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Home My WebLink AboutCO 605INDEX CONSERVATION ORDER NO. 605 Colville River Field, Qannik Oil Pool 1. April 3, 2008 2. April 9, 2008 3. May 15 2008 4. May 15, 2008 5. June 25, 2008 6. December 14, 2010 7. June 16, 2015 8. February 28, 2018 9. February 28, 2018 ConocoPhillips Alaska, Inc.'s request for Pool Rules Notice of Hearing, affidavit of mailing, e-mail list, bulk mailing list Transcript Letter to ConocoPhillips Alaska, Inc. E-mail re: producing CD2 -464 temporarily CPA application for MPM Multiphase Metering System (Appendices 3 and 4 of application are held confidential) CPA request for administrative approval to waive the monthly production allocation reporting requirement (CO 605.002) Corrected on 8/19/15. CPA Request for Administrative Amendment, CRU CPA Request to Amend Allowable Gas Offtake Rate, CRU (C0605.003) CONSERVATION ORDER NO. 605 STATE OF ALASKA STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7t" Avenue, Suite 100 Anchorage Alaska 99501 Re: THE APPLICATION OF CONO- COPHILLIPS ALASKA, INC. for an order for classification of a new oil pool and to prescribe pool rules for development of the Qannik Oil Pool within the Colville River Field, Colville River Unit, Arctic Slope, Alaska Conservation Order No. 605 Colville River Field Colville River Unit Qannik Oil Pool June 30, 2008 NOTICE CLOSING DOCKET BY THE COMMISSION: The Commission has the closed the Docket in the above captioned matter. ENTERED AND EFFECTIVE at Anchorage, Alaska and this 30th day of June, 2008. BY DIRECTION OF THE COMMISSION Jo~y~7. Colbi,~j S e ial As ' t to the Commission • • 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 Qannik Oil Pool within the Colville River Field, Colville River Unit, Arctic Slope, Alaska Conservation Order No. 605 Colville River Field Colville River Unit Qannik Oil Pool June 30, 2008 IT APPEARING THAT: 1. By letter and application dated April 3, 2008, and received by the Alaska Oil and Gas Conservation Commission (Commission) that same day, ConocoPhillips Alaska, Inc. (CPAI), in its capacity as unit operator and on behalf of the working interest owners of the Colville River Unit (CRU), requests an order defining a new oil pool, the Qannik Oil Pool, within the CRU, and prescribing rules governing the development and operation of that pool. Also, CPAI is applying for an Area Injection Order (AIO) for the Qannik Oil Pool. 2. A notice of a public hearing was published in the ANCHORAGE DAILY NEws, on the State of Alaska's Online Public Notice Web site, and on the Commission's Web site on April 9, 2008. 3. The Commission received no comments or requests for a public hearing. 4. The Commission held a public hearing on the pool rules and AIO applications on May 15, 2008. 5. The hearing record was held open until May 25, 2008, so that CPAI could provide the additional information for the area injection order application requested during the hearing. FINDINGS: 1. Operator: CPAI is the operator of the leases in the Affected Area, which is defined below. 2. Development Area: The Affected Area lies in the Colville Delta area, within the CRU (see Figure 1, below). The. Qannik Oil Pool initially will be developed from the CD2 Drill Site (CD2), which is located in Section 2, Township (T) 11N, Range (R) 04E, Umiat Meridian (UM). • • Conservation Order No. 605 June 30, 2008 Page 2 Owners and Landowners: All lands within the Affected Area are leased and lie in or near the CRU. Two companies hold working interests in the proposed Qannik Oil Pool: ConocoPhillips (78%) and Anadarko Petroleum Company (22%). The landowners are the State of Alaska, Department of Natural Resources and the Arctic Slope Regional Corporation. Figure 1. Proposed Affected Area for Qannik Oil Pool (highlighted with yellow) 4. Exploration and Delineation History: CPAI drilled the Nanuk No. 1 discovery well in Section 19 of T11N, RSE, Umiat Meridian ("UM") in 1996. To date, approximately 130 wells have penetrated the Qannik reservoir. Two overlapping, three-dimensional seismic surveys and well data have been used to determine the geologic structure and reservoir distribution of the Qannik Oil Pool. Production test data, conventional and sidewall core data, well log data, Repeat Formation Tester data and Modular Formation Dynamics Tester data have been used to establish the reservoir and fluid properties of the proposed Qannik Oil Pool. 5. Pool Identification: The proposed Qannik Oil Pool is the accumulation of hydrocarbons common to, and correlating with, the interval between the measured depths of 6,086' and ~ This map is for illustration purposes only. Refer to the legal description for the precise representation of the proposed Qannik Oil Pool. L~ Conservation Order No. 605 June 30, 2008 Page 3 6,249' on the Electromagnetic Wave Resistivity (EWR) log recorded in well CRU CD2- 11 (see Figure 2, below). Figure 2. CRU CD2-11 -Type Well Log for Qannik Oil Pool z 2 Figure 2 is for illustration purposes only. Refer to the Electromagnetic Wave Resistivity (EWR) well log measurements recorded in well CRU CD2-1 1 for the precise representation of the proposed Qannik Oil Pool. • Conservation Order No. 605 June 30, 2008 4. Geolo~y: Page 4 a. Stratigraphy: The Qannik Oil Pool encompasses late Cretaceous-aged sediments deposited as top-set beds in a shallow, north-trending, eastward-migrating marine shelf environment that is the age-equivalent to the Nanushuk Group of the central Arctic Slope. The Qannik sediments consist of very fine-to fine-grained sandstone deposited as thin, elongate deposits that extend at least 12 miles north-to-south, along depositional strike, and about 6 miles west-to-east, along depositional dip. Within the CRU, the Qannik sandstone is very fine-grained and lithic-rich. Net pay is up to 22 feet thick, and averages 10 to 15 feet. Porosity is 20 to 25 percent, and permeability ranges from 10 to 50 millidarcies. b. Structure: Within the proposed development area, the Qannik reservoir sandstone occurs in anorth-south, very low-relief syncline. No seismically mapable faults are present. c. Trap Confi urg ation: Well log and seismic information indicate that the Qannik accumulation is a stratigraphic trap. The Qannik sandstone is truncated to the west and shales out to the east. A gas-oil contact exists at about -4,000 feet true vertical depth subsea (TVDSS). An oil-water contact has not been observed in the proposed development area. d. Confining Intervals: The Qannik Oil Pool is overlain and underlain by thick accumulations of marine shale and siltstone that are assigned to the Torok Formation and laterally continuous throughout the proposed development area. 6. Reservoir Fluid Properties: Qannik reservoir fluid samples recovered from the Nanuk No. 2 and Nanuq No. 5 exploratory wells and the CD2-11 and CD2-404 service wells measured between 27° and 32° API gravity, with viscosity of about 2.0 centipoise at 1,850 psig and 89° F. The solution gas-oil ratio (GOR) measured 404 standard cubic feet per stock tank barrel, and the bubble point pressure is about 1,850 psig. At the datum depth of 4,000' TVDSS the Qannik reservoir pressure is about 1,850 psi and the reservoir temperature is about 89° F. 7. In-Place and Recoverable Oil Volumes and Production Rates: Nine-Well Eighteen-Well Hydrocarbon Volume Development Development (MMSTB) (MMSTB) Original Oil in Place (OOIP) 79 127 Primary Recovery with Gas Cap Expansion 12 19 (Primary) (15% of OOIP) Primary + Waterflood (a total of 22% of 17 28 OOIP) • • Conservation Order No. 605 June 30, 2008 Page 5 The annualized peak production rate for the Qannik Oil Pool is expected to be between about 3,000 and 6,000 barrels of oil per day (BOPD). The expected maximum and average waterflood injection rates are 12,000 barrels of water per day (BWPD) and 5,000 BWPD, respectively. Production from the Qannik Oil Pool and other CRU pools will be commingled on the surface prior to processing and custody transfer. 8. Reservoir Development Drilling Plan: The Qannik Oil Pool will be developed initially with nine horizontal wells: the CD2-404 well and eight new wells. The producer-to- injector ratio will be about 2:1. The production and injection wells will range in length from 6,000' to 9,000' within the reservoir, and will be parallel to one another. Three central, north-trending injection wells will be arranged end-to-end and flanked on both sides by outboard production wells; this alternating arrangement will form aline-drive flood pattern. Individual wells will be spaced about 2,700' to 3,400' apart. The wells will be oriented to maximize use of the expansion drive and minimize gas influx from the gas cap, which lies to the east. Extra producers and injectors may be added at a later date based on net oil pay and reservoir performance. 9. Reservoir Mana eg ment: CPAI proposes to develop this oil pool as awater-injection enhanced oil recovery project, supplemented by expansion of the gas cap. Water injection is planned to begin during the third quarter of 2008. Production and injection will be balanced to maintain reservoir pressure at or near the original measured pressure. 10. Reservoir Surveillance Plans: CPAI proposes to meet bottomhole pressure survey requirements by conducting stabilized, static pressure measurements at bottomhole or extrapolating from surface pressure fall-off measurements, pressure buildup measurements, multi-rate test results, drill-stem test results, formation test results, or other appropriate pressure transient or static test results. CPAI proposes to meet the annual bottomhole pressure measurement requirement by conducting bottomhole pressure surveys as needed; pressures will be referenced to a datum of 4,050' TVDSS. CPAI proposes to report the data and results from the pressure survey(s) annually. 11. Wellbore Construction: CPAI proposes that the surface casing of wells drilled in the Qannik Oil Pool be set at approximately 2,400' TVDSS and cemented to surface. Intermediate casing will be set and cemented with the shoe in the target formation. Leak-off or formation integrity tests will be conducted, and significant hydrocarbon zones in the boreholes outside of the reservoir intervals will be protected in conformance with Commission regulations. The proposed Qannik Oil Pool will be developed using horizontal wells with a 3-1/2- inch liner that is slotted across sandstone intervals and blank across shale intervals. Production will be conveyed to the surface using a packer and 3-1/2-inch tubing. Injectors may be equipped with 4-1/2-inch tubing and liner. CPAI proposes that all production wells within the Qannik Oil Pool be equipped with a fail-safe automatic surface safety valve (SSV) and asurface-controlled sub-surface safety valve (SCSSSV). CPAI proposes that all injection wells be equipped with (i) a • Conservation Order No. 605 June 30, 2008 Page 6 double check valve arrangement or (ii) a single check valve combined with a SSV, and that a SCSSSV be considered as a single check valve. 12. Waivers: CPAI requests that the Commission grant the following waivers: a. Directional Wellbore Plans: CPAI proposes to provide a plan view well plat, vertical section diagram, close approach data and description of the proposed directional program in lieu of meeting the requirements of 20 AAC 25.050(b). b. Well Spacing: CPAI proposes to eliminate the wellbore spacing restrictions of 20 AAC 25.055 to accommodate horizontal, line-drive wells and maximize ultimate recovery. c. Gas-Oil Ratio Limits: CPAI seeks an exemption from the GOR limits of 20 AAC 25.240(a) in accordance with the provisions of 20 AAC 25.240(b). 13. Sustained Casing Pressure Rules: CPAI proposes to operate Qannik Oil Pool wells in compliance with previous Commission orders addressing sustained casing pressures for active wells. Similar rules are appropriate for this development. 14. Allowable Gas Off Take: By administrative actions dated February 13, 2007, an allowable gas off take of 1 MMCFPD was approved for the Colville River Field. Rule 3 of CO 443A-003 requires that any new pools identified in the Colville River Field be subject to the same limitation. CONCLUSIONS: 1. Pool Rules for the development of the Qannik Oil Pool within the Colville River Field in the Colville River Unit are appropriate. 2. The Qannik Oil Pool is hydraulically isolated from all other oil pools. 3. 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 ensure that future development plans promote greater ultimate recovery and prevent the waste of resources. 4. Proper annular pressure management is necessary to prevent the failure of well integrity and uncontrolled release of fluids or pressure, and to minimize threats to human safety and the environment. Filing the proposed submittals, rather than those required by 20 AAC 25.050(b), will, as required by 20 AAC 25.050(h), at least equally ensure "accurate surveying of the wellbore to prevent well intersection, to comply with spacing requirements, and to ensure protection of correlative rights." 6. Eliminating spacing restrictions on wellbores interior to the Affected Area, which is defined below, will increase the operator's flexibility in placing 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. C7 • • Conservation Order No. 605 June 30, 2008 Page 7 Correlative rights will be protected by requiring a 500-foot set back from external property lines where the owners and landowners are not the same on both sides of the line. 7. A gas-oil ratio limitation waiver is appropriate under 20 AAC 25.240(b)(1) because the Qannik Oil Pool will be developed as an enhanced recovery project. 8. Surface-controlled subsurface safety valves are appropriate for all producing wells that will flow hydrocarbons to the surface. Requests for the approval of alternate types of subsurface safety valves should be addressed through the administrative action rule (i. e., Rule 10 (below)). NOW, THEREFORE, IT IS ORDERED: The development and operation of the Qannik Oil Pool 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 Sections T 1 ON, R04E 1 - 4 T10N, ROSE 4 - 6 T11N, R04E 1 - 4; 9 - 16; 21 - 28; 33 - 36 T11N, ROSE 4 - 9; 16 - 21; 28 - 33 T12N, R04E 1 - 4; 9 - 16; 21 - 28; 33 - 36 T12N,ROSE 4- 9; 16 -21;28-33 Rule 1 Field and Pool Name The field is the Colville River Field. Hydrocarbons underlying the Affected Area and within the interval of the Torok Formation identified in Rule 2 (below) constitute the oil pool named the Qannik Oil Pool. Rule 2 Pool Definition The Qannik Oil Pool is the accumulation of hydrocarbons common to, and correlating with, the interval between the measured depths of 6,086' and 6,249' on the EWR log recorded in well CRU CD2-11. • • Conservation Order No. 605 June 30, 2008 Rule 3 Well Spacing Page 8 There shall be no restrictions as to well spacing except that no pay shall be opened in a well within 500' of an external property line where the owners and landowners are not the same on both sides of the line. Rule 4 Drilling Waivers All permits to drill deviated wells within the Qannik 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 of 20 AAC 25.050(b). Rule 5 Automatic Shut-in Equipment a. All production wells must be equipped with afail-safe automatic SSV and a SCSSSV. b. Injection wells, including water injection service wells, must be equipped with (i) a double check valve arrangement or (ii) a single check valve and a SSV. Asubsurface-controlled injection valve or SCSSSV 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 Commingling a. Production from the Qannik Oil Pool and other CRU pools 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 Apri13, 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 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 an annual well test and allocation review report in conjunction with the annual reservoir surveillance report required under Rule 9 (below). Rule 7 Reservoir Pressure Monitoring a. A bottom-hole pressure survey shall be taken on each well prior to initial production or injection. b. The operator shall obtain the pressure surveys needed to manage the hydrocarbon recovery processes that are subject to the annual plan outlined in Rule 9 (below). c. The reservoir pressure datum will be 4,000' TVDSS. d. Pressure surveys may consist of stabilized static pressure measurements at bottomhole or be extrapolated from surface measurements (single phase fluid conditions), pressure fall-off measurements, pressure buildup measurements, multi-rate test results, drill-stem test results, Conservation Order No. 605 June 30, 2008 Page 9 open-hole formation test results or other appropriate technical pressure transient or static test results. e. A Reservoir Pressure Report, Form 10-412, shall be utilized for all surveys; all relevant data shall be attached to the report. The data submitted shall include, but are not limited to, rate, pressure, depth, fluid gradient, temperature, and all other well conditions necessary for a complete analysis of each survey. f. The results and data from any special reservoir pressure monitoring tests or surveys shall be submitted in accordance with paragraph (e) of this rule. Rule 8 Gas-Oil Ratio Exemption Wells producing from the Qannik Oil Pool are exempt from the GOR limits of 20 AAC 25.240(a) as long as 20 AAC 25.240(b)(1) applies. Rule 9 Annual Reservoir Review An annual reservoir surveillance report must be filed by April 1St of each year. The report must include future development plans, reservoir depletion plans, and surveillance information for the prior calendar year, including: 1. the voidage balance, by month, of produced and injected fluids and the cumulative status for each producing interval; 2. a reservoir pressure map at datum and a summary and analysis of the reservoir pressure surveys within the pool; 3. the results and, where appropriate, an analysis of any production and injection log surveys, tracer surveys, observation well surveys, and any other special monitoring; 4. a review of pool production allocation factors and issues over the prior year; 5. a review of the progress of the enhanced recovery project; and 6. a reservoir management summary, including the results of any reservoir simulation studies. 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 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 Commission within three working days after the operator identifies a development well as having (i) sustained inner annulus pressure that exceeds 2,000 psig for all development wells, or (ii) sustained outer annulus pressure that exceeds 1,000 psig. • Conservation Order No. 605 June 30, 2008 Page 10 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 ashut- 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 2,000 psig, and (2) that the outer annulus pressure at operating temperature will be below 1,000 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 of this 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 casing 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. Rule 11 Allowable Gas Off Take (Source CO 443A.003 et al) 1. The cumulative gas off take rate from the CRF must not exceed 1 MMCFPD. • 2. Natural gas may be severed from the CRF only to meet CPAI's contractual obligation to provide the Village ofNuigsut with natural gas. • Conservation Order No. 605 June 30, 2008 Rule 12 Administrative Action Page 11 Upon proper application, or its own motion, and unless notice and public hearing are otherwise required, the Commission may administratively waive the requirements of any rule stated herein or administratively amend this order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater. ENTERED at Anchorage, Alaska, and dated June 30, 2008. ~*~u ~s Daniel T. Se unt, Jr., Chair ~_-s. ~-ic'a OiL~as Conservation Commission -+t R,, ,. ~. »` o rman, om er ' ,, • ,. ~:~ s a it ar,~el Gas Conservation Commission .~1~~1•' .. i Cathy Poerster, Commissioner Alaska Il and Gas Conservation Commission RECONSIDERATION AND APPEAL As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the 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 IO-days is a denial of reconsideration. If the Commission denies reconsideration, upon denial, this order or decision and the denial of reconsideration aze 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. [f 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. • Mary Jones David McCaleb Cindi Walker XTO Energy, Inc. IHS Energy Group Tesoro Refining and Marketing Co. Cartography GEPS Supply & Distribution 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 300 Concord Plaza Drive Ft. Worth, TX 76102-6298 Houston, TX 77056 San Antonio, TX 78216 George Vaught, Jr. Jerry Hodgden Richard Neahring PO Box 13557 Hodgden Oil Company NRG Associates Denver, CO 80201-3557 408 18th Street President Golden, CO 80401-2433 PO Box 1655 Colorado Springs, CO 80901 John Levorsen Mark Wedman Baker Oil Tools 200 North 3rd Street, #1202 Halliburton 4730 Business Park Blvd., #44 Boise, ID 83702 6900 Arctic Blvd. Anchorage, AK 99503 Anchorage, AK 99502 Schlumberger Ciri Ivan Gillian Drilling and Measurements Land Department 9649 Musket Bell Cr.