Ran 222 jts._~~Lß~~ 4711 L-80 Buttress casing to 8559'. Cemented in two stages: First stage with 1150 cu. ft. Class G cement;" second stage through D.V. packer at 2623' with 130 cu. ft. Permafrost C cement preceded by Arctic Pack. Cleaned out D.V.; tested casing to 3000 psi. okay. Cleaned out float equipment and drilled 8 1/2" hole to 8587'. Performed leak-off test to 0.815 psi/ft. gradient. Drilled and cut 18 cores from 8763-9918'; total cut 977'; total recovered 977.25'. Drilled to 10018'. Attempted to run open,hole logs; hit bridge at 9890'. Made wiper~trip to clean out hole. Ran HDT; stuck in hole; recovered. Ran velocity survey. HDT. sidewall cores. and gravity meter. Set bottom cement plug at 10018' .with 114 cu. ft. Class G cement. Pumped second plug from 8869-8660' (160 cu. ft. Class G cement). Set EZ Dril¡ at 8459' and squeezed 70 sks Class G; layccement plug (30 sks) on top of EZ Drill. Pressure tested to 3000 psi. Lay cement plug from 2650-2280' (145 sks Permafrost C cement). Cut off 9 5/8" casing at 92' .Bl{B, and cut off 13 3/8" casing 5' below cellar top. Cut cellar out below tundra and cemented from 92' BKB to surface with 52 sks Permafrost C cement. Installed abandonment. marker and released rig at 2000 hours. March 1 ~. 1982. NOTE: Cement plugs witnessed by Bobby Foster of AOGCC. RECEIVED APR 1 6 1982 ZtJasl<a Oil & Gas Cons. Commlss¡u" Anchorage CO~!nr)f.MTIAl ¡~,t ;t::~:H;¡ F V Ii "¡L.n..i d 1~ Ii Lll -~.~ _. -.-"*" -.- .--.. _.~ . . ~!-ij ~l¡:t~~ 1~ - : .0, ;.... ., ¡:. . ........ N.elik #1 P & A Schem. .. 13-3/8" 72#, L-80. BTC Surface Casing cut off @ 5' 20" Conductor to 91' ...=------ 9-518" 47# L-80 casing cut off @ 92' BKB Cemented from Surface to 92' BKB with 52 sks Permafrost C cement . 2280' - 2650' 145 sks Permafrost C cement plug 111 30 sks cement plug on top of EZ Drill f EZ Drill set at 8459' . Squeezed 70 sks Class G cement . 8660' - 8869' 160 Cu. Ft. Class G cement plug . 114 Cu. Ft. Class G Cement Plug . TD @ 10018' MDfTVD ¡... .'. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG . . ~ 1. Status of well Classification of Service Well Oil 0 Gas 0 Suspended 0 2. Name of Operator PhiJlips Alaska, Inc. 3. Address P. O. Box 100360, Anchorage, AK 99510-0360. 4. Location of well at surface Abandoned 0 Service 0 210' FSL, 1170' FWL, Sec. 2, T12N, R4E, UM (ASP: 369592, 6003006) AtTop Producing Interval 1009' FSl, 328' FWL, Sec. 2, T12N, R4E, UM (ASP: 368762, 6003820L At Total Depth 1011' FSL, 337' FWL, Sec. 2, T12N, R4E, UM (ASP: 368771, 6003822) 5. Elevation In feet (Indicate KB, DF, etc.) 16. Lease Designation and Serial No. 43 DP RKB I Pad 15' ADL 380092/388525 12. Date Spudded 13. Date T.D. Reached 14. Date Comp.. Susp. Or Aband. March 5, 2001 March 14,2001 March 21,2001 17. Total Depth (MD + TVD) 18. Plug Back Depth (MD + TVD) 19. Directional Survey 8040' MD 17875' TVD 2050; MD 12036' TVD YES 0' No 0 22. Type Electric or Other Logs Run MWD1LWD with(ARC5-GRlRes), PEX(MCFUCNUTLD/GRlAITH), CSI, DSI. MDT 23. CASING. LINER AND CEMENTING RECORD SETTING DEPTH MD TOP BOTTOM Surface 117' Surface 2036' 7. Pennit Number 201-036/301-062 8. API Number 50-103-20370-00 9. Unit or Lease Name N/A 10. Well Number . Nigliq #1 11. Field and Pool Exploration 115. Water Depth, If offshore (p&A'd) N/A feet MSL 120. Depth where SSSV set N/A feel MD 16. No. of Completions o 21. Thickness of Permafrost CASING SIZE 16" 9.625" wr. PER FT. 62.5# 36# GRADE H-40 J-55 HOLE SIZE CEMENTING RECORD AMOUNT PULLED 24" 285 sxAS I 318 sx AS /II & 233 sx Class G 12-1/4" 24. Perforations open