#5 2525 Gambell Street #400 PO Box 93330 Anchorage, AK 99507 Anchorage, AK 99503 Anchorage, AK 99503 Jill Schneider Gordon Severson Jack Hakkila US Geological Survey 3201 Westmar Cr. PO Box 190083 4200 University Dr. Anchorage, AK 99508-4336 Anchorage, AK 99519 Anchorage, AK 99508 Darwin Waldsmith James Gibbs Kenai National Wildlife Refuge PO Box 39309 PO Box 1597 Refuge Manager Ninilchick, AK 99639 Soldotna, AK 99669 PO Box 2139 Soldotna, AK 99669-2139 Penny Vadla Richard Wagner Cliff Burglin 399 West Riverview Avenue PO Box 60868 PO Box 70131 Soldotna, AK 99669-7714 Fairbanks, AK 99706 Fairbanks, AK 99707 Bernie Karl North Slope Borough Williams Thomas K&K Recycling Inc. PO Box 69 Arctic Slope Regional Corporation PO Box 58055 Barrow, AK 99723 Land Department Fairbanks, AK 99711 PO Box 129 Barrow. AK 99723 ~` ~,/ ~~~/~ • ~ Page 1 of 1 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Tuesday, July 01, 2008 11:55 AM Subject: co605 Colville River Unit Attachments: co605.pdf BCC:'Dale Hoffman'; Fridiric Grenier; Joseph Longo;'Mary Aschoff; Maurizio Grandi; Tom Gennings; 'Willem Vollenbrock'; 'Aleutians East Borough'; 'Anna Raff; Arion, Teri A (DNR); 'Arthur Copoulos'; 'Barbara F Fullmer'; 'bbritch'; 'Bill Walker'; 'Brad McKim'; 'Brandon Gagnon'; 'Brian Gillespie'; 'Brian Havelock'; 'Brit Lively'; 'Bruce Webb'; 'buonoje'; 'Cammy Taylor'; 'Cande.Brandow'; 'carol Smyth'; 'Cary Carrigan'; caunderwood@marathonoil.com; 'Charles O'Donnell'; 'Chris Gay'; 'Christian Gou-Leonhardt'; 'Cliff Posey'; 'Dan Bross'; 'dapa'; 'Daryl J. Kleppin'; 'David Brown'; 'David Hall'; David House; 'David L Boelens'; 'David Steingreaber'; 'ddonkel'; 'Deborah J. Jones'; 'doug_schultze'; 'Eric Lidji '; 'Evan Harness'; 'eyancy'; 'foms2@mtaonline.net'; 'Francis S. Sommer'; 'Fred Steece'; 'Garland Robinson'; 'Gary Laughlin'; 'Gary Rogers'; 'Gary Schultz'; 'ghammons'; 'Gordon Pospisil'; Gould, Greg M (DEC); 'Gregg Nady'; 'gregory micallef ; 'gspfoff ; 'Hank Alford'; 'Harry Engel'; 'jah'; 'James Scherr'; 'Janet D. Platt'; 'jejones'; 'Jerry McCutcheon'; 'Jim Arlington'; 'Jim White'; 'Jim Winegarner'; 'Joe Nicks'; 'John Garing'; 'John S. Haworth'; 'John Spain'; 'John Tower'; 'John W Katz'; johnny.aiken@north-slope.org; 'Jon Goltz'; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; knelson@petroleumnews.com; 'Krissell Crandall'; 'Kristin Dirks'; 'Laura Silliphant'; 'Lois'; 'Lynnda Kahn'; 'mail=akpratts@acsalaska.net'; 'mail=fours@mtaonline.net'; 'Marilyn Crockett'; 'Mark Dalton'; 'Mark Hanley'; 'Mark Kovac'; 'Mark P. Worcester'; 'Marguerite kremer'; 'marty'r 'Matt Rader'; 'Meghan Powell'; Melanie Brown; 'Mike Bill'; 'Mike Mason'; 'Mikel Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson ; 'mkm7200 ; 'Nick W. Glover'; NSK Problem Well Supv; NSU, ADW Well Integrity Engineer; 'Patty Alfaro'; 'Paul Decker'; 'Paul Winslow'; Pierce, Sandra M (DNR); 'Randall Kanady'; 'Randy L. Skillern'; 'rcrotty'; Rice, Cody J (DNR); 'rmclean'; 'Rob McWhorter '; rob.g.dragnich@exxonmobil.com; 'Robert Campbell'; 'Robert Fowler'; 'Robert Province'; 'Roger Belman'; 'Rudy Brueggeman'; 'Scott Cranswick'; 'Shannon Donnelly'; 'Sharmaine Copeland'; 'Sondra Stewman'; 'Sonja Frankllin'; 'Stan Porhola'; 'stanekj'; 'Steve Lambert'; 'Steve Moothart'; 'Steven R. Rossberg'; 'tablerk'; 'Tamera Sheffield'; 'Temple Davidson'; 'Terrie Hubble'; 'Tim Lawlor'; 'Todd Durkee'; Tony Hopfinger; 'trmjrl'; 'Walter Featherly'; 'Walter Quay'; 'Wayne Rancier'; Birnbaum, Alan J (LAW); Crisp, John H (DOA); Davies, Stephen F (DOA); Fleckenstein, Robert J (DOA); Foerster, Catherine P (DOA); Grimaldi, Louis R (DOA); Johnson, Elaine M (DOA); Jones, Jeffery B (DOA); Laasch, Linda K (DOA); Mahnken, Christine R (DOA); Maunder, Thomas E (DOA); McIver, C (DOA); McMains, Stephen E (DOA); Noble, Robert C (DOA); Norman, John K (DOA); Okland, Howard D (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Saltmarsh, Arthur C (DOA); Scheve, Charles M (DOA); Seamount, Dan T (DOA); Smith, Chasity R (DOA); Williamson, Mary J (DOA) Attachments:co605.pdf; Jody Jaylene Colombie Special Assistant to the Commission Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 (907) 793-1221 Direct Line (907) 276-7542 Fax 7/1/2008 • • 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. j oil. DONE at Anchorage, Alaska, and dated ary 11, 2011 Daniel T. Se. r ou , r., Commissioner, Chair • • � . • i1 . • :. s Conservation Commission Oa _, r .. man, Coer r a Oi - . • a Conserva ion Commission ' et,,, citil ''''''''%. i 'p1 r•�T .= � 4 . , Cat y P.:oerst-r, Commissioner Alaska • 11 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. Y 1 • 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 Raff; 'Barbara F Fullmer; 'bbritch'; 'Becky Bohrer; 'Bill Penrose'; 'Bill Walker; 'Bowen Roberts'; 'Brad McKim'; 'Brady, Jerry L'; 'Brandon Gagnon'; 'Brandow, Cande (ASRC Energy Services)'; 'Brian Havelock'; 'Bruce Webb'; 'carol smyth'; 'caunderwood'; 'Chris Gay; 'Cliff Posey'; 'Crandall, Krissell'; 'D Lawrence'; 'dapa'; 'Daryl J. Kleppin'; 'Dave Matthews'; 'David Boelens'; 'David House'; 'David Steingreaber; 'ddonkel @cfl.rr.com'; 'Deborah J. Jones'; Delbridge, Rena E (LAA); 'Dennis Steffy; 'Elowe, Kristin'; 'Erika Denman'; 'eyancy'; 'Francis S. Sommer'; 'Fred Steece'; 'Gary Laughlin'; 'Gary Rogers'; 'Gary Schultz'; 'ghammons'; 'Gordon Pospisil'; 'Gorney, David L.'; 'Greg Duggin'; 'Gregg Nady'; 'gspfoff; 'Harry Engel'; 'Jdarlington (jarlington @gmail.com)'; 'Jeanne McPherren'; 'Jeff Jones'; 'Jerry McCutcheon'; 'Jill Womack'; 'Jim White'; 'Jim Winegarner; 'Joe Nicks'; 'John Garing'; 'John Katz'; 'John S. Haworth'; 'John Spain'; 'John Tower'; 'Jon Goltz'; 'Judy Stanek'; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; 'Kelly Sperback'; 'Kim Cunningham'; 'Larry Ostrovsky'; 'Laura Silliphant'; 'Marilyn Crockett'; 'Mark Dalton'; 'Mark Hanley (mark.hanley @anadarko.com)'; 'Mark Kovac'; 'Mark P. Worcester'; 'Marguerite kremer'; 'Michael Dammeyer; 'Michael Jacobs'; 'Mike Bill'; 'Mike Mason'; 'Mike) Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'nelson'; 'Nick W. Glover; 'NSK Problem Well Supv'; 'Patty Alfaro'; 'Paul Decker (paul.decker @alaska.gov)'; 'Paul Figel'; 'PORHOLA, STAN T'; 'Randall Kanady'; 'Randy L. Skillern'; ' rob.g.dragnich @exxonmobil.com'; 'Robert Brelsford'; 'Robert Campbell'; 'Ryan Tunseth'; 'Scott Cranswick'; 'Scott Griffith'; Scott, David (LAA); 'Shannon Donnelly'; 'Sharmaine Copeland'; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); 'Sondra Stewman'; 'Steve Lambert'; 'Steve Moothart'; 'Steven R. Rossberg'; 'Suzanne Gibson'; 'tablerk'; 'Tamera Sheffield'; Taylor, Cammy 0 (DNR); 'Temple Davidson'; 'Teresa Imm'; 'Terrie Hubble'; 'Thor Cutler; 'Tina Grovier; 'Todd Durkee'; 'Tony Hopfinger'; 'trmjrl'; 'Valenzuela, Mariam '; 'Vicki Irwin'; 'Walter Featherly'; 'Will Chinn'; Williamson, Mary J (DNR); 'Yereth Rosen'; 'Aaron Gluzman'; Bettis, Patricia K (DNR); caunderwood @marathonoil.com; 'Dale Hoffman'; 'David Lenig'; 'Gary Orr; 'Jason Bergerson'; 'Joe Longo'; 'Lara Coates'; 'Marc Kuck'; 'Mary Aschoff; 'Matt Gill'; 'Maurizio Grandi'; Ostrovsky, Larry Z (DNR); 'Richard Garrard'; 'Sandra Lemke'; 'Talib Syed'; 'Tiffany Stebbins'; 'Wayne Wooster; 'William Van Dyke'; Woolf, Wendy C (DNR); Aubert, Winton G (DOA) (winton.aubert@alaska.gov); Brooks, Phoebe L (DOA) (phoebe.brooks @alaska.gov); Colombie, Jody J (DOA) (jody.colombie @alaska.gov); Crisp, John H (DOA) (john.crisp @alaska.gov); Davies, Stephen F (DOA) (steve.davies @alaska.gov); Foerster, Catherine P (DOA) (cathy.foerster @ alaska.gov); Grimaldi, Louis R (DOA) (Iou.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); Saltmarsh, Arthur C (DOA) (art.saltmarsh @alaska.gov); Scheve, Charles M (DOA) (chuck.scheve @alaska.gov); Schwartz, Guy L (DOA) (guy.schwartz @alaska.gov); Seamount, Dan T (DOA) (dan.seamount @alaska.gov); Shartzer, Christine R (DOA) Subject: Other 66 Safety Valve Systems Attachments: other66.pdf Samacwtha. Fig Ala4:.a, OLL a' CO V {-t -►v Ccrwu 4LO-w (907)793 -1223 (907)276 -7542 (faw) 1 • Mary Jones David McCaleb XTO Energy, Inc. IHS Energy Group George Vaught, Jr. Cartography GEPS P.O. Box 13557 810 Houston Street, Ste 200 5333 Westheimer, Suite 100 Denver, CO 80201 -3557 Ft. Worth, TX 76102 -6298 Houston, TX 77056 Jerry Hodgden Richard Neahring Mark Wedman Hodgden Oil Company NRG Associates Halliburton 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 Ct. Anchorage, AK 99515 -4295 Fairbanks, AK 99711 Anchorage, AK 99503 North Slope Borough Jill Schneider Gordon Severson P.O. Box 69 US Geological Survey 3201 Westmar Circle Barrow, AK 99723 4200 University Drive Anchorage, AK 99508 -4336 Anchorage, AK 99508 Jack Hakkila Darwin Waldsmith James Gibbs P.O. Box 190083 P.O. Box 39309 P.O. Box 1597 Anchorage, AK 99519 Ninilchick, AK 99639 Soldotna, AK 99669 Kenai National Wildlife Refuge Penny Vadla Cliff Burglin Refuge Manager 399 West Riverview Avenue 319 Charles Street P.O. Box 2139 Soldotna, AK 99669 -7714 Fairbanks, AK 99701 Soldotna, AK 99669 -2139 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 \ 0 1`\ Orders Establishing Requirements for Well Safety Valve Systems 1/7/2011 Conservation New Regulation Provisions Unit/Field Pool Order (1) Rule Rescind Rule? Existing Order Requirement Addressing Reqts from Order Revised Rule - "Well safety valve systems" (2) Comment 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 25.265(a); 25.265(b); 25.265(d)(2)(H); Check valve requirements for injectors are not covered by Colville River Unit Qannik 605 5 no (i) double check valve, or (ii) single check valve and SSV; injection 25.265(h)(5) arrangement or (ii) a single check valve and a SSV. Asubsurface- controlled injection valve or readopted regulation valve satisfies single check valve requirement; test every 6 months SCSSV satisfies the requirements of a single check valve." fail -safe auto SSV and SCSSV; injection wells (except disposal) require "Injection wells (excludin dis injectors) must be equipped with(i) a double check valve 25.265(x); 25.2659(b); 25.265(d)( Check valve requirements for injectors are not covered by Oooguruk Oooguruk - Nuiqsut 597 6 no (1) double check valve, or (ii) single check valve and SSV; injection 25.265(h)(5) arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or readopted regulation valve satisfies single check valve requirement; test every 6 months SCSSV satisfies the requirements of a single check valve." fail -safe auto SSV and SCSSV; injection wells (except disposal) require 25.265(a); a ) ; 25.265(b); b ) ; 25.265 ( d )( )' 1 "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements injectors for injectors are not covered b y Oooguruk Oooguruk - Kuparuk 596 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 valve satisfies single check valve requirement; test every 6 months 25 SCSSV satisfies the requirements of a single check valve." readopted regulation 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 Prudhoe Bay Unit Raven 570 5 yes sign on wellhead 25.265(m) N/ deactivated SVS was replaced with requirement to maintain a deactivated SVS; si m 9 ( ) tag on well when not manned fail -safe auto SSV and SCSSV; injection wells (except disposal) require 25.26r a "I njec ti on we ll s (exc di injectors) must be e with(i) a double check valve (a); 25 25 Check valve requirements for injectors are not covered by Colville River Unit Fiord 569 5 no (i) double check valve, or (ii) single check valve and SSV; injection 25.265(h)(5) arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or readopted regulation valve satisfies single check valve requirement; test every 6 months SCSSV satisfies the requirements of a single check valve." fail -safe auto SSV and SCSSV; injection wells (except disposal) require "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve 25.265(a); 25.265(b); 25.265(d)(2)(H); Check valve requirements for injectors are not covered by 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 25.265(h)(5) readopted regulation valve satisfies single check valve requirement; test every 6 months ( )( 5 ) SCSSV satisfies the requirements of a single check valve" fail -safe auto SSV and SCSSV; injection wells (except disposal) require 25.265(a); 25.265(b); 25.265(d)(2)(H); "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered by Colville River Unit Nanuq 562 6 no (i) double check valve, or (ii) single check valve and SSV; injection 25.265(h)(5) arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or readopted regulation valve satisfies single check valve requirement; test every 6 months SCSSV satisfies the requirements of a single check valve." fail -safe auto SSV; SSSV landing nipple below permafrost; test as 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; Prudhoe Bay Unit Put River 559 3 yes prescribed by Commission 25.265(h)(5) replaces SSSV nipple requirement for all wells Deep Creek Unit Happy Valley 553 3 yes SSV or SSSV 25.265(a) N/A Prudhoe Ba Unit Orion 505B 3 yes fail -safe auto SSV; SSSV landing nipple below permafrost; test as 25.265(a); 25.265(b); 25.265(d); WA Readopted 25.265(d) dictates which wells require SSSV; Y prescribed by Commission 25.265(h)(5) replaces SSSV nipple requirement for all wells Prudhoe Ba Unit Polaris 484A 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; Y prescribed by Commission 25.265(h)(5) replaces SSSV nipple requirement for all wells fail -safe auto SSV; SSSV landing nipple below permafrost; gas /MI Milne Point Unit Milne Point Readopted 25.265(d) dictates which wells require SSSV; 477 5 yes injection well require SSSV or injection valve below permafrost; test 25.265(a); 25.265(b); 25.265(d); N/A Schrader Bluff 25.265(h)(5) replaces SSSV nipple requirement for all wells every 6 months fail -safe auto SSV; SSSV landing nipple below permafrost; gas /MI 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; Prudhoe Bay Unit Borealis 471 3 yes injection well require SSSV below permafrost; test every 6 months 25.265(h)(5) replaces SSSV nipple requirement for all wells fail -safe auto SSV and SCSSV; test as prescribed by Commission; 500• Existing pool rule established a minimum setting depth for the Northstar Northstar 458A 4 no ft minimum setting depth for SSSV 25 25.265(b); 25.265(d)(1) The minimum setting depth for a tubing conveyed subsurface safety valve is 500 feet" SSSV Prudhoe Ba 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 months 25.265(h)(5) N/A 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 SCSSV satisfies the requirements of a single check valve." SSSV requirement for MI injectors fail -safe auto SSV (all injectors and producers capable of unassisted 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; Prudhoe Bay Unit Midnight Sun 452 6 yes flow to surface); test every 6 months 25.265(h)(5) replaces SSSV nipple requirement for all wells fail -safe auto SSV and SCSSV; SSSV may be installed above or below r " The setting depth of a required subsurface safety valve must be located in the tubing either Existing pool rule established alternate SSSV setting depth; 25.265(a); 25.265(b); 25.265(d)(1); • Duck Island Unit Eider 449 7 no permafrost; injection wells require double check valve; LPS trip above or below permafrost. Injection wells must be equipped with a double check valve check valve requirements for injectors are not covered by pressure; test every 6 months 25 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 SCSSV satisfies the requirements of a single check valve." SSSV requirement for MI injectors fail -safe auto SSV (S /D well and artificial lift); sign on well if SVS Requirement to maintain a wellhead sign and list of wells with deactivated; maintain list of wells w /deactivated SVS; test as 25 a deactivated SVS was replaced with requirement to maintain a 1 Kuparuk River Unit; O; 25.265 b O: 25.265 h 5 O( ); Kuparuk 432D 5 yes prescribed by Comm CO 432D.009 modifies Rule 5(b) - LPP N/A tag on well when not manned; administrative approval CO Milne Point Unit may be defeated on W. Sak injectors w / surface pressure <500psi w/ 25.265(m) 432D.009 remains effective [re:defeating the LPS when surface r for West Sak water injector is <500psi] injection pressure o s a injector p 7 notice when defeated and placed back in service injection Page 1 of 2 Orders Establishing Requirements for Well Safety Valve Systems 1/7/2011 Conservation New Regulation Provisions Revised Rule - "Well safety valves stems' (2) Comment Unit/Field Pool Order (1) Rule Rescind Rule? Existing Order Requirement Addressing Regts from Order y systems" ( ) fail -safe auto SSV; gas /MI injectors require SSV and single check 25.265(x); 25.265(b); 25.265(d); "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered by Kuparuk River Unit Tarn 430A 6 no valve and SSSV landing nipple; water injection wells require (i) double arrangement or (ii) a single check valve and a SSV. Asubsurface- controlled injection valve or readopted regulation; readopted 25.265(d)(5) does not include check valve, or (ii) single check valve and SSV; test every 6 months 25 SCSSV satisfies the requirements of a single check valve." SSSV requirement for MI injectors Milne Point - Sag fail -safe auto SSV; injection wells require double check valve; test j pp 9 Check valve requirements for injectors are not covered by 423 7 n Milne Point Unit every 6 months 25.265(a); a ) ; 25.265 ( b ) ; 25.265(h)(5) h )( 5 ) In ection wells must be equi ed with a double check valve arrangement." ement." readopted regulation River fail -safe auto SSV; gas /MI injectors require SSV and single check Check valve requirements for injectors are not covered by valve and SSSV landing nipple; water injection wells require (i) double "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve readopted regulation; readopted 25.265(d)(5) does not include Kuparuk River Unit Kuparuk West Sak 406B 6 no check valve, or (ii) single check valve and SSV; test every 6 months; 25.265(a); 25.265(b); 25.265(d); arrangement or (ii) a single check valve and a SSV. A subsurface- controlled injection valve or SSSV requirement for MI injectors; administrative approval CO P P CO 4068.001 modifies Rule 6(e) - LPP may be defeated on W. Sak 25.265(h)(5) SCSSV satisfies the requirements of a single check valve. The Low Pressure Pilot may be 4066.001 remains effective [re:defeating the LPS when surface injectors w /surface pressure <500psi w/ notice when defeated and defeated on West Sak water injectors with surface injection pressure less than 500psi." injection pressure for West Sak water injector is <500psi] placed back in service 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); N/A submit test results electronically within 14days; SVS defeated /removed 25.265(m) only if well SI or pad continuously manned fail -safe auto SSV (S /D well and artificial lift); sign on well if SVS 25.265(a); 25.265(b); 25.265(h)(5); Requirement to maintain a wellhead sign and list of wells with Prudhoe Bay Unit North Prudhoe 345 4 yes deactivated; maintain list of wells w /deactivated SVS; test as 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 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; Prudhoe Bay 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 Ba Unit Niakuk 329A 5 yes fail -safe auto SSV and SCSSV; maintain list of wells w/ removed or 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; Y deactivated SVS; sign on wellhead 25.265(h)(5); 25.265(m) replaces SSSV nipple requirement for all wells 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; Prudhoe Bay Unit Pt. McIntyre 3178 8 yes routine well ops w/o notice 25.265(j); 25.265(m) replaces SSSV nipple requirement for all wells 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; Prudhoe Bay Unit West Beach 311B 6 yes w /deactivated SVS; test as prescribed by Commission 25.265(h)(5); 25.265(m) replaces SSSV nipple requirement for all wells West Fork (Sterling West Fork A &B) 300 5 yes fail -safe auto SVS on each production tubing 25.265(a); 25.265(b) N/A Requirement to maintain a wellhead sign and list of wells with fail -safe auto SSV; sign on well if SVS deactivated; maintain list of wells 25.265(a); 25.265(b); 25.265(h)(5); N/A deactivated SVS was replaced with requirement to maintain a Prudhoe Bay Unit Lisburne 207A 7 yes w/deactivated SVS; test as prescribed by Commission 25.265(m) tag on well when not manned Prudhoe Ba Unit Prudhoe Ku aruk 98A 5 yes suitable automatic safety valve installed below base of permafrost to 25.265(d) N/A Readopted 25.265(d) dictates which wells require SSSV; Y P prevent uncontrolled flow replaces SSSV nipple requirement for all wets Commission policy dictating SVS performance testing AOGCC Policy - SVS Failures; issued by order of the Statewide N/A N/A N/A yes 25.265(h); 25.265(n); 25.265(o) N/A Dave Commission 3/30 /1994 (signed by Commission Chairman requirements Footnotes (1) No SVS rules found in Injection Orders (2) New title for Revised Rule; "N /A" means entire pool rule to be rescinded 1 Page 2 of 2 . . Public Hearing Record And Backup Information available in Other 66 • • Aco_z1 0 / 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 This feature is particularly beneficial when measuring and very rapidly. h p y g roduction streams production 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 3of3 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. oSKtOft 1a DONE at Anchorage, Alaska and dated June 21 1 11 /- Zf // / l� / / _r te_ 411 Daniel T. Seamount, Jr. . 