to Production (MD + TVD of Top and Bottom and interval. size and number) 25. SIZE Plug #1: 8040'-6940' Plug #2: 4600'-3770' Plug #3: 2587'-2050' . TUBING RECORD DEPTH SET (MD) NM NM PACKER SET (MD) N/A None 26. ACID, FRACTURE. CEMENT SQUEEZE. ETC. DEPTH INTERVAL (MD) . AMOUNT & KIND OF MATERIAL USED Plug 1: 8040'-6940' 400 .SX 15.8 ppg Class G cement Plug 2: 4600'-3770' 345 sx 15.8 ppg Class G cement Plug 3: 2587'-2050' 275 sx 17 ppg Class G cement 27. Date First Production N/A Date of Test Hours Tested N/A Row Tubing Casing Pressure PRODUCTION TEST Method of Operation (FlowIng. gàS lift, etc.). Plugged & Abandoned Production for OIL-BBL GAS-MCF Test Period > Calculated OIL-BBL GAS-MCF 24-Hour Rate> WATER-BBL CHOKE SIZE . 1 GAS-OIL RATIO OIL GRAVITY· API (corr) WATER-BBL Press. 28. CORE DATA Brief description 01 lithology, porosity, fractures. apparent cfrps and pressence of 011. gas or water. Submit core chips. To be sent under separate cover letter . Form 10-407 Rev. 7-1-80 CONTINUED ON REVERSE SIDE Submit in duplicate " , 29. .-- GEOLOGIC MARKERS 30. .-- :. FORMATION TESTS MEAS. DEPTH TRUE VERT. DEPTH Include interval tested, pressure data. all fluids recovered and gravity. GOR, and time of each phase. NAME To be submitted under separate cover See Attachltlent 31. LIST OF ATTACHMENTS Summary of Operations, Directional Survey, As-Built. Geological Markers 32. I hereby certify that the following Is true and correct to the best of my knowledge. Questions? Call Scott Reynolds 265-6253 Signed µ t... ~ G. C. Alvord TItle Alpine DrillinQ Team leader Date b {4(Q/ Prepared by Sharon Allsup-Drake INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Item 1: Classification of Service wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water .supply for injection, observation, injection for in-situ combustiòn. Item 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other spaces on this form and in any attachments. Item 16 and 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the producing intervals for the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such inteival. Item 21: Indicélte whether from gróund level (GL) or other elevation (DF, KB, etc.). Item 23: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, Other-explain. Item 28: If no cores taken, indicate "none". Fonn 10407 " , eliq #1 P & A Schemati. 16" Conductor to 117' 9-5/8" 36# J-55 @ 2036' MD 11989' TVD . 2050' - 2587' 275 sks 17 ppg Class G cement plug 10.4 ppg Kill Weight Mix . 3770' - 4600' 345 sxs 15.8 ppg Class G cement plug 10.4 ppg Kill Weight Mix . 6940' - 8040' 400 sxs 15.8 ppg Class G cement plug . TD @ 8040' MD/7875' TVD , "" ~ '. .~. . . STATE OF ALASKA ALASKA Oil AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG GINJ 0 2. Operator Name: ConocoPhillips Alaska, Inc. 3. Address: P. O. Box 100360, Anchorage, AK 99510-0360 4a. Location of Well (Govemmental Section): Surface: 1349' FSL, 816' FEL, Sec. 5, T12N. R5E. UM At Top Productive Horizon: 2331' FSL, 724' FWL, Sec. 33, T13N, R5E, UM 1586' FNL, 1806' FWL, Sec. 29, T13N. R5E, UM 4b. Location of Well (State Base Plane Coordinates): Surface: x- 388228 y- TPI: x- 392484 y- Total Depth: x- 388364 y- 18. Directional Survey: Yes 0 NoU J. 1a. Well Status: Oil 0 Gas U WlNJ 0 WDSPL 0 Total Depth: 21. Logs Run: GRlRes, Dens/Neutron 22. CASING SIZE Wf. PER FT. 16" 62.5# 9.625" 36# 7" 26# GRADE H-40 J-55 L-80 Plugged 0 Abandoned 0 20AAC 25.105 No. of Completions _ 6003843 6010042 6016746 Zone- 4 Zone- 4 Zone- 4 Suspended U 20AAC 25.110 Other WAG 0 5. Date Comp., Susp., or