'tnrm.r Cathy P. Foers er Chair, Commissioner e r -1 issio - Comm ssioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the Commission denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the Commission grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the Commission, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited to the questions presented to the Commission by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. • • Fisher, Samantha J (DOA) From: Fisher, Samantha J (DOA) Sent: Monday, June 20, 2011 4:55 PM To: '( michael .j.nelson @conocophillips.com); '(Von.L .Hutchins @conocophillips.com)'; 'AKDCWelllntegrityCoordinator'; 'Alan Dennis'; 'alaska @petrocalc.com'; 'Anna Rafe; '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 Towers; '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'; 'Mike) 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, d� , ry ( ), 9 9 9, Kathleen J (DNR); 'Lara Coates'; 'Lois Epstein'; 'Marc Kuck'; 'Marie Steele'; 'Mary Aschoff; 'Matt Gill'; 'Maurizio Grandi'; Ostrovsky, Larry Z (DNR); 'Patricia Bettis'; 'Richard Garrard'; 'Ryan Daniel'; 'Sandra Lemke'; 'Talib Syed'; 'Wayne Wooster'; 'Wendy Wollf; 'William Van Dyke'; Aubert, Winton G (DOA) (winton.aubert@alaska.gov); Ballantine, Tab A (LAW); Brooks, Phoebe L (DOA) (phoebe.brooks @alaska.gov); Colombie, Jody J (DOA) (jody.colombie @alaska.gov); Crisp, John H (DOA) (john.crisp @alaska.gov); Davies, Stephen F (DOA) (steve.davies @alaska.gov); Foerster, Catherine P (DOA) (cathy.foerster @alaska.gov); Grimaldi, Louis R (DOA) (lou.grimaldi @alaska.gov); Herrera, Matt F (DOA); Johnson, Elaine M (DOA) (elaine.johnson @ alaska.gov); Jones, Jeffery B (DOA) (jeff.jones @alaska.gov); Laasch, Linda K (DOA) (linda.laasch @alaska.gov); Maunder, Thomas E (DOA) (tom.maunder @alaska.gov); McIver, Bren (DOA) (bren.mciver @alaska.gov); McMains, Stephen E (DOA) (steve.mcmains @alaska.gov); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA) (bob.noble @alaska.gov); Norman, John K (DOA) (john.norman @alaska.gov); Okland, Howard D (DOA) (howard.okland @alaska.gov); Paladijczuk, Tracie L (DOA) ( tracie.paladijczuk @alaska.gov); Pasqual, Maria (DOA) (maria.pasqual @alaska.gov); Regg, James B (DOA) (jim.regg @alaska.gov); Roby, David S (DOA) (dave.roby @alaska.gov); Saltmarsh, Arthur C (DOA) (art.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) Subject: co432d -010, co406b -010, co430a -009, co435a -008, co456a -008, co443b -001, co562 -003, co569 -002, co605 -001 (Kuparuk and Colville) Attachments: co605- 001.pdf 1 • • 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 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 Borou 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 cr` Q � c-4 A L A S-" K A--,, GOVERNOR BILL WALKER Ms. Misty Alexa Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL CONSERVATION ORDER NO.562.004 CONSERVATION ORDER NO.569.003 CONSERVATION ORDER NO.605.002 Manager, WNS Development ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: CO-15-007 333 West Seventn Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.aiaska.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 tect data for a minimum of five vears. DONE at Anchorage, Alaska and dated August 6, 2015. Cathy . Foerster Daniel T. Sea 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: AKDCWeIIIntegrityCoordinator, Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew Vandedack; 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, James J (DNR); Jason Bergerson; jill.a.mcleod@conocophillips.com; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Kenneth Luckey; King, Kathleen 1 (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Matt Gill; Franger, James M (DNR); Morgan, Kirk A (DNR); Pat Galvin; Bettis, Patricia K (DOA); Pete Dickinson; Peter Contreras; Richard Garrard; Robert Province; Ryan Daniel; Sandra Lemke; Sarah Baker, Peterson, Shaun (DNR); Pollard, Susan R (LAW); Talib Syed; Terence Dalton; Tina Grovier (tmgrovier@stoel.com); Todd, Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster, William Hutto; William Van Dyke; Ballantine, Tab A (LAW); Bender, Makana K (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Crisp, John H (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Herrera, Matthew F (DOA); Hill, Johnnie W (DOA); Hunt, Jennifer L (DOA); Jackson, Jasper C (DOA); Jones, Jeffery B (DOA); Kair, Michael N (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, To: Angela K (DOA); Wallace, Chris D (DOA) Subject: CO 569.003, CO 605.002, CO 562.004 (Colville River Field) Attachments: co569-003.pdf, co605-002.pdf, co562-004.pdf Please see attached. Samantha Carlisle Executive Secretary II Alaska Oil and Gas Conservation Commission 333 West Th Avenue Anchorage, AK 99501 (907) 793-1223 (phone) (907) 276-7542 (fax) CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Samantha Carlisle at (907) 793-1223 or Samantha.Carlisle4alaska.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 20 Aziz, C)L�`&~ Angela K. Singh THE STATE "ALASKA GOVERNOR BILL WALKER Ms. Misty Alexa Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL CONSERVATION ORDER NO.562.004 CONSERVATION ORDER NO. 569.003 CONSERVATION ORDER NO. 605.002 (Corrected) Manager, WNS Development ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: CO-15-007 333 west Sevensh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.alaska.gov Request for administrative approval to waive the monthly production allocation reporting requirement for the Nanuq Oil Pool, Fiord Oil Pool, and Qannik Oil Pool in the Colville River Field. Dear Ms. Alexa: It has come to the attention of the AOGCC that the Conservation Order number that was used through this order was incorrect, it has now been corrected. By letter dated June 16, 2015, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to waive the requirement for monthly reporting of daily allocation and test data contained in Rule 7(e) of Conservation Order No. (CO) 562 and Rule 6(e) of CO's 569 and 605. In accordance with Rule 12 of the orders, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request for administrative approval to waive the requirement to submit monthly reports of daily allocation and test data. Rule 7 of CO 562 and rule 6 of COs 569 and 605 states: (e) The operator shall submit a monthly report and electronic file(s) containing daily allocation data and daily test data for agency surveillance and evaluation. Part (f) of these rules require an annual allocation review report accompany the annual reservoir surveillance report. Receiving an annual report on the production allocation and well test data and retaining the ability to review the daily data if necessary allows the AOGCC to verify the performance of the well testing and allocation system without the need for monthly reports on the same data. CO 562.004, CO 569.003, & CO 605.002 (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 tunc August ; Cath P. Foerster Daniel T. Sew6ount, Jr.� Chair, Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE i If )N 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); AKDCWeIIIntegrityCoordinator; Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew VanderJack, Anna Raff; Barbara F Fullmer, bbritch; Becca Hulme; bbohrer@ap.org; Bob Shavelson; Brian Havelock; Bruce Webb; Burdick, John D (DNR); Carrie Wong; Cliff Posey; Colleen Miller; Crandall, Krissell; D Lawrence; Dave Harbour; David Boelens; David Duffy; David House; David McCaleb; David Steingreaber; David Tetta; Davide Simeone; ddonkel@cfl.rr.com; Dean Gallegos; Delbridge, Rena E (LAS); DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Frank Molli; Gary Oskolkosf, George Pollock, ghammons; Gordon Pospisil; Greg Duggin; Gregg Nady; gspfof, ,, Jacki Rose; Jdarlington oarlington@gmail.com); Jeanne McPherren; Williams, Jennifer L (LAW); Jerry Hodgden; Jerry McCutcheon; Solnick, Jessica D (LAW); Jim Watt; Jim White; Joe Lastufka; news@radiokenai.com; John Adams; Easton, John R (DNR); Jon Goltz; Juanita Lovett; Judy Stanek; Houle, Julie (DNR); Julie Little; Kari Moriarty, Kazeem Adegbola; Keith Wiles; Kelly Sperback; Gregersen, Laura S (DNR); Leslie Smith; Lisa Parker, Louisiana Cutler, Luke Keller, Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Kremer, Marguerite C (DNR); Mary Cocklan-Vendl; Michael Calkins; Michael Duncan; Michael Moora; Mike Bill; mike@kbbi.org; Mikel Schultz; MJ Loveland; mkm7200; Morones, Mark P (DNR); Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nick W. Glover; Nikki Martin; NSK Problem Well Supv; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Renan Yanish; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly, Sharmaine Copeland; Sharon Yarawsky, Shellenbaum, Diane P (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Sternicki, Oliver R; Moothart, Steve R (DNR); Suzanne Gibson; sheffield@aoga.org; Tania Ramos; Ted Kramer, Davidson, Temple (DNR); Terence Dalton; Teresa Imm; Terry Templeman; Thor Cutler, Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater, Anne Hillman; Bajsarowicz, Caroline J; Brian Gross; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Don Shaw; Donna Vukich; Eric Lidji; Erik Opstad; Gary Orr, Smith, Graham O (PCO); Greg Mattson; Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Holly Pearen; Hyun, James J (DNR); Jason Bergerson; jill.a.mcleod@conocophillips.com; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Kenneth Luckey; King, Kathleen J (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Matt Gill; Franger, James M (DNR); Morgan, Kirk A (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Sarah Baker, Peterson, Shaun (DNR); Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); Todd, Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster, William Hutto; William Van Dyke Subject: Corrected CO 605-002 Attachments: co605-002 corrected.pdf James Gibbs Jack Hakkila Bernie Karl P.O. Box 1597 P.O. Box 190083 K&K Recycling Inc. Soldotna, AK 99669 Anchorage, AK 99519 P.O. Box 58055 Fairbanks, AK 99711 Gordon Severson Penny Vadla George Vaught, Jr. 3201 Westmar Cir. 399 W. Riverview Ave. P.O. Box 13557 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Ms. Misty Alexa Richard Wagner Darwin Waldsmith Manager, WNS Development P.O. Box 60868 P.O. Box 39309 ConocoPhillips Alaska, Inc. Fairbanks, AK 99706 Ninilchik, AK 99639 P.O. Box 100360 Anchorage, AK 99510-0360 y-&�ctLQO Angela K. Singh THE STATE °fALASKA I -I GOVERNOR BILL WALKER Mr. Stephen Thatcher Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVALS CONSERVATION ORDER NO. 443C.001 CONSERVATION ORDER NO. 562.005 CONSERVATION ORDER NO. 569.004 CONSERVATION ORDER NO. 605.003 Manager, WMS Development North Slope Operations and Development ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510 Re: Docket Number: CO -18-002 and AIO-18-014 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc,oiaska.gov Request for administrative approval to amend allowable gas offtake for the Colville River Field and authorize surface commingling of production from the Lookout Oil Pool with production from the Fiord and Qannik Oil Pools. Colville River Field Colville River Unit Alpine Oil Pool Nanuq Oil Pool Fiord Oil Pool Qannik Oil Pool Dear Mr. Thatcher: By letter dated February 28, 2018, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to amend the allowable gas offtake rate established for the Colville River Field (CRF) to increase the allowable rate from 1 MMSCFPD to 7 MMSCFPD to allow for development of the Lookout Oil Pool (LOP) in the Greater Moose's Tooth Unit (GMTU). By a different letter also dated February 28, 2018, CPAI requested administrative approval to amend the Common Production Facilities and Surface Commingling rules for the Fiord and Qannik Oil Pools to allow commingling production on the surface with production from the LOP.' ' The Alpine and Nanuq Oil Pools pool rules do not contain a rule that would preclude commingling those pools with the LOP. CO 443C.001, CO 562.005, CO 569.004, and CO 650.003 August 13, 2018 Page 2 of 4 In accordance with Rule 11 of Conservation Order No. (CO) 443C and Rule 12 of COs 562, 569, and 605, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request to increase the allowable gas offtake rate from the CRF. On February 13, 2007, the Alaska Oil and Gas Conservation Commission (AOGCC) authorized a 1 MMSCFPD gas offtake from the CRF for the sole purpose of meeting contractual obligations to ship gas from the CRF to the village of Nuiqsut. CPAI plans to begin production from the LOP in GMTU in late 2018 and has requested authority to ship gas from the CRF to the GMTU to support LOP development. The LOP is expected to routinely produce significant excess gas that will be shipped, along with the produced oil and water, to the Alpine Central Facility (ACF) where the gas will be returned to the LOP, used for lease operations within the CRF, or injected into the pools in the CRF for EOR purposes. However, prior to initial production the GMTV 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 GMTV. 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. Any new pools that process production at the ACF will be subject to the terms of this administrative approval. Rule 6 of CO 569 is amended to read as follows: Rule 6 Common Production Facilities and Surface Commingling a. Production from the Fiord Oil Pool may be commingled with production from other CRU pools and the Lookout Oil Pool in surface facilities prior to custody transfer. b. Production shall be allocated to wells within the Fiord Oil Pool in accordance with the procedures described in Section 5.0 of ConocoPhillips' application dated November 22, 2005. c. Each producing well must be tested a minimum of twice per month. d. The Commission may require more frequent or longer tests if the allocation quality deteriorates. e. The operator shall retain electronic file(s) containing daily allocation data and daily test data for a minimum of five years. f. The operator shall provide the Commission with a well test and allocation review report in conjunction with an annual reservoir surveillance report. CO 443C.001, CO 562.005, CO 569.004, and CO 650.003 August 13, 2018 Page 4 of 4 And Rule 6 of CO 605 is amended to read as follows: Rule 6 Common Production Facilities and Surface Commimline 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. -t""L� P Hollis S. French Cath P. oerster Daniel T. Seamount, Jr. Chair, Commissioner Commissioner Commissioner NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default 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 unti15:00 p.m. on the next day that does not fall on a weekend or state holiday. I I1: Sl ATY °ALASKA. (jW-ERNuR 1;111 N\"Al KH' 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 oogccalaska.gov Request for administrative. approval to amend allowable gas offtake for the Colville River Field and authorize surface commingling of production from the Lookout Oil Pool with production from the Fiord and Qannik Oil Pools. Colville River Field Colville River Unit Alpine Oil Pool Nanuq Oil Pool Fiord Oil Pool Qannik Oil Pool Dear Mr. Thatcher: By letter dated February 28, 2018, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to amend the allowable gas offtake rate established for the Colville River Field (CRF) to increase the allowable rate from 1 MMSCFPD to 7 MMSCFPD to allow for development of the Lookout Oil Pool (LOP) in the Greater Moose's Tooth Unit (GMTU). By a different letter also dated February 28, 2018, CPAI requested administrative approval to amend the Common Production Facilities and Surface Commingling rules for the Fiord and Qannik Oil Pools to allow commingling production on the surface with production from the LOP.' 1 The Alpine and Nanuq Oil Pools pool rules do not contain a rule that would preclude commingling those pools with the LOP. CO 443C.001, CO 562.005, CO 569.004, and CO 650.003 August 13, 2018 Page 2 of 4 In accordance with Rule 11 of Conservation Order No. (CO) 443C and Rule 12 of COs 562, 569, and 605, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request to increase the allowable gas offtake rate from the CRF. On February 13, 2007, the Alaska Oil and Gas Conservation Commission (AOGCC) authorized a 1 MMSCFPD gas of take 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 GMTV. The Fiord and Qannik Oil Pools are currently authorized to commingle production on the surface with production from other CRF oil pools. These rules need to be amended to allow the LOP production to be commingled as well. The LOP is an Alpine formation reservoir. As such, production from the LOP should be compatible with the CRF oil pools. The administrative action rules for the affected orders allow the AOGCC to amend an order administratively if the proposed action will not result in waste, will not jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in increased risk of fluid movement into freshwater. Waste is prevented because the long-term benefits of using the gas from the LOP for EOR purposes in the CRF far outweigh the short-term and largely negligible impacts of periodically shipping small volumes of gas from the CRF to the GMTU to support LOP development. Correlative rights are protected because all of the affected pools are within the Colville River Unit. Selling small volumes of gas from the CRF to the GMTU is based on sound engineering and geoscience practices because the sharing of production facilities and infrastructure will lessen environmental impacts and increase ultimate recovery through the sharing of expenses. Selling gas from one unit to another has no impacts on the risk of fluids moving into freshwater. CO 443C.001, CO 562.005, CO 569.004, and CO 650.003 August 13, 2018 Page 3 of 4 Now therefore it is ordered that Rule 12 of CO 443C and Rule 11 of CO 605 are amended to read as follows: Allowable Gas OffTake 1. The cumulative gas offtake rate from the CRF must not exceed 7 MMCFPD. 2. Natural gas may not be severed from the CRF for any other purpose than to meet ConocoPhillips' contractual obligations of providing the Village of Nuiqsut with natural gas and to support development of the Lookout Oil Pool in the Greater Moose's Tooth Unit. 3. Any new pools that process production at the ACF will be subject to the terms of this administrative approval. The conditions of approval in CO 562.001 and 569.001 are amended to read as follows: 1. The cumulative gas off take rate from the CRF must not exceed 7 MMCFPD. 2. Natural gas may not be severed from the CRF for any other purpose than to meet ConocoPhillips' contractual obligations of providing the Village of Nuiqsut with natural gas and to support development of the Lookout Oil Pool in the Greater Moose's Tooth Unit. 3. Any new pools that process production at the ACF will be subject to the terms of this administrative approval. Rule 6 of CO 569 is amended to read as follows: Rule 6 Common Production Facilities and Surface Commingling a. Production from the Fiord Oil Pool may be commingled with production from other CRU pools and the Lookout Oil Pool in surface facilities prior to custody transfer. b. Production shall be allocated to wells within the Fiord Oil Pool in accordance with the procedures described in Section 5.0 of ConocoPhillips' application dated November 22, 2005. c. Each producing well must be tested a minimum of twice per month. d. The Commission may require more frequent or longer tests if the allocation quality deteriorates. e. The operator shall retain electronic file(s) containing daily allocation data and daily test data for a minimum of five years. f The operator shall provide the Commission with a well test and allocation review report in conjunction with an annual reservoir surveillance report. CO 443C.001, CO 562.005, CO 569.004, and CO 650.003 August 13, 2018 Page 4 of 4 And Rule 6 of CO 605 is amended to read as follows: Rule 6 Common Production Facilities and Surface Commin¢lin¢ 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 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 coup. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 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 �-14M X Conor Ph1111 S February 28, 2018 Stephen Thatcher Manager, WNS Development North Slope Operations and Development Con000Phillips Alaska, Inc. ATO -1770 700 G Street Anchorage, AK 99501 phone 907.263.4464 Hollis French, Chair MAR 0 t 2018 Alaska Oil and Gas Conservation Commission 333 W. 7th Ave #100 O G' ! C C 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 D LL U 3 2 1 0 Jan -18 Jan -23 Jan -28 Jan -33 Jan -38 Figure 1. Forecasted Gas Sales from CRU to GMTU 45,000 40,000 35,000 30,000 V 25,000 S` 20,000 15,000 10,000 5,000 Jan -18 Jarf23 Jan -28 JarF33 Jan -38 Figure 2. Cumulative Net GMTU Gas Injection into CRU Jan -43 Jan -43 Application to Amend CRU AGOTR February 28, 2018 Page 5 of 5 90 84 70 e I Assumed Conditions Pressure =3750psia to Temperature a 197' F ppu I Current Injectant MW-23.3lb/lb-mo1 E 0 20 It. 0 60 80 100 Pore Volumes of Gas Injected, % PV Current ACF Injectant Lean Gas 1 a e a z s K 0 67 3 324 140 160 - can Gas- Current Compast Tonal Blend -a 1ov Enrichingfluid-- UrLErricWng Fluid- 205A Enriching Fluid Figure 3. Simulated Oil Benefit of Gas Injection E:? ConocoPhillips February 28, 2018 Hollis French, Chair Alaska Oil and Gas Conservation Commission 333 W. 7th Ave #100 Anchorage, Alaska, 99501-3539 Stephen Thatcher Manager, WINS Development North Slope Operations and Development ConocoPhillips Alaska, Inc. ATO -1770 700 G Street Anchorage, AK 99501 phone 907.263.4464 EGr::iV MAR 01 2018 RE: Request for Administrative Amendments, Colville River Unit, North Slope, AK Dear Commissioner French, ConocoPhillips Alaska, Inc. ("CPAP') as operator of the Colville River Unit ("CRU") and Greater Mooses Tooth Unit ("GMTU"), requests that the Alaska Oil and Gas Conservation Commission administratively amend area injection orders for the Fiord, Nanuq, and Qannik oil pools to allow injection of GMTU Lookout Oil Pool ("LOP") produced water into any of the other CRU oil pools. CPAI also requests that the conservation orders for the Fiord and Qannik oil pools be amended to allow commingling of LOP production in surface facilities prior to custody transfer. This request is being made concurrently with applications for a LOP Conservation Order and Area Injection Order. Those applications provide further background for this request. The CO application explains that LOP production is expected to be compatible with production from the CRU oil pools. The Fiord, Nanuq and Qannik pools area injection orders have specific rules for "fluids authorized for injection." LOP produced water is not specifically listed as a fluid authorized for injection. The recent Commission order authorizing the expansion of the Alpine Pool Area Injection Order provides that "[p]roduced water from the Alpine Central Facility" is a fluid authorized for injection. See Area Injection Order No. 18D, Rule 1 b. CPAI requests that the Alpine pool language be used to amend the Fiord, Nanuq and Qannik area injection orders to allow for injection of any produced water from the Alpine Central Facility including LOP produced water injection. This amendment will provide for consistency in CRU oil pool area injection orders. 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, 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 ConocoPhillips June 16, 2015 " G IVED Misty Alexa Manager, WNS Development North Slope Operations & Development A0GCCPO BoxConocoP100360 hillips Alaska, Inc. 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 G, 6 , Manag r, Western North Slope Development Cc: Mike Nixson, Anadarko Bobby Donahue, Petro -Hunt Teresa Imm, ASRC Cord Feige, AK DNR Division of Oil & Gas t0 Roby, David S (DOA) From: Soria, Dora I [ Dora .I.Soria ©conocophillips.com] Sent: Wednesday, December 15, 2010 11:28 AM To: Roby, David S (DOA); Cellos, Harry S; Cologgi, John R; Parviz Mehdizadeh; Davidson, Temple (DNR); Dykstra, Jeffrey R (DNR); Konsor, Alicia G (DNR); Heumann, Michael P (DNR) Cc: Fullmer, Barbara F (LDZX) Subject: RE: Attendance sheet Importance: High All, This is a reminder that certain portions of the report CPAI presented yesterday are confidential as follows: The information in Appendices 3 and 4 of the AOGCC `Application Report" for the MPM Multiphase Metering System provided by ConocoPhillips Alaska, Inc., as Operator ( "ConocoPhillips "), is confidential and proprietary to ConocoPhillips and is not subject to disclosure because it contains information or data that is (1). trade secret information as defined in AS 45.50.940(3) and State v. Arctic Slope Regional Corp., 834 P.2d 134 (Alaska 1991); (2).required to be held confidential under AS 38.05.035(a)(8); (3). exempted from disclosure under 5 U.S.C. 552(b)(4) or (b) (9); and /or (4). required to be held confidential under AS 31.05.035(d). Best regards and Happy Holidays! -dora Dora I. Soria Staff Landman ConocoPhillips Alaska, Inc. Exploration and Land P.O. Box 100360, Anchorage, AK 99510 email - dora .i.soria(a�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); Heumann, 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 2 • evAk M \ A?p I caki,`civ\ c,- Na -- PrevIpk Uukrte yl 26 7- 70 z,z cu4P16.7 and- / -- e P.0 btif(s 3 75 g z 33 o kg, ("C 61-Ar Arei CW/eiS J7/ cp/c2 AO, /2 496 C • plaa)crt- Lz6u1. NWned, Geort WibPs. 355132 ae ;iei JOAO3 • i 700 G Street Anchorage, AK 99501 ConocoPhil lips Phone: 907 - 263 -3701 December 14, 2010 Daniel T Seamount Jr., Commissioner` r. Alaska Oil & Gas Conservation Commission 333 West 7 Avenue, Suite 100 S EC 9 ' �� Anchorage, AK 99501 fJ4)yK4 WI i., Re: Application Report for MPM Multiphase Metering System AV, $ c • Comps and Request for Approval of Amendments to Conservation Orders or age 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 Se above mentioned tests. Taking into iount 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. i�icerely, ) Ad" 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. - re � AS2C 8; , � ; II Report • • ConocoPhillips CPAI AOGCC "Application Report" for the MPM Multiphase Metering System 0 MultiPhaseMeters Prepared Parviz Mehdizadeh and Gordon Stobie 12/14/2010 • 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). • • CPAI AOGCC "Application Report" for the MPM Multiphase Metering System Prepared Parviz Mehdizadeh and Gordon Stobie 11/11/2010 • 12- 02- 2010AOGCC NIPM for Approval (2).doe 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) 8 Table 5 - Summary of Alpine Tests 8 Table 6 - Summary of Alpine Test Results - Accumulated Delta Relative to Test Separator 8 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. 8 Figure 7 — Water Cut comparison MPM Meter to Test Separator The dotted lines show the ± 5% variation band 8 Figure 8 — Oil flow comparison MPM Meter to Test Separator the dotted lines show the ±10% variation band. 8 Figure 9 — Mass Gas flow comparison MPM Meter to Test Separator. Dotted lines show the ±10% variation band. 8 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. 8 Table 7- Raw and Post Process MPM Gas Data 8 6 — Further Field and Flow Loop Testing 8 Table 8 - Flow Conditions and Fluid Properties In MPM Tests 8 Table 9- Summary of Field and Flow Loop Test Results 8 7. Factory Acceptance Tests (FAT) 8 8. Field Maintenance and Periodic Calibration 8 9. List of References 8 10. List of Appendices - Supportive Documents 8 1 -17 •2- 02- 2010AoGCC MPM for Approval (2).doc• AOGCC "Application Report" for MPM Multiphase Measurement System 1. Introduction This document describes the design and performance of the MPM multiphase metering system — hereafter referred to as MPM - designed for well testing in operating areas shown in Appendix 1. This report compiles the test data and literature that was used to qualify the design and establish performance levels for the MPM. This document is to be submitted to Alaska Oil and Gas Conservation Commission (AOGCC) as an "Application Report" to obtain their approval for using the MPM as an alternative to conventional gravity based test separators for well testing. The "Guidelines for Qualification of Multiphase Metering Systems for Well Testing" issued by AOGCC, requires operators to submit an "Application Report" before new metering systems are used for production well testing and allocations. This CPAI "Application Report" provides the information that is requested in the Section 3 of the AOGCC document. 2- MPM Meter Development History The MPM multiphase metering system has been developed by Multi Phase Meters AS (MPM) in Norway under a Joint Industry Project supported and directed by ConocoPhillips, ENI, Hydro, Shell, Statoil and Total. A comprehensive test and qualification program was established by the participating members to be able to qualify the MPM Meter for use in field applications. The first part of this qualification program consisted of testing the meter in the MPM Flow Laboratory. Following successful completion of the vendor flow loop tests, the MPM meter was taken to K -Lab in Norway for the first performance tests in October 2006. After successfull flow test at K -Lab the meter was made available commercially. Many of the JIP Partners bought meters for further field testing. ConocoPhillips purchased an MPM meter and conducted field performance trials of the meter at their North Sea Ekofisk facility. Other specific application field trials were also conducted. The results from all the field trials are discussed in Section 6 of this report. At this time 83 MPM meters have been sold for various applications - of these 31 units have been commissioned, and the first commenced operating in October 2007 as shown in Table 1. After a comprehensive review of the performance records of MPM meter from flow loops and field trials, CPAI selected the MPM multiphase metering system for field tests at Alpine. The results from these field tests are reported in Section 5 of this application. The Alpine tests have demonstrated that the MPM meter has suitable measurement capabilities for well testing. 3. Proposed Applications The proposed MPM multiphase metering system is designed to be used either as permanent wellhead installation or mobile systems deployed in a field. Information and data presented in 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 % 2 -17 0 12- 02- 201 0A0GCC' MPM for Approval (2).doe when compared to a test separator system. This level of performance has been demonstrated under flow conditions that cover a wide range of fluid properties, water cuts, and gas void fractions. Appendix 1 shows the wells and production horizons for which CPAI is the Operator or has working interests in that may use the proposed multiphase metering unit. This Appendix also shows the working interest owners. All parties with working interest, royalty ownership, as well as the Alaska Department of Revenue will be notified about the use of the MPM meters when the application of the metering system affects such interests. The allocation methodology currently practiced at CPAI operating fields will not be affected by the application of the MPM metering technology. The well head conditions and range of fluid properties at the CPAI Proposed Sites for MPM Installations are shown in Table 2. Table 1 - Current MPM Installations Project Country Operator Units Size MP WG Installed Morvin (subsea) Norway Statoil 4 3" v 8/1/2010 Champion West Brunei BSP 1 3" v 6/2/2010 Ebla Syria PetroCanada 1 5" v v 5/30/2010 Baraka Tunisia ENI 1 3" v 5/15/2010 Welltesting Oman PDO 1 3" v v 11/10/2009 Oseberg Low Pressure Norway Statoil 4 3" v v 3/1/2010 Oseberg B46 Norway Statoil 1 5" v 9/15/2009 Bardolino -Howe UK Shell UK 1 5 v 8/15/2009 Penguin UK Shell U.K. 1 10" v 8/15/2009 Nini Ost Denmark Dong 1 5" v 2/20/2010 Oseberg B30 Norway StatoilHydro 1 5" v 12/1/2008 Oman Well Testing Oman MB Petroleum 1 3" v 8/1/2008 Blacktip Australia ENI 2 5" v 9/15/2009 Maamoura Tunisia ENI 3 2 " -3" v 12/18/2009 Separation Module Norway StatoilHydro 1 2" v 10/1/2008 Compression project Norway StatoilHydro 1 10" v 1/1/2008 Oseberg B28 Norway StatoilHydro 1 5" v 3/1/2008 Vega Norway StatoilHydro 1 5" v 10/1/2007 Ekofisk 2/4 M Norway Conoco Phillips 1 5" v v 10/1/2007 Separation module Norway StatoilHydro 1 3" v v 10/1/2007 Separation module Norway StatoilHydro 1 3" v v 10/1/2007 Gullfaks A Norway StatoilHydro 1 3" v 10/1/2006 3 -17 •2- 02- 2010AOGCC MPM for Approval (2).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. 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 4 -17 • 12- 02- 2010AOGCC MPM for Approval (2).do• 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 ig Gamma Detector — — Single Energy Gamma Sensor Body Electronics/ Transmitters Flow computer (P, dP) %CO - 3D Broadband section Salinity Probe r' Termination Box Venturi Inlet connection Figure 1- The main components of the MPM meter 5 -17 0 2- 02- 2010AOGCC MPM for Approval (2).doc• V V V ` �J I / _ try„ ...,,„ ... , , ( , _ A .. 1 Figure 2 -The MPM Meter performs RF measurements in many different planes. A summary of the MPM measurement uncertainty specification is shown in Table 3. The full uncertainty specification is defined in Reference 2. The measurement specifications include sensitivity which is defined as the smallest change which can be reliably detected and trended. As noted previously, 31 MPM units have been installed in various fields shown in Table 1 for well testing and field allocation. Some have been operating since October 2007. The MPM meter is generally installed downstream of a blind tee in the flow line or as a part of wellhead spool. The proposed well head field configuration is shown schematically in Figure 3. Installation procedures are described in Ap endix 2. A 1 1_ x woo al's! i R -mil 1 leaWM ITA - == li 11 - i V4 . a „�. cE >, "..'e.�M '568 GM- `S Figure 3 - Schematic of the MPM Well Head configuration 6 -17 • 12- 02- 2010AOGCC MPM for Approval (2).do. Table 3 — Summary of MPM Accuracy (Uncertainty) Specifications at 95% confidence level Topside & Subsea Meter Uncertainty ,,,;, Sensitivity MultiPhase Mode GVF range - % GVF WLR 0 -80 80 -95 0 -95% Gas Flow Rate 0 - 100% 5 % _ 5 % ± 0,5 % Liquid Flow Rate 0 - 100% 2.5 % 5 % ± 0,3 % WLR 5 °.%0 & 7 1 % 1 % ± 0,1 % 5 -85% 2% 2% ±0,2% WetGas Mode - 3 Phases (2) GVF range - % GVF WLR 90 - 95 95 - 98,5 90 - 98,5% Gas Flow Rate 0 - 100% 3 °0 3 % ± 0,5 % Liquid Flow Rate 0 -100% 4 °0 10 % ± 0,3 % Hydrocarbon mass flow 0 - 100% 3 •0 3 % ± 0,3 % Water Fraction tabs) 0 - 100% 0. 1 % 0.1 % ± 0,01 % WetGas Mode - 2 Phases (3) GVF range - % GVF WLR 90 - 95 95 - 99 99 - 100 90 - 100% Gas Flow Rate 0 - 100% 3 % 3 % 3 % ± 0,3 °J° Liquid Flow Rate 0 - 100% 3 % 5 % 15 % ± 0,3 % Hydrocarbon mass flow 0 - '100% 2.5 % 2.5 % 2.5 % ± 0,2 % Water Fraction (abs) -: '15% 0.04 % 0.04 % 0.02 % ± 0,003 % >15 °b 0.08 % 0.08 % 0.04 % ± 0,005 % Salinity Measurement Uncertainty < 50 mS /cm > 50 mS /cm Multi Phase (Salinity Probe) ±2 mS /cm (4) ±4 % rel (4) Wet Gas (S- curve) ± 50 mS /cm (6) ± 50 mSfcm (6) 5. Performance of MPM at Alpine The testing was performed at Alpine Field. A 3 "NB, Beta 0.55 MPM meter was installed in series with a compact two phase separator as shown schematically in Figure 4 Alaskan Multiphase Meter Test Test Schematic • Test Separator Flow from wells 16ft by 5ft Dia • • MPM Figure 4- Schematic of MPM Installations at Alpine 7 -17 •2- 02- 2010AOGCC MPM for Approval (2).doc • 1 MP11 s low To T'est�; °- eparato . ('p'%ard Flow ir \IPM Figure 5 — MPM Meter installed at Alpine Figure 5 shows a photograph of the MPM installed at the well pad. The well pad consisted of producers and injectors. The injectors were on a miscible water - alternating -gas (MWAG) cycle. Many wells utilize lift gas (so produced gas composition can vary from well to well). The Alpine well pad ( CD -1 ) selected for testing consisted of 24 producers. The use of the 3" MPM meter available for the tests restricted some of the larger producers on the well pad from being tested. As a result only 16 wells were tested. The trials were conducted during March -April 2010. The liquid flow rates, gas flow rates, GVF, and WC were in the following ranges: • Fluid Flow Rates 300 -5200 BPD • Gas Flow Rates 4 -8 MMSCFD • Water Cut Range 19% -95% ( although 99% was observed) • GVF Range 88 -90% (although 100% was observed) • Flow Line Pressure 145 - 200 psig • Flow Line Temperature 68 -86 °F • API Oil Gravity 40 Table 4 shows the wells tested, number of tests and average test durations. The test results are summarized in Table 5. The liquid and oil volumes are reported in BBL, gas volume is reported in Mscf (although later comparisons are in gas mass flow), deviations are reported in percentage. Well tests varied in duration from 3 to 25 hours — based on operational experience with the wells. There were some relatively stable, some slugging and some unstable wells. The total hours of well testing was in excess of 800 hours. The summation of test results shown in Table 5 illustrates similar performance to currently used well testing methodology. 8 -17 12- 02- 2010AOGCC MPM for Approval (2).dolp 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 16ft T -T by 5ft OD, 42 BBL capacity vessel. Gas was metered by a Micro Motion CMF300 Coriolis meter - capable of flow up to 9.4MMscfd with a DP <10psi. Vendor accuracy is quoted as ±0.35%. Considering the gas leg of the separator may carry some small amount of liquid (less than WG Type 1), the gas measurement is assumed to have an uncertainty of ± 4%. Liquid was metered by a Micro Motion CMF200 Coriolis meter. The meter had a 20:1 turndown — with a range of 660 to 13,200BBL /d with a DP < 0.2 psi. Vendor quoted accuracy for liquid measurements is ±0.1 % of rate. This accuracy level does not account for any gas carry under during slugging flow. An analysis of the Coriolis meter drive gains indicated that the meter was working well. Only six short (several minutes) durations when the meter drive gains peaked above 4V (of 14V) were noted. Based on these observations the uncertainty in liquid measurement is assumed to be ±2.5%. Water cut was monitored using a Phase Dynamics Inc.(PDI) online water cut monitor, backed up by Net oil Computation(NOC) density based calculations. It has been observed that the WC monitor has problems with WC's >75%, and in those cases the NOC density calculations have been used. The MPM Meter was installed downstream of a 3" blind tee in the test separator module. The well fluids moved upward through the MPM and downward to the Test Separator. Figures 6 to 9 show graphs of the well test results for liquid rate, water cut, oil rate, and gas rate. In each graph the data from the MPM is plotted against the data from test separator. Generally the MPM meter and the test separator tracked each other well. The average of the differences from all 80 well tests are shown in Table 5. The gas data has a positive bias. MPM were encouraged to review the data with that in mind. MPM did review the data and found that: • two wells slugged so badly that the DP cells saturated at 5000mbar (72.5 psi DP) and these results were eliminated from the data set. 9 -17 •2- 02- 2010AOGCC MPM for Approval (2).doc• • The PVT gas density calculated based on the composition provided by CPAI and the in -situ density seen from the gamma densitometer varied by about 0.5Kg/M3 relative to a base density of about 12Kg /m3. Using the above corrections, i.e. eliminating the saturated DP cell flow data and reprocessing the data with in -situ gas density, the differences were reduced as shown in Table 6. Table 5 - Summary of Alpine Tests Alpine Separator MPM Deviations ( %) Well Liq Oil Water Gas WC Liq Oil Water Gas WC Liq Oil Water Gas WC 4 4784.0 345.4 4438.6 5795.0 92.8 4219.8 340.2 3879.6 6237.9 91.9 -11.8 -1.5 -12.6 7.6 -0.8 8 434.9 242.6 192.3 4118.6 44.2 371.6 158.2 213.4 4473.1 57.4 -14.6 -34.8 10.9 8.6 13.2 12 1284.8 881.3 403.5 3410.1 31.4 1286.7 921.8 364.9 3856.1 28.4 0.2 4.6 -9.6 13.1 -3.1 18 1880.1 803.9 1076.2 4335.3 57.2 1753.4 818.1 935.3 4772.2 53.3 -6.7 1.8 -13.1 10.1 -3.9 24 2184.0 702.1 1482.0 6492.6 67.9 2186.3 620.5 1565.8 6983.7 71.6 0.1 -11.6 5.7 7.6 3.8 25 2375.4 1089.8 1285.6 7535.1 54.1 2486.7 1126.7 1359.9 7781.8 54.7 4.7 3.4 5.8 3.3 0.6 27 2142.4 661.4 1481.0 7210.3 69.1 2172.7 812.5 1360.2 7546.1 62.6 1.4 22.8 -8.2 4.7 -6.5 28 572.2 121.0 451.2 2844.4 78.9 614.9 157.5 457.4 3069.5 74.4 7.5 30.2 1.4 7.9 -4.5 32 2347.5 775.7 1571.8 5662.8 67.0 2277.9 671.7 1606.2 6303.8 70.5 -3.0 -13.4 2.2 11.3 3.6 34 343.7 276.8 66.9 2865.6 19.5 257.2 183.5 73.7 3308.7 28.7 -25.1 -33.7 10.2 15.5 9.2 35 3486.8 1251.7 2235.2 6773.4 64.1 3223.1 1045.6 2177.4 7423.6 67.6 -7.6 -16.5 -2.6 9.6 3.5 38 1655.7 664.9 990.8 5296.7 59.8 1674.4 653.3 1021.2 5534.5 61.0 1.1 -1.7 3.1 4.5 1.1 40 1273.9 792.6 481.2 4679.2 37.8 1209.4 815.8 393.5 4920.0 32.5 -5.1 2.9 -18.2 5.1 -5.2 41 1809.9 1252.1 557.8 7756.5 30.8 1657.3 1247.0 410.3 7809.0 24.8 -8.4 -0.4 -26.4 0.7 -6.1 43 818.4 432.0 386.3 4060.1 47.2 725.4 343.0 382.4 4435.1 52.7 -11.4 -20.6 -1.0 9.2 5.5 44 1675.9 1223.0 452.8 4888.8 27.0 1590.7 1178.6 412.1 5340.3 25.9 -5.1 -3.6 -9.0 9.2 -1.1 I 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 (2).doilb 804X1 5040 N- 4 ` • i 4000 - .' r ' f` f' L. 3050 - • 2000 - t DP saturated 5004 mbar oegiret 2 1000 - 0 0 1000 ,?000 3000 4000 4000 60001 Alpine separator Ilqufd flowradte (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. 100 r .. ../. ' 0 - ot _:'" - 3 .� r -4 10 - 0 10 20 00 70 00 90 '00 Alpine separator wailer out 110 Figure 7 — Water Cut comparison MPM Meter to Test Separator The dotted lines show the ± 5% variation band 11 -17 .2- 02- 2010AOGCC MPM for Approval (2).doc • L r f , •wr ,-- - �r »s 7 1 'CC - i " r ' ti r r CD r O ,. m .-° j 1000 - ® • t z r .A 3 500 - f ` y .+ ,' r'♦ r l F :. 0 500 1000 1500 2000 2500 Alpine separator oil flawrate (stb /d) Figure 8 — Oil flow comparison MPM Meter to Test Separator the dotted lines show the ±10% variation band. 1Q0o -r r 1 - -T - - "3 - + �. _ r +'�. • f a .s r .r in to:* r' Pi ¢ ,s • ,- 4. � r 0 * 000 ; n I ms r . a dQ 22, "r r s -- 1000 a rt - �`` : - ... _.. .... t .. . „�... 0 1000 2000 X100 1000 5020 00 i 7200 0000 2000 .. XII .Alpine separator gas 11owrale Obit) 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 (2).do. 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. 12 3118111145011.41111M to 8 -Gas Density PVT lkg/m3] 6 - Measured Gas Density 4 [kg/m3] 2 0 O N M `7 ul lD n 00 0 0 •-4 N r M M rY r4 - 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 [ %] [0/] 4 5795 7.6 2.3 DP >5000m bar 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 >5000mbar cut off 38 5296.7 4.5 -0.7 40 4679.2 5.1 -0.1 41 7756.5 0.7 -4.4 43 4060.1 9.2 3.8 44 4888.8 9.2 3.8 Total 7.3 1.9 All data 13 - 17 •2- 02- 2010A0GCC MPM for Approval (2).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- 2410AOGCC MPM for Approval (2).doll, Table 8 - Flow Conditions and Fluid Properties In MPM Tests Test Location Liq Range Gas Range WLR Range GVF Range Pressure Temp .