Aband.: April 11, 2005 6. Date Spudded: March 22, 2005 7. Date TD Reached: April 9, 2005 8. KB EleVation (ft): 36.7' RKB 149.6' AMSL 9. Plug Back Depth (MD + lVD): 18915' MD 16816' ìVD 10. Total Depth (MD + lVD): 18915' MD 16816' ìVD 11. Depth where SSSV set landing nipple @ 2267' 19. Water Depth, if Offshore: N/A feet MSL CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD SETTING DEPTH lVD TOP BOTTOM TOP BOTTOM 36.7' 114' 36.7' 114' 36.7' 3075' 36.7' 2437' 36.7' 11076' 36.7' 6998' 23. Perforations open to Production (MD + TVD of Top and Bottom Interval, Size and Number; if none, state "none'1: open hole completion 24. SIZE 4.5" 1 b. Well Class: Development 0 Exploratory 0 Service 0 Stratigraphic TesD 12. Permitto Drill Number: 205-033 I 13. API Number: 50-103-20507-00 14. Well Name and Number: CD3-108 15. Field/Pool(s): Colville River Field Fiord Oil Pool 16. Property Designation: ADL 372105/372104/364471 17. Land Use Permit: LAS21122 20. Thickness of Permafrost: 1293' MD HOLE SIZE CEMENTING RECORD AMOUNT PULLED 42" 12.25" 8.5" 10 yds Portland Type III 522 sx AS Lite, 239 sx Class G 254 sx Class G TUBING RECORD DEPTH SET (MD) 10097' I PACKER SET 10037' 25. ACID, FRACTURE. CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT AND KIND OF J'v1ATERIAL USED nla 2ß. Date First Production PRODUCTION TEST Method of Operation (Flowing. gas lift, etc.) Shut-In, refer to attachment for flowback rates GAS-MCF WATER-BBL CHOKE SIZE Production for OIL-BBL Test Period-> Flow Tubing Casing Pressure Calculated press. psi 24-Hour Rate -> 27. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water (attach separate sheet, if necessary). Date ofTest Hours Tested Submit core chips; if none, state "none". Form 10-407 Revised 12/2003 OIL-BBL NONE GAS-MCF WATER-BBL CONTINUED ON REVERSE GAS-OIL RATIO_ OIL GRAVITY - API (corr) not available (.. .. >(";:. . 29. . 28. ;,~ GEOLOGIC MARKERS FORMATION TESTS NAME MD ìVD Include and briefly summarize test results. List intervals tested, and attach detailed supporting data as necessary. If no tests were conducted, state "None". CD3-1 08 Seabee Form. Nanushak Gamma Ray Shale Kalubik Kuparuk Formation 3203' 5460' 9564' 10060' 10147' 2509' 3913' 6456' 6706' 6746' NIA 30. LIST OF ATTACHMENTS Summary of Daily Operations, Directional Survey, Mechanical Integrity Test, Monthly Production Report 31. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Vem Johnson @ 265-6081 Printed Name ~ )Y. "Iyord Signature / --t: ~ Title: Phone Alpine DrillinQ Team Leader Date , {" f ,,~ Prepared by Sharon AlIsu~Drake INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Item 1a: Classification of Service wells: Gas injection, water injection, Water-Altemating-Gas Injection, salt water disposal, water supply for injection. observation, or other. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 4b: TPI (Top of Producing Interval). Item 8: the Kelly Bushing elevation in feet abour mean low low water. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 13: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 20: True vertical thickness. Item 22: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 23: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1. and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 26: Method of Operation: Flowing. Gas Lift, Rod Pump, Hydraulic Pump, Submersible. Water Injection, Gas Injection, Shut-in. Other (explain). Item 27: If no cores taken, indicate "none". Item 29: List all test information. If none, state "None". Form 10-407 Revised 12/2003 ," . '" _ ConocoPhillips Alaska, Inc. . _ ~ CD3-108 TUBING (0-10097, OD:4.500, ID:3.958) SURFACE ----< (0-3075, OD:9.625, W:36.00) 'RODUCTION (0-11075, OD:7.000, W:26.00) PACKER 10037 -10038, OD:5.970) NIP 10084-10085, OD:5.000) WLEG 10095-10096, OD:5.200) OPEN HOLE 11075-18915, OD:6.125) . .)