` API Gravity. Comments BPD MMSCFD P51 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 SWRI 0 -150 8.5- 33.9 0-25% 95 -100 1750 -2940 112 961600)560 Variable water salinity Ekofisk 0 8300 1.7 -13.6 0-100%R *, 0- 100 %R * 88 300 -350 78 -205 35 Stable and Slugging 1.5 -48% N 97 %N flow K -Lab 2008 24 Month Wet Gas NA NA 0 -100 94-100 450 -1800 65 -130 94 -100 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 Oil Viscosity- Rates Unavailable for Heavy 011 NA NA 0-90 0-98 105 -180 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 Liquid Gas I WC I Oil I Water Reference Used MPM Flow Lab ±1.1% ±1.23% NA 1.2% +0.03% Loop Sep - 2 K -Lab Blind ±0.1 % ±1.4% NA 0.05% 1.2% Loop Sep -2 Gullfaks Dec 06 ±3.4% ±0.7% NA 1.7% r 0.83% Test Sep - 3 Phase -2 Gullfaks Jan 07 ±1.4% - 1.4% NA 0.82% r 1.36% Test Sep -3 Phase -1 SWRI Wet Gas * * ** ±0.7% 1.2 - 1.63% NA 0.96% r -2.6% Loop Sep -2 Phase -1 SWRI Wet Gas * * ** ±0.7% ±1.2 - 1.35% NA r +5.69% -2% Loop Sep - 3 Phase -1 Ekofisk * ** +1.2% +19.9 * ** +1.5 %abs +3% -5.8% Test Sep * ** K -Lab 2008 -2010 ±5 -10% ±5 -10% ±5 -10% ±5 -10% ±5 -10% Data not Released Alpine* -4.7% +7.3% 0.42% r +3.7% -5.4% Test Sep - 2 Phase -1 Alpine -Post Proc ** r -2.6% -0.4% r - 0.22% -2.1% -3.0% Test Sep - 2 Phase -1 Heavy Oil NA NA NA NA NA Test Sep CEESI - Wet Gas NA NA NA NA NA Loop Sep NOTES 1 = The values are reported on accumulative basis * Out of the box - no processing accumulated discrepancy MPM meter vs. Test Sep. Alpine data comprises >80 well test and 800 hours of flow ** Post Processed accumulated discrepancy MPM meter vs. Test Sep * ** Test comprised 76 well tests over 360hours of flow. These tests determined that the new Ekofisk 2/4M Test Separator Gas meter was in error. It was a multipath USM of a bounce path design and liquids (in the gas) contaminated the transducer signals. The MPM gas rates were confirmed as being `nearer to the expected figures' by the Reservoir Engineers from prior GOR knowledge (from 30 years prior production experience of the Ekofisk field). The MPM gas and oil data (converted to GOR) fits the earlier experience. * * ** 2Phase and 3Phase refers to the MPM Measurement Modes - each has its own advantages. 15 - 17 0 2- 02- 2010AOGCC MPM for Approval (2).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 Fosse' 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- 2010AOGCC MPM for Approval (2).doS 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% • • • • \-- -.0\ i „ , Na n ) - ":"' - : ---.1°--- Kogru River � Iaan � ,, 4”.„ _ ` ) nos a • „d„ NWMILNE1 P �f snwa Leo. y ,j �i Sr, ` F 1 ..aft OEW SITE _ pp - M `7 • �' ''\ A MINE SITES A �• • �� KRU •) . 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Bear Tooth Unit ,MP1 ?A 1' W AK1 . 1F, 11E 1D \ CD-4 UQ 1 PF -2 2D CD-6 L• • OUT y r ' e ' ) �.Y '2F ) '1L I_, ' 2E • i1J Colville';; fiver Um 4 2G 2 Kiiparuk River Unit to , a Wi l l CD -7 -'ARK NUIQSUT n. 1 / t i WSAK25618 Greater Mooses Tooth Unit % _J • i ll ff • I N \ '` / i W +E j \ �� J / S NPR - A � 1:340,000 \ ,,,,,„,. 0 1.252.5 5 7.5 10 r ,,,, Kuparuk River Unit Mites 4 Canada i i Alask. ` , ConocoPhillips 4 ' 1 ci j CPAI Operated Facilities r 1 '1 1 • Map 1 ~ - „ _ 10100701A00 10 -7 -10 Appendix 2 • • mpm Multi - Meters Appendix 2 MPM High Performance Flowmeters Installation and User Manual MPM Topside Meter 0 r r 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 mot sr teb-, 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 External communication ports 16 4.4 METER CONFIGURATION 16 4.4.1 PVT Data 16 4.4.2 Conversion to Standard Conditions 18 4.4.3 Two Phase wet gas Mode 19 4.4.4 Input of look -up tables 19 4.4.5 Continuous input of density values (Live PVT) 20 5 OPERATION 21 5.1 STARTING THE MPM USER INTERFACE 21 5.1.1 MPM Terminal 21 5.2 REMOTE ACCESS 21 5.2.1 Setting up the remote computer 21 5.2.2 Main page 22 5.2.3 Menu 23 5.24 The Information area 24 5.2.5 Graphics area 25 5.2.6 Status bar 26 5.3 ALARM STATUS 27 TD-010 — Installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 2 of 41 Project Confidential • • mpm Pdeur, 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: su000rt(a�mom- 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 f 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. y'u acer5.� e 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 • • mpm The MPM Meter is an in -line and full bore meter, based on conventional multiphase metering equipment in combination with the patented 3D- BroadBand 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 • • 111- in 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 __ M. DNV's recommended practice for qualifying new products; the RP A- 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) ,1` ' "� • ~.. Water Depth < 2700 m ...,.� OA The design and qualification program was further done in accordance to ""°"'""`° " "' " ▪ = - ..,,,_ • ISO 13628 ' wy,_� • API 17D/ API 6A. .:...,... > ,...��:"„ d4 • NACE compliance N.:4 ..„ o s,o.., 2.3 Topside Meter Components The Meter is built with all parts in one unit with little need for final assembly on site. The only part which needs to be assembled is the gamma source. The MPM Meter does all measurements and calculations locally in the meter electronics, and transmits the measured data to a SCADA (control system) at the host platform, and /or the MPM terminal (PC). The main components of the MPM Topside Meter are as follows: - Mechanical parts, including sensor, antennas and transmitters. - Electronics system. - MPM Terminal and Communication system. TD-010— Installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 7 of 41 Project Confidential • • MPM 2.4 Mechanical parts Outlet connection — 1 — Electronics Enclosure Gamma Detector — 41e $., SI 4siv — Single Energy Gamma • .....la Sensor Body "- a ° Electronics/ Transmitters !Mc, i i . Flow computer (P, dP) c.''t -.i y_ ``` i 3D Broadband �,�` Salinity Probe \if a � , t x." a section l k Venturi �.\� _. / Termination Box 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 tJ 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 software running on the electronics is the "brain" of the meter and does ,. all data recordings, calculations and transmittal to surface. • All electronics, apart from the gamma densitometer, are rated for the full industrial temperature range of -40 °C to 85 °C. When selecting the electronics units for the system, special attention was made towards finding modules with high MTBF figures which had undergone vibration and shock testing in addition to HALT (Highly Accelerated Life Time Test). TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 10 of 41 Project Confidential • • 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. _ • 10 MPM Meter electronics and MPM terminal Remote FIELD PC SENSOR AND ELECTRONICS 0 U Modbus mpm sass °rTCanP Flow / / t\ RF Termina�' Compute PC Sena( N Serial Electronics 0- � II o i t b ail = co SCADA Transmitte Sensor The MPM Meter communication protocol is MODBUS v1.1a. 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 • • Rip: 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 htPM terminal ( optional )— ft of e!er legging meter. It is possible to connect multiple meters to and one terminal. Its tasks comprise the following: eommunCann SvAiLit • Poll configured measurement variables at --- configured intervals. • Log the polled measurement variables. • Log alarms, events and diagnostic Database information from the connected meters • Create and distribute periodic reports for service personnel by e-mail, if l, ii SMTP f i server is available Web Service --1---- 1 • Run diagnostic functions '�� r • Upload software updates -, • Upload configuration /calibration data. • Update average values measurement data in the database. l I 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 • mM 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. Alt 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 s 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 t, e-set 3tc 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 [oto] Conclusion messages dPinlet 1 dPinlet 2 dPoutiet 1 dPoutiet 2 Temperature 1 Temperature 2 Pressure 1 Pressure 2 Gamma Detector TD-010 — Installation and User Manua{ — 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 external communication ports, data logging shall be started with a minimum poll rate of 1 Hz. 4.3.2.1 External Serial Ports — RS 485 Connect the MPM Terminal to COM 1, and perform logging of number of messages and errors for minimum 1 hour and fill in table below. Repeat for any additional COM ports on Meter. Acceptance Criteria: The test is accepted if the error rate is less than 0.1 %. Serial Port Number of Number of errors Error rate [ %) Conclusion messages COM 1 COM 2 The serial ports have been tested with Modbus poll and interface to the control system. No communication errors have been detected. 4.3.2.2 4.3.2.3 Ethernet (TCP /IP) Connect the MPM Terminal to communicate with the MPM Meter with Modbus over TCP /IP. Perform logging of number of messages and errors for minimum 1 hour and fill inn table below. Repeat for any additional Ethernet ports on Meter. Acceptance Criteria: The test is accepted if the error rate is less than 0.1 %. Communication Number of Number of errors Error rate [ %) Conclusion Channel messages Primary Eth1 port Primary Eth2 port* • Only applicable for electronics with redundant Ethernet 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 tums 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 Tess the same for all brands of meters. Except the fact that the MPM Meter can be outfitted with an option of Auto configuration functionality. With this functionality, the water conductivity is automatically measured by the Meter, and there would be no more need to provide manual input values (which would also eliminate the need for sampling). In the table below are listed the different configuration data. The table below also indicates the importance of the various configuration data in order to maintain the uncertainty specification for the meter. If some of these parameters are wrong, the meter will work, but some of the measurements may be outside the specified uncertainty limits. Key parameter Importance • Oil density Important, particularly at low GVF and low WLR • Gas density Important, particularly at high GVF • Water conductivity (low WLR) Less important • Water conductivity (high WLR) Very Important' • Water density Medium' • Surface tension oil /gas (P > 15 bar) Less important • Surface tension oil /gas (P < 15 bar) Important for wet gas flow conditions • Viscosity of gas Less important • Viscosity of oil (< 2 cP) Less important • Viscosity of oil (> 2 cP) Important, particularly for high viscosities All the parameters for the on 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 Zook -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 I Density t Mol % I Mol wt [kgim3l ' If the MPM Meter is equipped with the automatic configuration option (salinity measurement), the importance is low TD-010 — Installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 17 of 41 Project Confidential • • mpm 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 58,124 105 0,546 72,151 nC5 0,711 72,151 C6 1,197 85,300 C7 2,400 90,000 731,7 C8 2,710 103,700 755,8 C9 1,992 118,800 748,4 C10+ 23,889 298,700 913,8 Based on the composition, MPM can calculate all the required data for the oil and gas phase using Calsep PVTSim (Equation of State). The measurements from the MPM meter can together with together with Calsep PVTSim and the MPM Meter simulator also be used to verify the well composition. If the total composition is not known, the total composition may be derived from oil and gas samples at a known GOR. This may performed during the commissioning phase if pure oil and gas samples can be obtained under pressure. A total composition for the hydrocarbon phase can be obtained by analysing the gas and oil composition separately and recombining the composition for the oil and gas phase at the GOR measured by the MPM Meter. Please contact MPM for further details. Even if salinity measurements are included in the MPM meter, it is recommended to put in density and conductivity for the water as a fallback option until the meter has made a proper measurement. In order to calculate the PVT tables MPM need to be supplied with the following data: • Hydrocarbon composition of the actual well(s) • Operational range of temperature and pressure • Density for water at a given temperature (e.g. 15 degree Celsius) • Salinity or conductivity for the water Please also note that if measurements are done for Hydrocarbon Mass basis, then the oil and gas densities are of less importance since an overriding of the gas tends to be followed by a similar under reading of the oil and visa versa. 4.4.2 Conversion to Standard Conditions The MPM Meter can also provide measurement outputs at standard conditions or any other fixed temperature and pressure conditions such as test separator conditions. The conversion from actual to standard conditions can be done with or without phase transfer between the oil and gas phase. TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 18 of 41 Project Confidential • • mpm 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 Zook -up table for an oil to gas transfer factor is used to calculate net phase transfer from oil to gas (user selectable). The amount (in mass terms) of oil which is degassing is calculated by multiplying the oil mass rate at actual conditions by the oil to gas mass transfer factor. The mass which is degassing is added to free gas and divided by the density at standard conditions to obtain the total gas flow rate at standard conditions. The oil mass at standard • conditions is reduced by the amount (in mass terms) which is degassing such that the total hydrocarbon mass flow rate is unchanged. The look -up table for the oil to gas transfer factor can be calculated based on the composition of the well using a PVT simulator such as Calsep PVTSim and downloaded to the MPM Meter using the GUI. 4.4.3 Two Phase wet gas Mode In two phases wet gas mode the MPM Meter requires the GOR as an input parameter. The GOR can either be downloaded directly to the meter using live PVT as described in section 4.4.5 below or based on a temperature and pressure dependent look -up table. The look -up table can be calculated from the composition for the well. 4.4.4 Input of look -up on and gas densities tables PVT input type O dertdy tack oa density tksro In this case, oil and gas Pressure Patel densities are provided at 1 10 15 m 25 given pressures and 10 020 ex 8w a31 ego temperatures in tabular Temperature 30 OW 093 930 070 form. (deg CI Ia 930 am am 000 190 50 850 870 893 Aga 900 To find the correct densities Gas densky WWI for a given temperature and Pressure Pouf pressure, the Meter will do a 10 1001 1002 1003 1004 linear interpolation between 10 0 8 e a 8 the data points in the table. Temperature m 9 9 4 9 9 In the figure is shown typical [deg CI 10 10 1D 10 11 11 1 1 10 11 density table 50 12 12 12 12 t2 The other PVT data are keyed In via the GUI/ PMP ( OK (1 Cancel I 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 Zook -up tables are used. Hence, it is possible to use a combination of live PVT and look -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 i mpm 5 OPERATION 5.1 Starting the MPM User Interface 5.1.1 MPM Terminal Login - _= rX1 Click on the Icon for the MPM GUI, a login- window like User: 'User the one in Password: 1 Terminals: Figure 1 will appear. If the Name Server name/IP address desired MPM terminal is not available in the list, it must Loop -Terminal mpm bop Eamon 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 I Cancel 1 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 a • mpm 12..Jt =rcve ±,venue 5.2.2 Main page The Main Page of the user interface consists of a standard MS Windows GUI divided into three parts, a menu bar (top of window), an information area (left hand side of window) and a graphics area (see Figure 2). In addition, the status bar (lower part of the window) is used to give some information about the meter. The Main Page serves several purposes - Provide a trend of flow rates, fluid properties and flow condition — as a function of time. - Shows numerical, instantaneous values of flow rates, fluid properties and flow condition. - Display information of the meter state The menu gives access to meter configuration, adding or removing MPM Meters, select different trend, and look at diagnostics information. Consult MPM personnel in order to alter meter add or remove MPM Meters and to select the variables and units displayed in the main page. MPM GUI v3.0.0.2121 Subsea Prirraary> (1010) r tot and configuration Meter Sena D.agrostic 30 stem -- 1 1 - Update trends and values -- - - Trends — - - - - -- -- .. - - --- -- - - ® Update — a■ (m': r; Graph averages -- _- -. -- - _ - Oil. gas and water flow te r, (et 1"; Oil ' 60Irta'fi - Flow rates (Actual candtiar) Gas I G.QIm'fi OP ME m'm Gas i1i� T m'm Mater illliil E m'm Water 1.11111LE mum 1 .- - - - - [ Injected % m'm 3 , i Familial MEE m'fi Measured *mimes - - 1+AR a ^313302 "mica ltmrae uam ttseX t2MSC 'WVF li4 — ssi Ir, Graph averages - - -- GVF - . - --. - .. ' sabm , end Conductivity — :ere tTsrn GOR goimE m'Jm' Sal. , e - -_ Other Coed- Illll LE mstan Tleavening* r ' 3 Pressure ME WI g x I Density MU kg+m' dP =EC mar Velocity Imo E m St•A Rr: .�.: ,t - yf j t •1 water conductivity rnSkm 11rm "233s2 1=03 a a' wadsaririty NM � — TA - Graph averages - Scale Index lllllllll E*,: 1Y i ^,1R and GVF — 'h x WLR I 10C.[3� : . . - - - - - -- - - - GVF Illlllli`iC% - Activeprocess data set - -- - - -- - -- tc_ _a: - -- W1 -Sams Meter Number One e IG - Status I3I , -- - - - -- -- - S Q Stabs: OK tr c_ _q AAaterOndinre - - � 2 , - _z MPM t . 13.352591 11 UM 13.352591 "Mena umm umm ._------ _- --- m - - - - -__ 0 Undefined .O WGM mode (3phaae) 0 Measured w. density 0 Measures w. conductivity lStiable / Slug away 0: (1002 ,: Figure 2 Main page showing Menu (1), Information area (2), Graphics area (3) and status bar (4) TD -010 – Installation and User Manual – MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 22 of 41 Project Confidential • • MPM i. ° R4: t,rolcr 5.2.3 Menu The Menu (Figure 3) gives access to the following items: Login Login in as another user, (change user level) Select Meter Select other Meter to display data from (if more than one meter is installed) at the MPM Terminal Configuration Report Prints the configurations of the MPM terminal View event log View details about events on the meter (See also Section 5.4) MPM GUI v2.0.0.1902 <Local meter' (11100) Logan and corhiguration Meter Service Diagnostic Figure 3 MPM Terminal Menu TD 0 — Installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 23 of 41 Project Confidential • • mpm 5.2.4 The Information area The Information area displays current values for Update trends and vases — — - flow rates, measured fractions and other I Update measurements. — — - - -- FIow rates (Actual conditions) A check box on the top makes it possible to oa 32.8 m'!h stop the updating of values. This is useful if the Gas MEM m'!h operator wants to stop the update and evaluate the data. Water 3.4 rem _ 1 —Measured fractions The flow rates are presented in the selected 9 . units. WLR { WVF 0.0 Measured fractions display the fractions GVF 87 z calculated by the MPM Meter. GOR 0.0 OM The area called "Other" show some of the ; - Other — — transmitter readings, calculated velocity, ! Temperature J NAI'C measured Water Conductivity (converted to p rime 16.3 Barg 25 °C) and measured Water Salinity. ; ply 0.0 kgJrr The status light is green if no alarms are active 204.9 mBar on the meter. If an alarm situation occurs, the I Velocity 0.0 m!s light switches to red. swi 0,0 y, { Click on the light to view Alarm status. From the Water conductivity ms /cm Alarm status it is possible to click 'View event log" to see the details (See also section 5.3). Water salinity 0.8 i Scale Index MAI% The meter connection state light is green when the meter is online. If the meter is offline or r Status having communication error (no contact with the Q Status: OK meter), the light switches to red. j @ 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 • • 5.2.5 Graphics area Trends ar =r; Graph averages Oil, gas end water flow ) :cer(m =.'rf - t ^I'm _42c Oil I 32.OIrrr' /h % "" VPPN llt,r x.1 1.1 f dl ftJ�'Yt.J INI " RA . lr'�tiNu" PYy Water I 3.5Im =/h 2!- Gas I 258.1Im'/h -2X -•s: 2 ;X Salirity and Conductivity _ C s r � ° ��,_ Graph averages a Sat I 0.81% 4 1. 1 14 1 if i i4i f ‘5 . ANi i V A ri 1 N y i ;''�� L�•+kt s Cord. I 2.731 /cm 2 ZT - x = ffl- WLP. : Graph averages WLR and IF — 3h t';j WLA I ask GVF 87.9k % InPin 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 a ut1r� -h eMetccs 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. Qoi cantinas 0 MPH No* - - -- Me w. den 0 Measured w:cmduc dy :stable *3 --- - - - _ - - - - Slug,Qualito - - - - - - f tc%Nt 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 • • MPH" I.W upreLmet, °= 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 Tight 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 / ddPi'r i of Q dPDutlet Pressure Temperature Q 3D Broadband Software External Communication (� 0 OK ,j Failed o Unavailable I View event log I Close Figure 7 Alarm status II TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 27 of 41 Project Confidential S • 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. Q Seventy Process _- Evert id 0 Into 0 DSP Interface 0 Mew Camica6m service FA data iput (Iran:niter data Of tiroadoad dotal has fated (16399) A, iA loge pap in raw4ata =cued. No 8tagrabtim done (764001 0 Warrig 0 External Communication 0 Process Supervisor !A strange data value has occured (16401) -. 