-.......................... t Po . . ALPIN E API: 501032050700 Well Type: SVC SSSV Type: NONE Orig 4/11/2005 Completion: Annular Fluid: Last W/O: Reference Log: 38' RKB Ref Log Date: Last Tag: TO: 18915 ftKB Last Tag Date: Max Hole Angle: o deg @ Casing String- ALL STRINGS Description CONDUCTOR SURFACE PRODUCTION OPEN HOLE Tubing String· TUBING Size I Top 4.500 0 Gas Lift Mandrels'Valves St I MD I TVD I ~~; I Man Type I V Mfr 1 9932 9932 CAMCO KBG-2 Other ()Iugs, equip., etc.) . JEWELRY Depth TVD Type 33 33 HANGER 2267 2267 NIP 10037 10037 PACKER 10084 10084 NIP 10095 10095 WLEG 10097 10097 TTL General Notes Date I Note 4/11/2005 TREE: FMClUnihead System wi Horizontal Tree Gen 11/4-1/16" 5K TREE CAP CONNECTION: 7" OTIS Size 16.000 9.625 7.000 6.125 TVD 114 3075 11075 18915 Top o o o 11075 Bottom 114 3075 11075 18915 Bottom 10097 I Wt I Grade I 12.60 L-80 TVD 10097 Angle @ TS: deg @ Angle @ TO: deg @ CD3-108 Rev Reason: Pull Ball, Rod, RHC, set OV, Drift TBG Last Update: 4/29/2005 Wt 62.50 36.00 26.00 0.00 Grade H-40 J-55 L-80 Thread WELDED BTC BTCM Thread IBTM V Type I V OD I Latch I Port I TRO I Date I Vlv Run Cmnt OV 1.0 BK 0.250 0 4/12/2005 Description FMC 4.5" TBG HANGER CAMCO 'DB' LANDING NIPPLE BAKER PREMIER PACKER HALLIBURTON 'XN' NIPPLE @ 62.39 DEGREE HALLIBURTON WIRELlNE GUIDE ID 4.500 3.812 3.875 3.725 3.875 3.875 ... ,.. , . ConocoPhillips Alaska, Inc~ Post Office Box 100360 Anchorage, Alaska 99510-0360 Telephone 907-276-1215 . ~ ConocoPhillips April 6, 2005 Alaska Oil and Gas Conservation Commission 333 West ih Avenue, Suite 100 Anchorage, Alaska 99501 Re: Application for Permit to Drill CD3·109 Dear Sir or Madam: ConocoPhillips Alaska, Inc. hereby applies for a Permit to Drill an onshore production well from the Fiord CD3 drilling pad. The intended spud date for this well is 4/25/2005. It is intended that Doyon Rig 19 be used to drill the well. CD3-109 will be drilled to penetrate the Nechelik reservoir horizontally. After setting 7" intermediate casing, drilling operations will be temporarily shutdown, and the rig will be moved to C02 pad while an ice road is available. Doyon 19 will return to drill the horizontal section when an ice road is available in early 2006. At the end of the work program, the well will be closed in awaiting completion of well work and facilities construction that will allow the well to begin production fourth quarter 2006. Please find attached the information required by 20 ACC 25.005 (a) and (c) for your review. Pertinent information attached to this application includes the following: 1. Form 10-401 Application for Permit to Drill per 20 ACC 25.005 (a). 2. Fee of $100 payable to the State of Alaska per 20 ACC 25.005 (c) (1). 3. A proposed drilling program. 4. A proposed completion diagram. 5. A drilling fluids program summary. 6. Pressure information as required by 20 ACC 25.035 (d)(2). 7. Directional drilling / collision avoidance information as required by 20 ACC 25.050 (b). Information pertinent to the application that is presently on file at the AOGCC is: 1. Diagrams of the BOP equipment, diverter equipment and choke manifold layout as required by 20 ACC 25.035 (a) and (b). 2. A description of the drilling fluids handling system. 3. Diagram of diverter set up. If you have any questions or require further information, please contact Vern Johnson at 265-6081 or Chip Alvord at 265-6120. Sincerely, Vern Johnson Drilling Engineer '" jlll1i¡i,!; .......... !:!;!:¡:!: I Fiqii (CD3) Colville River FMilid CD~ 09 Suspension Schem~ic . ¡i¡¡¡¡¡¡iL m¡¡¡m I 16" Conductor to 114' ¡¡¡'filii! 4 %" 12.6#/ft 1ST-Mod Tubing set at 1645' MD ,!i¡¡¡¡li\, Jilfmm '!IIJ!!II1I w¡m¡¡¡ !\il~I!~¡ "----->. ¡j¡j1¡¡j1¡ ¡¡¡hm¡¡ i:::Ë¡i¡¡¡ immm .!IIml!li jji;:" mimi!i 9-518" 36 ppf J-55 BTC . Surface Casing @ 2884' MD 12498' TVD cemented to surface 9.6 ppg KCI Brine with 1500' MD diesel cap Displaced 4 %" and 7" with 55 Bbls diesel Top Nechelik at 9585' MD 17003' TVD 7" 26 ppf L-80 BTC Mod Production Casing @ 9685' MD I 7026' TVD @ 77° I ConocoPhillips Alaska, In!lt Post Office Box 100360 Anchorage, Alaska 99510-0360 Telephone 907-276-1215 . '- '~ ConocJ'Phillips March 14, 2005 Alaska Oil and Gas Conservation Commission 333 West yth Avenue, Suite 100 Anchorage, Alaska 99501 Re: Application for Permit to Drill CD3-11 0 Dear Sir or Madam: ConocoPhillips Alaska, Inc. hereby applies for a Permit to Drill an onshore injector well from the Fiord CD3 drilling pad. The intended spud date for this well is 4/14/2005. It is intended that Doyon Rig 19 be used to drill the well. CD3-110 will be drilled to penetrate the Nechelik reservoir horizontally. After setting 7" intermediate casing, drilling operations will be temporarily shutdown, and the rig will be moved to another location (likely CD3-1 09) in order to get another penetration in the Nechilik while the ice road is available. Doyon 19 will return to drill the horizontal section when an ice road is available in early 2006. The well will be drilled and the well completed as an open hole injector. At the end of the work program, the well will be closed in awaiting completion of well work and facilities construction that will allow the well to begin injection fourth quarter 2006. It is also requested that the packer placement requirement be relaxed to place the completion packer 250 ft TVD above the Nechelik formation. This will place the completion at a maximum inclination less than 65° and allow access to the completion with standard wireline tools for future intervention. Please find attached the information required by 20 ACC 25.005 (a) and (c) for your review. Pertinent information attached to this application includes the following: 1. Form 10-401 Application for Permit to Drill per 20 ACC 25.005 (a). 2. Fee of $100 payable to the State of Alaska per 20 ACC 25.005 (c) (1). 3. A proposed drilling program. 4. A proposed completion diagram. 5. A drilling fluids program summary. 6. Pressure information as required by 20 ACC 25.035 (d)(2). 7. Directional drilling / collision avoidance information as required by 20 ACC 25.050 (b). Information pertinent to the application that is presently on file at the AOGCC is: 1. Diagrams of the BOP equipment, diverter equipment and choke manifold layout as required by 20 ACe 25.035 (a) and (b). 2. A description of the drilling fluids handling system. 3. Diagram of diverter set up. (. ... Ficwi (CD3) Colville River Fad CD~ 10 Suspension Schem~ic 'f j.......... ;::~:::::: ¡¡¡I¡¡¡,¡¡ f· """"'L . Surface Casing @ 2680' MD /2439' TVD cemented to surface 16" Conductor to 114' 4 %" 12.6#/ft IBT-Mod Tubing set at 1695' MD ~ 9.6 ppg KCI Brine with 1500' MD diesel cap Displ~ced 4 %" and 7" with 50 Bbls diesel Top Nechelik at 8814' MD /6988' TVD 7" 26ppf L-80 BTC Mod Production Casing @ 8,959' MD