'Accumulated pahse ref dwnnel (20492) 0 Error 0 Flow Calculations 0 Transmitter Interface l Cdpiation issue (1 6388( ❑ Lop !Could not find process (4100) {Could not open file with ca8xatern constants f16396) v Date Seventy Souse Process Event Id Evert DssaMien -- - -- It %12.20%1703 Wamig Flow Calculations 16388 Calculation issue .. 08.122006 1258 Waring Flow Calculations 16368 Calculation issue 081 2 2006 1253 , Wan Flow Calculations 16388 Calculation issue 0812.2006 1250 • Trio DSP Interface 20491 DSP/Elecaoras rieynsis value 0E122006 1250 Iris DSP Interface 29492 Accumulated pahse ref charnel 08.12.2006 1250 Serial port DSP Interface 204% DSP Se port diagnosis value_ 0812.20061248 Wang Flow Calculations 183% Caktiation issue 06.1220061243 ' Wang Flow Calculations 16388 CakJatioe issue 08.122 6 123 Wasp Flow Cakuiatnns 16388 Calculation issue 08.122W61235 9INo DSP Interface 20492 Accuuatedpahse ref channel 08.1220% 1235 J ?)Irio DSP Interface 20491 DSP/Ekcuoms 6agnosis value: 08.122W61235 i Irk DSP Interface 204% DSP Serial port diagnosis values 1 08 2 2006 1233 ! Wan Flow Calculations 16388 Calculation issue 98.1 2 2006 1229 Warig Flow Calculations 16388 Calculation issue 09122006 1223 r Waning Pb., Ca1 16388 r..r +4 issue 08.12.2006 lam ) Irio DSP Interface 20490 DSP Serial port depose values 08.1220% 1229 1 DSP Interface 20491 DSP/Electronics diagnosis values 00.122061220 J) Irfo DSP Interface 20492 Accuulatedpahse ref charnel 08.123061218 Wang Flow Calc,iatmns 16388 Calculation issue 08.1220001213 Waring Flow Calculations 16388 Calculation issue C6.12.2006 1208 I tlWaming Floe Calculations 163% Calculation issue 08.122006 12 5 'J)Irie DSP Interface 20452 Accumulated pahse rel char el l First page 11 Previous page I Neat Page 11 Last page I Page 1/1200 ( Figure 8 Event log Event properties Io® E vent Id 20490 Severity: Info ( + Date: 08.12.200612:50:56 Process: DSP Interface + Meter Local Meter Description: 1l/SP Serial ..rt di nosis value. �. 4 I Additional data f Byte: Nee) ( Tad r UTXUOK. 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 • • 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 expert data ..,. _...... dad , A 4 t• Meter: I Internal test meter J Start 106.11.200714:1201 7 j Erk 15 minutes _j Li Lop i tervat I, 0.5 second I View II Escort I Close Trend Avaia a variables. Local meter tPlelet dlriett sPlnlet2 dPQullet — noes An..ryala9etn — onae- morasik eatin4t4 — txaaurAccrivowae [ref ti 80utIMi a - dPQutlet2 Emulsion index FCStatus GamnaCount n• «JPN'LNr. " 1'' ,',rkMN 1rV OVVent''\'"144 1P. L^_ J,+ '1 ./ 1 VOV Gas density Gas velocdy GOR Mass GOR Standard Mass GOR Standard Volume 1 GOP. VoMu GVF Actual Vane Liquid veto* MeteStatus Mu density 08 den* Pressure Pressure: Pressure2 QFamWater Aclud Mass QFamWater Adud Volume QFamWater Standard Mass QFamWater Standard Volume CIGas Actual Mass QGas Actual Voume QGas Standard Moon I sit- Volume QOi Actual Ma. Q0i Actual Voume Q08 Standard Mats Q08 Standard Volume Quditydndex a QWder Actual Mass Ee1,2fM aerdon OVUM O1sr, .:.116 uvunX 1.918E vM�Y 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 ka,niPhasetueuas Dialogue toolbar t* r Figure 11 Toolbar Button The toolbar button (Figure 11) functions are as follows; 1. Page setup 2. Print the graph 3. Print preview 4. Copy the graph 5. Previous 6. Next 5.6 Meter Configuration These dialogues are available for user with Supervisor privileges. In order to log on as Supervisor, select Login dialogue from the "Login and configuration" menu. 5.6.1 Select active process data set With this menu option the user may select a process data set for the current MPM meter. There are 10 process data sets available for each MPM meter; each set can be configured individually. The next section explains the various data input fields available in a process data set. 5.6.2 Create New Look -Up tables (PVT gas and oil properties) In order to create a new look up tables in the process data set, density gas, density oil, viscosity gas, viscosity oil, surface tension and Gas - oil- ratio(GOR at actual conditions) as function of temperature and pressure is needed. When these parameters are available, open the Process Data Configuration page and choose which process data set you want to enter data into. Open the PVT, oil and gas properties page and type your obtained parameters into the tables as function of temperature and pressure. Then close the window and press `send to meter' to upload the tables to the meter. 5.6.3 Process data configuration TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia. Entrada Page 30 of 41 Project Confidential • • mpm vult.ha f,tetcs; 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 i ,_ 411 11 A.____ rocess data set - - --- -- -- — - -- - - -- - -- -- ' - - - -- - - { , - - --- -- l Water density -- Fired -- --- - Measured - -- - - --- _ Irfermation — — _ Name 'Average Cep fa al wells on Cfwlet 1 ; j Water cordudnty O Farad 0 Measured `- -, . - - . - . - . Description { mss' O O ,. .Water --- - t Density 104M kora3 at temperature 151 deg C I 1 . Conductivity ill ms /cm *temperature 251 deg C Measurement mode O We Sas O Mukphase Q Automatic MPM GVF 9GOI ( ' _ WGM GVF I 97.01 I =I , . . H .,.,. : ., ® Use Broad Band deraly Standard conditions hfe*su GVF for Broad Band measurement I 99.51 , Density d I 855.0071 kg/m' 1 151 deg. C Mari tsn ONF for Gamma meaamrent I 99.01 Der* gat ( 0.90714/0 at 1 OI bug ❑ Use Movinp Avuage Box an output data . ❑ Use find GDR Fared GOR 1 I d Use Lookup table ❑ Disable 88 Fined WLR I 1 ' ' ❑ Add flashed gas from d ' . ❑ Enable Live PVT input - Dielectsic ant ' - - - - -_ - -- -- - -- - - : Dielectric constant offset ... _ - - - - Gas - - . _ ._ _ . _ . - - - -_. - - Water /gas surface tension - - -- - -- 01 I 1 ❑ Override 1 1 deg. C ' . Of 1 OI Gas Isentrapic Exponent 1 1 : ! ® Cale m surface tension from water sefriv ; at Surface tension water I . - - 1 N, ' Gas I 1 .I ❑ Overtide I :I berg Gas I OI Use Dry Ai Density ❑ ... Sak wabrfactors _ - , , Vscaslyatactualconditiws - - - --- . Water viscosity factors - - - -- - Water saintly filer limas -- - -- -- -- - Massabsorptioncoeffxtient - - - - B0 I ?. 1 ' Oa I0.006149IPas D0 I 07181 Min vakue 1 0.51% Oi I 'I ❑ Ovemde 81 I ,,-. _"I ; ' Gas 1 1.59E-05IPaa 01 I 0.003591 Mar value 1 dlk ' . Water I - .I ❑ Override B2 I '1 1 Water 1 >;,:, >IPal ❑ Use D I °I : : Gas 1 151 2 0vemde . Ie Figure 12 Process data configuration In the following is provided information about the different options and input data: Function Description 1 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 TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 31 of 41 Project Confidential • • mpm Function Description "MPM GVF", multiphase mode is selected. WGM GVF should always be larger than MPM GVF. In the section between MPM GVF and WGM GVF, the last setting is used. For low pressure applications (e.g. below 10 -15 berg), recommended switching area would typical be around 90% GVF. For higher pressure applications, it may be desirable to use a higher GVF setting, typical around 95% GVF. For ultra high GVFs, an additional BB based GVF measurement may be used. This measurement is particularly accurate for ultra high GVFs. The GVF range for the BroadBand GVF measurement can be configured by the parameters Minimum GVF for BroadBand GVF and Maximum GVF for Gamma measurement. Recommended values are 99.5% for Minimum GVF for 3D- BroadBand GVF and 99.0% for Maximum GVF for Gamma measurement Note: The Broadband GVF measurement is not available in multiphase mode. A moving average filter of 20 seconds can also be added to the output data in order to provide some damping on the output data. The meter can also be configured to be forced to use a fixed GOR. This function can be used to provide measurements from the meter if the gamma detector fails. However, the uncertainty of the measurement will be significant higher. The broadband electronics can also be disabled in this section. If the broadband unit is disabled, a fixed WLR value can be downloaded to the meter which will be used together with the remaining transmitter measurement providing simplified calculations of the flow rates. The measurement uncertainty for disabled broadband electronics is significantly higher particularly for slugging flow conditions. NOTE : If the meter is configured to measure the water salinity in wet gas flow conditions, this function will only be enabled if wet gas mode is selected. I.e., the meter will not measure the water salinity in wet gas flow conditions if mode selection is set to AUTOMATIC. Dielectric Constant This section allows the user to entering a fixed value for the dielectric constant of oil and gas which over rides the dielectric models in the MPM Meter Dielectric Constant Offset This section allows for correcting the dielectric constant models with a constant offset and can be used for fine- tuning or correction for error in the PVT input data. Salt Water Factors These parameters allows for use of different salt water models for calculating the temperature dependency of the water density. The default values correspond to NaCI salt. TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 32 of 41 Project Confidential • • mpm tg,a.'rt,�et 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 took -up tables) The water value can be used to over ride the viscosity calculation performed based on the salinity for the water Water Viscosity Factors These are salt composition related factors which are used to configure the models for calculation the water viscosity based on the water salinity. Water Calibration The water density and conductivity can either be entered into the meter manually (fixed option) or measured by the meter (measured option). The fixed values are entered at a given temperature (and 0 barg) which usually are 25 °C for the conductivity and 20 °C for the water density. The MPM meter performs temperature and pressure corrections for the density to the actual T and P conditions. If the measured conductivity and density is used, it is still recommended that the meter is configured with a typical fixed values for conductivity and density since this is used as fail -back values when the salinity measurement is out of range (the water salinity measurement is only available in water continuous flow) Standard Conditions The standard conditions calculations are configured by entering the oil and gas density at standard conditions. These parameters are typical calculated from the composition of the well. The temperature and pressure conditions for standard conditions are also defined here. In this section flashed gas there is also an option to add flashed gas from the oil. The oil at standard conditions will then be reduced accordingly such that the total hydrocarbon mass flow rate is conserved. When this option is enabled, it is possible to enter a temperature and pressure look -up table for the mass transfer factor from oil to gas. Gas This section allows specifying if some additional properties for the gas such as the Gas 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 TO -010 — Installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 33 of 41 Project Confidential • • mpm Llutt .s..r Function Description for the wells. For water injection wells, the upper value may be the salinity of the formation water whereas the lower salinity limit may be the value of the injection water (e.g. seawater). Water / Gas surface The water / gas surface tension is calculated by the meter based on the tension salinity and measured temperature when the "Calc surface tension from water salinity" option is enabled. A fixed value can also be entered. Mass absorption The mass absorption coefficients for oil water and gas at 660 keV can coefficient either be calculated by the meter or entered manually if the over ride function is used. The meter calculates the absorption coefficient from the oil and gas density and water salinity assuming NaCI salt. The mass absorption coefficient for oil, gas and water can be calculated form the composition using the XCOM database at NIST (National Institute of Standards and Technology) (http://physics.nist.cpv/PhysRefData/Xcom/html/xcoml.html) 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 • . mpm 5.7 Dialog toolbar ESe Send to meter I) 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 1 1 mpm 5.8 PVT, Oil and Gas properties dialogue i}il and gas Properties l ^J NT spot type Q table _ r fr-lmscosty GOR (Actual con. ;.ons)! Surface tensionoildgas I Oil ; gas mass transferfactorI Density ea I Temperature [deg. CI 60 701 801 90' 100 2501 5441 620 620 620: 620 260 620 5E6.E 584; SECS Sr:T .6 Pressure [Bargl 270 620 5E3.6 I 58.19 577.9 • 574.5 2101 520; 577.8 580 4 : , 574.E 571.5 2 9 0 6201 577.21 574.6 571.6 , 568.4 Density gas Pelnal Temperature [deg. CI 1 301 351 40' 45 50 19D1 145 `. 140.9; 136.91 133.3 129.E Pressure 155 148 14 4.2 140.2 ` 136.5 133 [avid 2001 151.8 14' 51 143.2 139.6 136 2051 155.1 ' 150.7 146.61 142.7 139.1 2101 158.? 153.9 j 149.7 145.8 142.1 I OK II Cancel 1 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 • S MPM m.,tiFteserictirs Oil and gas properties L : - X PVT inPUt type table it Den* I %coo* I GOR (Actual concitionsji Surface tension oil/gas 01-> as mass transfer factor I 01 - gas mass transfer factor Temperature [deg. CJ 1 40 , 6131 80, 100 I 110 zo i 0.02 ; 0.021 I 0.022 '1 0.023 I , 0.024 251 0.02 . 0.0211 I 0.023 0.023 i f 0.024 Pressure , 30i 0.022 i 0023 0.024 . 0.1 acas 326 , 35 tan] 0.0213 'I - 0,03 ! 0.032 i 0.035 0.037 i 40 i 0.03 0.0311 0.034 l 0.037 ' 1 0.04 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 -- - 4 ii Operations Centre a 411P- I ' 7 Internet Example: / FIELD B - Africa Example: FIELD A - North Sea MPUT 1 er17thI•1 TD -010 — Installation and User Manual — MPM Topside Meter.Rev01 Project Name: Magnolia, Entrada Page 38 of 41 Project Confidential 1 11110 111 mpm 6.2 Verification / recalibration of Venturi Cd Verification of the venturi Cd is recommended being done only if sand is being produced (erosion of pipe internals). To be able to verify the Venturi Cd, the Meter must be compared to a well proven reference, preferable with single phase flow. 6.3 PVT maintenance It is recommended that the to verify the PVT data used to configure the MPM Meter on an annual basis. Some applications may require more frequent verification and some Tess depending on the stability of the total hydrocarbon composition from the wells. A well composition verification can be done by verifying the measured GOR from the MPM Meter with the flashed GOR using a PVT Simulator based on the total hydrocarbon composition for the well. If a deviation is observed, a re- calculation of the total composition for the well may be required. Measurements from the MPM Meter or the MPM Meter simulator, together with a PVT simulator can be used for this purpose. Please contact MPM for further details. The MPM Meter may also be used to measure single phase properties during shut down periods; however this may depend on the particular installation and flow conditions. If the Meter is filled with pure oil or gas during a shut down, measurements can be taken to verify the quality of PVT input (please contact MPM for further details). 6.4 Communication Tests There are two types of communications tests; one is to check how the internal communication runs the other is how the communication runs between MPM meter and the terminal. These tests are run from the MPM GUI and can be found under flag `Diagnostic' choosing subflag `Hardware'. The window in figure 15 below will appear. Meter =:Ern Maamoura 111 (4;4027) teratausication with meta Lest reset tax 01.0420011 Erras: 0 Taal 395 1 Reset error canter 1 Tines ter { Errors { Toted _ dPlnlet1 0 1592 dPlydet2 NA NA dP0u1 NA NA sPputtet2 NA NA Gametal 0 1241 Casna2 NA NA Prenatal 0 1591 Presaae2 NA NA Terrpeaturel 0 1591 Temperature2 NA NA 1 Read fl Reset 1 ICI 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 4111P • m,m tAlth bete The errors in communication between the MPM meter and the MPM terminal can be read from the upper left corner. 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 Tower 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 • mM vmpha, ;ttoet s 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 ~5 Qannik Pool Rules ~ ~ Page 1 of 1 Colombie, Jody J (DOA) From: .Foerster, Catherine P (DOA) Sent: Wednesday, June 25, 2008 3:40 PM To: Colombie, Jody J (DOA) Cc: Seamount, Dan T (DOA) Subject: FW: Qannik Pool Rules Fyi and the record From: Foerster, Catherine P (DOA) Sent: Wednesday, June 25, 2008 3:39 PM To: 'Frazer, Lamont C' Cc: Norman, John K (DOA) Subject: RE: Qannik Pool Rules Mr. Frazer, I have discussed your request with John Norman, another of the commissioners here at the AOGCC. He and I concur that granting your request will not result in waste of hydrocarbons, damage to fresh ground waters, infringement on others' correlative rights, or unacceptable oil field practices. Therefore your request is granted. Cathy Foerster From: Frazer, Lamont C [mailto:Lamont.C.Frazer@conocophillips.com] Sent: Wednesday, June 25, 2008 3:22 PM To: Foerster, Catherine P (DOA) Subject: Qannik Pool Rules Dear Commissioner Foerster: The purpose of this email is to seek permission to produce Qannik well CD2-464 on a temporary basis as per the proposed pool rules outlined in ConocoPhillips' April 3, 2008 conservation order application. The proposed pool rules would be in effect until the Alaska Oil and Gas Conservation Commission issues final pool rules for the Qannik Pool. If permission is granted, initial CD2-464 cleanup operations would be scheduled to commence on June 30, 2008. Please contact me if you have any questions. Sincerely, Lamont Frazer Qannik Coordinator ConocoPhillips Alaska, Inc. 6/26/2008 ~ 4 • -- - - _ ~ ,~ ,~s _ , ' - _. _~ _~ ~_ ~., ~~ ~ ~, 1 ~1 ~ v, L~7~ OIL CO1~T5ERQATIOI~T CO1rIbII55IOK May 15, 2008 Lamont Frazer Qannik Coordinator ConocoPhillips Alaska Inc. PO Box 100360 Anchorage, Alaska 99510 Dear Mr. Frazer: SARAH PALIN, GOVERNOR 333 W 7th AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 At the hearing today it was determined that the confidential materials submitted at the hearing as well as the confidential portion of the pool rules application submitted on April 3, 2008 were not required to complete the rules for the Qannik Oil Pool. All of these confidential materials were hand delivered to you by Jody Colombie and me after the hearing. Please contact me if you have any questions. Sincerely, Steve Davies Senior Petroleum Geologist cc: Mr. Kim Bowen, Anadarko Dora Soria, CPA ~3 1 ALASKA OIL AND GAS CONSERVATION COMMISSION 2 Before Commissioners: Daniel T. Seamount, Chairman Cathy Foerster 3 John K. Norman 4 In the Matter of the Proposed ) 5 Establishment of Pool Rules and ) Area Injection Order for Qannik ) 6 Oil Pool by ConocoPhi llips ) 7 ALASKA OIL and GAS CONSERVATION COMMISSION 8 Anchorage, Alaska 9 May 15, 2008 ~ 9:02 o'clock a.m. 10 VOLUME I 11 PUBLIC HEARING 12 BEFORE: Danie l T. Seamount, Chairman Cathy Foerster, Commissioner 13 John K. Norman, Commissioner 14 15 16 17 18 19 20 21 22 23 24 25 R & R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 ' • • 1 TABLE OF CONTENTS 2 Opening remarks by Chairman Seamount Testimony by Lamont Frazer 3 Testimony by Dora Soria . Testimony by Doug Knock . 4 Testimony by Brian Noel . Testimony by Jack Walker 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 R& R C O U R T R E P O R T E R S j 811 G STREET I I (907)277-0572/fax 274-8982 ANCHORAGE, ALASKA 99501 03 05 09 31 65 • . 1 2' 3i 41 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 2 2 '! 23 24 25 P R O C E E D I N G S (On record - 9:02 a.m.) CHAIRMAN SEAMOUNT: On the record. I'd like to call this hearing to order. The date is May 15th, 2008, the clock on the wall says 9:02 a.m. We're located at 333 West Seventh Avenue, Suite 100, Anchorage, Alaska. Those are the offices of the Alaska Oil & Gas Conservation Commission. To my right is Commissioner John Norman, to my left is Commissioner Cathy Foerster and I'm Dan Seamount. If anyone has special needs please see Special Staff Assistant Jody Colombie who's sitting in the back. R & R Court Reporters will be recording these proceedings. You can get a copy of the transcript from R & R Court Reporters. And we'd like to remind anybody testifying that we have two microphones in front of you, you need to speak into both of them. One's for the hearing room and the other's for the recorder. The purpose of this meeting is to hear a request by ConocoPhillips Alaska, Incorporated to classify the Qannik Reservoir in the Colville River Field as an oil pool and to prescribe rules to govern development of the proposed oil pool in accordance with 20 AAC 25.520. Concurrent with the application the operator is requesting an area injection order to authorize water flood operations in the same proposed pool. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 3 • • 1 2 3 4, 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 This hearing is held in accordance with 20 AAC 540 of the Alaska Administrative Code. So I see that we've got three -- no, four people wanting to testify today and it looks like they're all with the operator, ConocoPhillips. And I don't see that any other parties are going to testify at this time. We'11 give opportunity at the end just in case somebody changes -- if somebody else changes their mind. So I guess it's appropriate we start off with the applicant. Let's see, from -- are you giving sworn testimony? MR. FRAZER: Yes, I am. CHAIRMAN SEAMOUNT: Okay. Raise your right hand, please. (Oath administered) MR. FRAZER: Yes, I do. CHAIRMAN SEAMOUNT: And could you, please, state your name? MR. FRAZER: My name is Lamont Frazer. CHAIRMAN SEAMOUNT: Okay. And who do you represent? MR. FRAZER: I represent ConocoPhillips. CHAIRMAN SEAMOUNT: And do you wish to be an expert witness? MR. FRAZER: Yes. CHAIRMAN SEAMOUNT: Okay. Please state what the subject is and what your experience is? MR. FRAZER: The subject would be reservoir engineering. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 4 • • 1 2 3 4i 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 ~ 21 22 23 24 25 , I have a bachelor's degree from the University of Michigan. in chemical engineering, a master's degree from the University of Alaska at Anchorage in environmental quality engineering. I have six years of lower 48 experience and 20 years of Alaska experience working fields within the Prudhoe Bay Unit, the Kuparuk River Field and the Colville River Unit. CHAIRMAN SEAMOUNT: Commissioner Foerster, do you have any questions or objections? COMMISSIONER FOERSTER: No, I don't. CHAIRMAN SEAMOUNT: Commissioner Norman? COMMISSIONER NORMAN: No. CHAIRMAN SEAMOUNT: Do we have to make a motion to accept him as an expert witness? COMMISSIONER NORMAN: The Chair can just say. CHAIRMAN SEAMOUNT: Okay. You are accepted as an expert witness, Mr. Frazer, please proceed. MR. FRAZER: Thank you. TESTIMONY BY LAMONT FRAZER MR. FRAZER: What we're going to do today is talk about the -- I'll provide testimony for the Qannik Conservation Order. Just an outline of what we're going to talk about, I'll provide an introduction, ownership and development area will be covered by Dora Soria, Doug Knock will cover geoscience, then I'll provide testimony on reservoir and production issues, I'll also talk about the surface facilities and Brian Noel will talk R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 5 • • 1 2 3~~ 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 I about drilling completions. The intent of our testimony is to provide information that will form the basis for a conservation order with the goals of preventing waste, promoting conservation, protecting correlative rights, promoting maximum ultimate recovery and when possible, when it makes sense, to maintain consistency with other Colville River Unit pools. Just to provide an introduction, this is a slide that shows the relative location of Alpine relative to the other North Slope fields. We have Prudhoe, Kuparuk and Alpine. The Colville River Unit is shown here. We're going to show in more detail the actual mapping associated with Qannik, but basically it's an accumulation that overlies the Alpine Field. Primarily it's CD2, in some it's CD4. The expansion that we have proposed is a seven and a half acre expansion, a gravel expansion at CD2. Whenever possible we're going to use existing infrastructure. The development plan is a phased development. Our initial development is a nine well horizontal development covering about 5,000 acres. We plan or would like to implement a waterflood. The oil in place in the initial development area, we'll talk more about this later, is 79 million barrels with projected ultimate recovery of 17 million barrels. That's about a 22 percent recovery factor. If we're successful we've identified up to nine additional locations we'd like to proceed R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 0 • • 1 2 3 4 5 6 7 8 9 10 11 ~ 12 13 14 15 16 17 18 19 20 21 22 23 24 25 with in the next two years. We'll provide testimony as to where those locations are. And our working interest is 78 percent with Anadarko having 22 percent, that's the same as the Alpine Field. COMMISSIONER FOERSTER: If you're successful, what is the upside in additional reserves with those up to nine upside wells? MR. FRAZER: I have a slide that directly..... COMMISSIONER FOERSTER: Okay. MR. FRAZER: .....covers the information there. Just to provide an introduction as to where we are with regard to the project, we drilled our initial appraisal well, the CD2-404 in June of '06. We obtained all our permits by March of '07. we filed a PA application May of this year. We're currently undergoing facility construction, we started in February, we'll have all the insulation, all the work done by August. We plan to start development drilling in June and right now as of yesterday our plans were start production in July. Or our goal is and I think it's a realistic goal. COMMISSIONER FOERSTER: As of yesterday, are they different today? MR. FRAZER: No, but I haven't checked. With that I'll turn over the -- to Dora to talk about ownership. CHAIRMAN SEAMOUNT: Are you giving sworn testimony? MS. SORTA: Yes, I am, Commissioner -- Mr. Chair. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 7 ~ • 1 2 3 4 5 6i 71 8 9 10 11 12 13 14 15 16 17 18 I 19 20 21 22 23 24 25 CHAIRMAN SEAMOUNT: Please raise your right hand. (Oath administered) MS. SORIA: I do. CHAIRMAN SEAMOUNT: Please state your name? MS. SORIA: My name is Dora Soria, I'm a staff landman with ConocoPhillips. I -- my background is I have been a landman since 1990, I started my career with ARCO in Lafayette, Louisiana and worked in Houston and subsequently in Alaska. I have 10 years of experience in Alaska. I have worked the Cook Inlet, the North Slope and more recently I'm particularly focused on the Colville River Unit area and also in NPRA. I went to the University of Texas at Dallas, I have an undergraduate degree in -- a BA. I went to the University of Texas at Austin for law school and I graduated in 1990. COMMISSIONER FOERSTER: I'd like to have her entered as an extra special witness because of her education. MS. SORIA: Let that be on the record that I am a Texas longhorn and quite proud of it. COMMISSIONER NORMAN: Nothina -- no objection, Ms. Soria is well known to the Commission. CHAIRMAN SEAMOUNT: I think chaired is in this building, you consider you an expert witness. MS. SORIA: Thank you. I a~ TESTIMONY BY R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 I welcome you. the first hearing I ever were testifying. we do ~preciate that. DORA SORIA 8 • • 1 2 3 4 5 6 7 8' 9 10 I 11 12 13 14 15 16 17 18 19 20 21' 22 23 24 25 MS. SORTA: Well, good morning, Commissioners, and good morning Chair. The little piece that I have is relative to ownership and development in the area. This is just to orient you a little bit with regard to the area out here. Everything that you see in yellow is ConocoPhillips land within that outlined box. Further orientation here is -- it's kind of hard to see, but there is a stippled outline there that corresponds with the Colville River Unit outline as well. In this box that you see right in here, and it will be more specifically addressed on the next page, but it's 78/22 ConocoPhillips land. This is the outline that encompasses both the pool rule area and the area injection order. You will also see within here the proposed participating area that we are -- will be asking the State and ASRC, they are joint mineral owners here so we will be applying for that participating area. That is based on using a circle and tangent method regarding the proposed wells in the area and so that will be how that is configured and accepted. In addition to that you are seeing a purple outline in here and that purports to represent -- the outline that you saw earlier is just an ellipse or an elliptical portion that will be the reservoir area that we purport to encompass in this area. And that will be more specifically addressed by others that have more expertise in that area. Here you see again the Colville River Unit area, that is R& R G OUR T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 9 • • 1 2 3 4 5' 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 I more specifically shown right in here. This is just kind of the exhibit that we will attach to our application to the State and ASRC for the creation of the PA. And that was just to show you that the leases, you know, are within the Colville River Unit, that ConocoPhillips is the unit and will be the participating area operator. The participating area encompasses about 18,000 acres and you see where they are located and defined. In addition to that we are talking about 70,000 areas that are in the pool outline that I've not reflected on here. Again participating ownership is the working interest owners are 78 and 22 in the PA and all the tracts adjacent to the PA are 78/22, and in addition to that all the pool area and injection order area is ConocoPhillips 78 and 22. And there other ownerships at deeper horizons, but they are at 10,000 and greater and then some of them are 8,000 and greater, but they are not affecting our current request from you. That's all I have. Are there any questions? CHAIRMAN SEAMOUNT: Thank you, Ms. Soria. Commissioner Foerster? COMMISSIONER FOERSTER: None. CHAIRMAN SEAMOUNT: None? COMMISSIONER FOERSTER: None. CHAIRMAN SEAMOUNT: Commissioner Norman? COMMISSIONER NORMAN: Just one question and I think it's R& R C O U R T R E P O R T E R S 811 G STREET <907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 10 1 2 3 4 5 6 7 8 9i 10 11 12 13 14 15 16 17 18 19 20 21 22 23 i 24 2 5 ~I • • evident from the map, but I wanted to make sure. Well, first of all when do you plan to apply for the PA? MS. SORIA: June 15th. COMMISSIONER NORMAN: June 15th. And the area that you will be making application for includes the entire reservoir here? MS. SORIA: The way that it is styled with the DNR and ASRC is we can only apply for a PA that purports to encompass our. two year program from (indiscernible), so that is what that outline represents. So obviously the purple outline that you saw in that exhibit is a bigger outline, that is the reservoir outline. But we can only include in the participating area again. what we can drill in the next two following years. And then we will provide for revisions as we increase our program. COMMISSIONER NORMAN: So your plan would be then as you delineate to expand? MS. SORIA: That is correct. CHAIRMAN SEAMOUNT: Okay. MS. SORIA: Thank you. CHAIRMAN SEAMOUNT: Thank you, Ms. Soria. MR. FRAZER: The next individual to testify will be Doug Knock. CHAIRMAN SEAMOUNT: Are you giving sworn testimony? MR. KNOCK: I am, yes. CHAIRMAN SEAMOLTNT: Please raise your right hand. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 11 • • 1 2 3 4~ 5 6 7 8 9 10 11 12 13 14 15 16 17 I 18 ~, 19 ~~, 2 0 I'', 21 i 22 ~ 23 ~ 24 25 (Oath administered) MR. KNOCK: I do. CHAIRMAN SEAMOUNT: Okay. Please state your name, who you represent, whether you want to be an expert witness and what your qualifications are? MR. KNOCK: I would like to be an expert witness. My name is Doug Knock, I'm a geologist with ConocoPhillips. I have 20 years of industry experience. I have a bachelor's degree in geoscience from the University of Idaho, I have a master's degree in geoscience from the University of Alaska at Fairbanks. And I've worked for ARCO, Phillips and ConocoPhillips over that 20 year period on all the North Slope fields just about. CHAIRMAN SEAMOUNT: Commissioner Foerster? COMMISSIONER FOERSTER: I have no objection. CHAIRMAN SEAMOUNT: Commissioner Norman? COMMISSIONER NORMAN: No objection. CHAIRMAN SEAMOUNT: Yeah, I worked with Mr. Knock's father in Caster, Wyoming for a number years. It's a geological family. Okay. Please proceed, Mr. Knock. TESTIMONY BY DOUG KNOCK MR. KNOCK: The first slide the pool name and unit and pool reservoir. The unit is the Colville River Unit in the blue background. The pool name here is the -- going to be the Qannik Oil Pool and the reservoir is the Qannik Reservoir. R& R C O U R T R E P O R TER S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 12 • • 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Also on the slide are pads CDl, 2, 3 and 4, with the Qannik development most at CD2. Qannik Oil Pool definition. From the CD2-11 type log. I'm going to go ahead and read the definition here. The Qannik Oil Pool is defined as the accumulation of oil and gas common to and correlating to the stratigraphic interval between 6086 and 7249 feet measured depth in the CD2-11 well and its lateral equivalents. So we have the CD2-11 logs on the left display, measured depth, and you can see the top of the Qannik which is also informally known as the K-2 at 6086 and then on down to the bottom of the Qannik which we're calling K-2 Basal. And that is the Qannik Oil Pool. Also on the slide is a TVD representation of the logs to the right. So you've got to the left I believe the well went through Qannik at 59 degrees. So there's a lot of major depth footage on the measured depth display there. North Slope stratigraphy. Qannik is broadly equivalent to the Nanushuk Group, late cretaceous in age. It's the youngest of the six reservoirs in the greater Alpine area, it's also the newest discovery of the -- of those six reservoirs in the greater Alpine area. CHAIRMAN SEAMOUNT: And that was page 12. I forgot to aslt you all to -- when you're referring to the slides that -- refer to the slide number so that the reporter can get it accurate -- as accurately as possible. R& R C D U R 7 R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 13 • • 1 2 3 4 5 6 7 8 9'' 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. KNOCK: Okay. CHAIRMAN SEAMOUNT: Thank you. MR. KNOCK: Slide 13, a brief geologic overview, a structure map for top Qannik on the left showing the nine -- or eight proposed development wells with the one existing horizontal well drilled in blue in the center. (Indiscernible) environment is a shallow marine sandstone. The sand body is north-south elongate, the approximate depth is 4,000 feet subsea TVD. The trap is a combined structural and stratigraphic trap with onlap, a pinch out to the west, and a shale out to the east. CHAIRMAN SEAMOUNT: Are those -- what are the red dots? MR. KNOCK: Those are the 100 plus well penetrations we have going through this 4,000 foot interval on down to Alpine and other reservoirs. CHAIRMAN SEAMOUNT: They're the tag points then? MR. KNOCK: Those are the tag points for the top of the Qannik structure. So a lot of well control in the CD2 and the CD1 pads which are shown to the left and the right there. CHAIRMAN SEAMOUNT: And I assume all those areas without the tag points are based on seismic? MR. KNOCK: They are. So you -- the structure is highly controlled by all those penetrations around the pads and then you lose some structural control the north and the south. And highlighted on there is the 4,000 foot structural contour and R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 14 • • 1 2 3 4 5 6 7 8~ 9 to l 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 that is the approximate GOC. CHAIRMAN SEAMOUNT: It looks like your main part of the reservoir is this syncline, is that correct? MR. KNOCK: It's pretty much a very low relief, very low relief structure. I think those are -- what are those, 54 -- contour interval looks like 40 feet on here -- 20 feet, sorry, 20 feet contour interval management. I'm not very good at reading those contours, but I believe those are 20 foot contours so very low structural relief. Lithology is a very fine grained lithic rich sandstone, approximately equal parts of quartz grains and lithic grains, a lot of sedimentary rock fragments. Net pay is up to 22 feet, average 10 to 15 feet. Porosity 20 to 25 percent and permeability up to 50 millidarcies. COMMISSIONER FOERSTER: So is the Qannik something that you discovered as you were drilling deeper? MR. KNOCK: We drilled through it for, you know, a long period of time with the Alpine development. It was always deemed to be thin and not real impressive on the logs. There was always a question from a couple of rotary sidewall cores we got when we drilled the Alpine 1 well, they appeared to be pretty tight. I think we had MDT data way back then that also suggested low mobility. So we didn't really think it was developable being that it was deemed to be pretty tight and thin. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 15 ~ • 1 2 3 4 5 6 7 8 9 10 ~ 11 12 13 14 15 16 17 18 19 20 21 22 ~ 23 24 , 25 COMMISSIONER FOERSTER: So what changed your mind? MR. KNOCK: We got -- we finally got funding for a core and once we got a look at it with the core and we saw that it was fully oil saturated, there's always a question also on whether it was gas or oil. And getting that core convinced us that it was an oil reservoir as well and it had some reasonable reservoir properties. COMMISSIONER FOERSTER: Thank you. MR. KNOCK: Next slide, slide number 14 data and exploration history. Up to a -- or more than 120 well penetrations in the CDl and CD2 pad area with gamma ray and resistivity. About half of those we have density and neutron for porosity logs. We have mud logs and pretty much all the named wells on the slide and what do you want me to do with that? (Off record comments) MR. KNOCK: Mud logs in the CD2 pad area, approximately five around the CD2 pad. RFT/MDT data, Alpine 1, Nanuk 2, Nigliq lA, Nanuq 5 from the 1995 to 2002 time range. Rotary sidewall cores in the Alpine 1 well in 1995 and in Nigliq lA well in 2001 up to the north. We -- really what determined that it was going to be a reservoir, going to be a development was the CD2-11 core in 2005. Oil samples from MDT in Nanuq 2, Nanuq 5 and then oil samples from core extract in CD2-11, oil samples from the production test in CD2-404, the horizontal R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 ~o • • 1 2 3 4 5' 6~ I ~i gl 9 10 11 12 13 14 15 16 I 17 18 19 '~, 20 21 I 22 I 23 I 24 25 well. The well test in 2006 which was our appraisal well and 3D seismic, the Colville 3D shoot from 1996 covers the area. Log model analysis, as I said we'd -- on slide 15 we got a core in the CD2-11 well, we had our petrophysicist Jim Cline (ph), use that core to calibrate a log model for the Qannik interval. On the slide you can see the red curve with the core data points tied to the porosity log, a pretty good match between core porosity and log porosity. From this well we have 11 and a half feet of net pay from the log model and that agrees with the core data. 22 percent porosity, 16 millidarcy perm and about 37 percent water saturation. In 2006 as I said, sorry, slide 16, we drilled the horizontal well shown on the map on the bottom, just north of the CD2 pad. We drilled almost 6,000 feet horizontal. Didn't have any significant trouble drilling the well. We have a net to gross of about two-thirds, about two-thirds of the horizontal footage is in what we would call net sand. We spent some time in between what we were calling lobe one, the upper lobe and the lower lobe. So we spent a fair amount of time in the sort of paleocsoapy (ph) section between the two lobes. we had some uncertainty in structural control, but no problem getting the liner down and no problem completing the well. So it all worked out very good. CHAIRMAN SEAMOUNT: Thank you, Mr. Knock. MR. KNOCK: You bet. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 17 • • 1 2 3 4 5 6 7 8 9I 10 11 i 12 13 i 14 15 16 17 18 19 20 21 22 23 24 25 MR. FRAZER: Okay. I'm Lamont Frazer, I'm on slide 17. I wanted to provide a little bit of additional testimony with regard to why we didn't initially proceed with Qannik development. Oil price paid a tremendous role in changing our minds. COMMISSIONER FOERSTER: So for either one of you. When you originally started working up in Alaska, 10, 20 years ago, did you ever think you'd be developing 11 feet of net pay? MR. FRAZER: Eleven, no, I really did not. MR. KNOCK: No. MR. FRAZER: The other issue associated with Qannik is -- and I'll talk more about this in terms of fluid properties, but reservoir temperature is nominally 90 degree Fahrenheit so it's cool. It's 38 PI gravity crude, so it's not as good as Alpine. It's going to be much more viscous. Our in situ viscosity is two centipoise. So relative to Alpine this is a -- it's not a viscous crude by any stretch of the imagination, but relative to Alpine which has .5 centipoise in situ viscosity, it is VISCOUS. In addition there was consolidation issues associated with Qannik. We didn't know if we could drill long lateral sections as horizontal wells. We proved that we could do that with our CD2-404 exploration well. Okay. I'm going to talk about reservoir and production. On slide 18 I have a fluid properties summation. And it shows R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 1~3 • • 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21, 22 ; 23 24 25 that we've got oil samples from basically four wells over the Qannik interval. And they're all nominally 38 PI gravity crude. The reservoir temperature is nominally 90 degrees Fahrenheit, our saturation pressure and our initial pressure is approximately 1,850 at 4,000 feet TVD subsea which is the approximate oil gas contact. As I mentioned we have two centipoise in situ viscosity, our density's about .88 grams per cc. Our solution GOR is just over 400 SCF per barrel. The -- our FVF (ph), formation volume factor, is about 1.2 reservoir barrels per stock tank barrel. And our compressibility is about eight times 10 to the minus six per psi. We do not have a water sample from the Qannik. We have not seen water in the Qannik reservoir however we did obtain a water sample from the Torok formation which the Qannik is a part of. This is much deeper, this is about 6,200 feet subsea in the number 2, but what it showed is that we had nominally 18,000 ppm sodium chloride, brackish type water. Our development plans. Initially we would like to go with the nine well development, those nine wells are shown here. We're going to keep our CD2-404 appraisal well and we'll drill eight additional new wells. Our recovery mechanism will be waterflood from inboard water injectors and gas cap expansion. from the east. I'm currently on slide number 20. There is a potential that we may have some gas cap expansion from the west, but the reservoir quality degrades so severely in that R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 i9 • • 1 2 3 4 5 6 7 8 9 10 11 ~ 12 I 13 14 15 16 1' 7 18 19 20 21 22 i 23 24 2 5 I~ direction that we're not really counting on it. I'm now on slide 21. And this shows the expanded opportunities that we have. We have three additional updip (ph) injectors that we plan to drill to the east if we're successful and we've identified six locations from CD4 that we'd like to pursue if we're successful. With these nine additional locations we'd have 18 development wells that we've identified. Here though our recovery mechanism would change. Because we'd be isolated from the gas cap expansion to the east, we'd be primarily a waterflood. There is the potential again that we might get some gas cap expansion benefits from the west, but we can't count on that. I'd like to talk about on slide 22 the CD2-404 production results. This is a plot showing rate versus time for the summer '06 CD2-404 production test. We produced the well for 19 days and averaged about 1,200 barrels a day, then we shut it in. We shut it in for seven days. During that time we used a geomodel that was calibrated to our reservoir model to the initial 19 day draw down and the seven day build up, and we'll talk more about the results of that model in the following slides. What we then did is we produced the well periodicalll• throughout the summer. We encountered some problems though and I've highlighted those problems with the circles. What we found is our rates would suddenly drop off very precipitously and when we'd go into the well we found that we had hydrates. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 LO • • 1 2 3 4 5 6 7 8 9 10 ~I 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 I So we tried it again and we found out we had hydrates again so we started methanol injection to address the hydrate problem and it did appear to address the hydrate problem, we had no problems while we were using methanol. We stopped using methanol, shut in our lift gas and the well basically died on us, we went in and we found hydrates again. I'm now on slide 23. Commissioner Foerster, you had asked OOIP for the upside case, that's shown here. We estimate our OOIP about 127 million barrels and our expected recoveries about 28 million barrels. I'd like to talk about how we derived these numbers here. For our nine well case as I mentioned earlier, we have 79 million in place, ultimate recovery projected at 17 million with a range of 11 to 25. We're expecting a recovery factor of about 22 percent. The incremental benefit of waterflood is about 5 million barrels or 7 percent original oil in place. That means that through primary depletion and gas cap expansion we're expecting about a 15 percent recovery factor. Our peak annual rate is about 4,000 barrels with a range of three to six which translates to an average expected yearly rate of about 700 barrels per day per producer. Now this is simulation based. We didn't simulate the 18 well case, however we did scale the simulation result from the nine well case to approximate what the 18 well case would give us. And that gave us a recovery of about 28 million barrels, R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 21 ~ • 1 2 3 4 5 6' 7 8 9~ 10 11 12 13 14 , 15 16 17 18 19 20 21 22 23 I 24 25 18 to 40, again since we're scaling we're using the 22 percent recovery factor and an incremental benefit to waterflood of 9 million barrels or 7 percent original oil in place. CHAIRMAN SEAMOUNT: Do you know the extent of the pool north south.? MR. FRAZER: Do we know the extent? CHAIRMAN SEAMOUNT: Where you run out of well control, I mean..... MR. FRAZER: I'll let Doug answer that. MR. KNOCK: No, we do not. We don't have sufficient well control to north or south and seismic doesn't really show it up very clearly. CHAIRMAN SEAMOUNT: So your original oil in place is just based on an assumption of how far each well will drill, correct? MR. FRAZER: The original oil in place was calculated for these purposes by using half the well distance. Our spacing is nominally 3,000 feet so we've gone out 1,500 feet around the boundary of each well and that's how we've calculated our oil in place. CHAIRMAN SEAMOUNT: Okay. But so It could be a lot bigger, right? MR. FRAZER: It could be, yes. We've done some calculations and as mapped within the area that we're seeking pool rules for, it's about 160 million in place. But there's a R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 22 • • 1 2 3 4 5 6I 7 8 9 10 11 12 13 14 15 16 17 ~ 18 19 20 21 22 23 24 25 lot of uncertainty there. I'm now on slide 24 where I'm going to talk about reservoir management and surveillance plans. Reservoir management, what we plan to do to optimize rate and recovery is use undulating horizontal wells. The remaining wells are targeted for seven and a half to 9,000 feet lateral section. As a guideline we plan to have peak to trough distances of about 2,000 feet. Clearly if we have good reservoir quality rock we'll want to stay in that reservoir quality -- good quality rock longer distances, but as a guideline 2,000 feet to trough. We also have the updip injectors that you saw if things go well for our expanded phase development. There's a chance we'll want to drill the updip injectors to the east at CD2 even if things don't go well. The case that would entail that is if our gas gap encroachment is more severe than our reservoir simulations are projecting, we'll want to isolate that gas. To do that we'll drill the three updip injectors that I previously showed. In terms of voidage replacement, we do ultimately plan to target a voidage replacement of one, however it's going to be a function of our pattern and configuration. For example, in the upside case where we have isolation from the gas gap our target will be one and we'd like to measure it within the floodable area. Let me go back and show you that. I'm going to go back R J R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 23 11 to slide -- I'm going to go back to slide 21. In this scenario 2 where we drill the updip injectors and we have 18 wells, within 3 the floodable patterns our target pressure will be plus or ~ 4 minus 200 psi from initial conditions. However in the case 5 where we go to the initial development and we don't drill the ~ i 6I updip injectors because our results are bad, I'm now on slide 7 20, in this case we'll target 200 psi plus or minus initial 8) conditions in the floodable area. Of course we will not be ~ I 9' able to maintain pressure in the gas cap and, in fact, in order 10 to realize the gas cap expansion benefits we'll have to have 11 that go below saturation pressure. So our voidage replacement I 12 will be a function of our ultimate patterns. I 13i COMMISSIONER FOERSTER: Do you have adequate water? i 14~ MR. FRAZER: Do we have adequate water? We will have 15i adequate water for Qannik. We -- our latest projections are we j 16; can get adequate water from Alpine without hurting its flood, I 17 but, Commissioner, there is some issues with our toner (ph) in 18 terms of whether we can maintain that su 1 But that affects PP Y• 19 more than just Alpine, it affects all Colville River Unit 20 fields whether or not we'd be able to maintain our supply of 21 water from Kuparuk. 22 COMMISSIONER FOERSTER: Well, what would you suggest would 23 be the appropriate course of action if you're not able to get I 24i adequate water? I 25 MR. FRAZER: We have a team investigating alternatives I i R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 2`~ ~ ~ • • 1 2 3 4 5 6 7' I 8 9 10 11 12 13 14 15 16 17 ~i 18 19 20 21 22 23 24 25 right now. There's a number of options that we're looking at. I don't know which will be deemed the most economic, but there is other sources of water rel -- other than the Kuparuk River seawater treatment plant. There's a lower K-2 that's below us that could act as a source of water, there's the cretaceous source water wells at Kuparuk located at drill site 1-B that could be investigated. There's a number of options that are being looked at. COMMISSIONER FOERSTER: So are we saying it's being looked at because you anticipate problems here or because water's been a bottleneck and you need to -- you foresee further expansions, a combination of the above or something different or D, all of the above? MR. FRAZER: We believe that the seawater treatment plant that for the Colville River Unit. The talking about using for Qannik is I'll talk about our expected inje we're talking about 5,000 barrels modifications can be made to will provide adequate water amount of water that we're a relatively small amount and ~tion rates. But nominally of water per day for our nine well case. The water issue is a much broader issue and it's still in a state of flux, but it has to do with relations between ConocoPhillips and BP that are currently being worked and whether or not we'd be able to maintain the amount of water we want from the seawater treatment plant. And I'm not qualified R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 25 • • 1 2 3 4 5 6 7 8' 9 10 11 12 ~ 13 14 15 16 17 18 19 20 21 22 i 23 24 25 to talk move about that other than to say that we will do everything we absolutely can to get water, if that means having to look for other sources beyond the seawater treatment plant that's on the books right now that we're looking at. COMMISSIONER FOERSTER: Thank you. COMMISSIONER NORMAN: Mr. Frazer? MR. FRAZER: Yes. COMMISSIONER NORMAN: Could you go back to slide 21 for a moment, I just want to make sure that I under -- I believe I understand, but could you indicate there the area of the gas cap? MR. FRAZER: The gas gap -- in fact, I have a slide that will detail this in much more detail, but I'll..... COMMISSIONER NORMAN: Then I'll wait on that. MR. FRAZER: Okay. COMMISSIONER NORMAN: I'll wait until you come to that. MR. FRAZER: But let me -- let me show here because I believe that slide that details it might be in the confidential section so I'll detail it for the public. The gas gap is to the east. We've seen GOCs, Doug, correct me if I'm wrong, but I'm pointing to the approximate area where we're seeing the GOC because we cross the GOC with these injectors. MR. KNOCK: That's correct. MR. FRAZER: At the injectors even though we're penetrating into the GOC because it's a very low release system R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 26 • • 1 2 3 4 5 6 7 8' 9~ 10 11 12 13 14 15 16 17 18 19 20 21 22 I 23 24 25 we have mostly oil. Yes, we have gas, maybe a couple feet of gas on top of nine or eight feet of oil, so it's still a very enticing area to put our injectors. Of course we have uncertainty in terms of what the GOC does up here because we don't have well control. And the GOC to the west follows something like this, but again the reservoir is so poor there that it's unlikely it's going to give us much support. I'm back on slide 24. In terms of surveillance we plan to use well tests, pressure measurements and when appropriate surveillance logs. With regard to slide 25 I have a summary. This is Rule 3. In our written application we requested a specialized waiver specifically because we're drilling horizontal wells we'd like to come closer than the 1,000 foot well spacing minimum. Our heel to toe distances we'd like to be closer than that. And we would plan to notify the Commission any time that we drill within 500 feet of a boundary that has an ownership change. Another specialized waiver that we're looking at is..... COMMISSIONER FOERSTER: Do you have any boundaries with ownership changes? MR. FRAZER: I'll refer that to Dora. Dora, do we? MS. SORIA: Not in our blocks. COMMISSIONER FOERSTER: Okay. I didn't remember any. Okay. MR. FRAZER: On slide 26 we are seeking a GOR exemption in R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 27 • • 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 accordance with regulation 25 240(b) With enhanced recovery operations we'd like exemption from the GOR limits. And, of course, if we have the gas cap expansion benefits, we would have to have relief from those benefits otherwise we could -- or the regulations otherwise we couldn't produce the wells. Now I'm going to talk about surface facilities on slide 28. This is an outline of the CD2 drill site. What I have here is I have a overview of where we added our additional gravel and that's shown with a crosshatched area. And then I have blown up details in terms of what equipment, what additional facilities we added. We have our Qannik well row that can hold up to 18 additional wells, we have a chemical injection skid and we have a REIM or remote electrical instrumentation module. We do not yet have methanol storage on the facility although it's a possibility given the hydrate problems that we have, but we have identified space for it if we can't overcome those problems. We've also identified space for a future heater and separator if necessary, but right now neither of those are currently planned. In terms of metering the separation involves using divert valves to route production to a test separator. CD2 has a two phase test separator. We then measure the fluids, our produced gas is measured using a Coriolis mass meter corrected to STP. Our produced liquids are metered with a Coriolis mass meter. We use a microwave analyzer for water cut determiner and, of R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 2 is • • 1 2 3 4 5 6 7 8 9 10 11 12 13 14 I 15 16 17 18 19 20 21 22 23 24 25 course, we correct the old to STP. Other liquids or other fluids that we're metering including water injection, we use Orifice plate meters .for each well and lift gas where we're using Coriolis mass meters for each well and, of course, we correct to STP. Fluid allocations, we're now on slide 30. We're going to use the same methodology as we use throughout the Colville River Unit and that. is to -- basically what we do is we come up with an allocation factor that's calculated by summing the individual well tests for all the wells and dividing by the metered production and then we multiply that allocation factor by the test volumes for an individual well to come up with an allocated oil volume. And that concludes surface facilities and I'll turn it over to Brian Noel to talk about drilling and completions. CHAIRMAN SEAMOUNT: Are you giving sworn testimony? MR. NOEL: Yes, I am. CHAIRMAN SEAMOUNT: Please raise your right hand. (Oath administered) MR. NOEL: Yes, sir. CHAIRMAN SEAMOUNT: Please state your name, who you represent, whether you want to be an expert witness and what your qualifications are on what subject? Thank you. MR. NOEL: All right. My name is Brian Noel, I'm a drilling engineer with ConocoPhillips and I will be giving R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 29 • • 1 2 3 41 5~ 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 expert testimony. I have a bachelor of science in geology from the University of Illinois and also a bachelor of science in petroleum engineering from the University of Wyoming. I have over 25 years of varied industry experience in the Rocky Mountains and Alaska, I've been working as an engineer here in Alaska since 1991 for Conoco and their predecessor ARCO. And the last 10 years have been working in drilling. And in 2002 I obtained my PE license in petroleum engineering in the state of Alaska. CHAIRMAN SEAMOUNT: So you became a traitor to geology then. Any..... MR. NOEL: The downturn did that to me. CHAIRMAN SEAMOUNT: I don't blame you. Any questions, Commissioner Foerster? COMMISSIONER FOERSTER: No, I have none. CHAIRMAN SEAMOUNT: Commissioner Norman? COMMISSIONER NORMAN: You said you're working toward your PE license or you have your PE license? MR. NOEL: I obtained it in the fall of 2002. CHAIRMAN SEAMOUNT: Okay. So you are ruled an expert witness in petroleum engineering or drilling -- drilling engineering or both? MR. NOEL: Drilling engineering is my testimony..... COMMISSIONER FOERSTER: He's done both. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 30 1 2 3 4 5 6 7 81 9 I 10 I 11 12 13 14 15 16 17 ~ 18 19 20 21 22 23 24 25 ~ i CHAIRMAN SEAMOUNT: He -- okay. MR. NOEL: .....but I've done both. CHAIRMAN SEAMOUNT: We'll even throw in geology too. MR. NOEL: Thank you. COMMISSIONER FOERSTER: Don't forget to say what slides you're talking off of. TESTIMONY BY BRIAN NOEL MR. NOEL: Okay. We're currently on slide number 32. As you already heard it's -- the Qannik for the initial development is nine wells. We have drilled the CD2-404 well in 2006, a very successful operation. And what this slide portrays is the Qannik well spider map, it's a planned view of the wells. And then the grayed out underneath are the 60 Alpine sand wells that have been drilled from this CD2 pad to date. The base plan for Qannik is seven to 9,000 foot horizontals. The initial well we drilled was 6,000 feet so we've increased the length to span more of the reservoir as currently mapped. And we have been drilling in the Colville River delta since 1999, over 130 horizontal wells to date to various reservoirs, initially Alpine and then the Alpine satellites. Here's just a brief overview of our joint practices. These are consistent with the drilling that's been done to date in the Colville delta. These are all deviated wells so the R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 31 • • 11, 2 3~ 4 5 6 7~ 8 9 10 11 12 13 14 15 16 17 ~~ 18 19 20 21 22 23 24 25 directional surveys with MWD tools. The open hole logs would be obtained logging while drilling, no plans for wireline logs given the hole angles. We have the same horizontal wellhead system we've been using for all the development out there, it allows a single BOP rig up and a much more efficient operation for the following casing runs. And the North Slope muds we're using are typical across the Slope, it's the same we've been using for Alpine and the satellites. The first two hole sections, the surface and intermediate are both water based mud systems. And then for the horizontal in the Qannik sand we drilled the first well with a mineral oil based fluid in it, it's mainly being used due to the interbedded shales and trying to minimize reservoir damage. And we plan to continue with annular disposal of our drilling fluids and cuttings. The area injection order for Alpine recognized that there was no underground sources of drinking water in the area. We have a ball mill with the rig, we wash all the surface gravels and if they pass the test for contaminants we reuse those gravels for the spill on the gravel pads or roads out there at Alpine. And then the remainder of the cuttings we grind with a slurry and annular dispose with the mud. Our disposal interval under CD2 and consistent with all the Alpine pads is the top of the CB formation. It reallll R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 32 • • 1 2 3 4 5 6 7 8~ 9 10 11 12 13 14 15 16 17 18 19 20 21 22 i i 23 I 2 4 ii 25 accepts the fluids and our wells will be constructed and permitted under the regulation 25.080 for annual disposal. So we'd apply for each of those annual disposal permits separately as we move forward. Slide 34 is an outline of the drilling construction process. This is consistent with Alpine and the Alpine satellites. The new well on CD2 pad, the wells are spaced ors 20 foot centers. We have a conductor pipe which is insulated and thermo siphons installed to help with subsidence so we don't get enlarged thaw bulbs and have sink holes developing on the pad. Surface casings plan at 2,400 tvd and cemented back to surface in a single stage job. We've had no problems out there getting cement to surface on our wells. Then we install our BOPE and test it, test the casing and drill out our shoe, drill ahead less than 50 feet, perform the leak off test to show we have integrity. Drill our intermediate hole section and this is the directional part of the well where we turn the well so it's pointed north-south and land horizontally in the sand. We run our second string of pipe, the production casing, it's cemented in zone. We'll bring cement according to regulations above the top of the Qannik sand a minimum of 500 feet of coverage. Once that's in place we drill out 50 feet, perform a formation integrity test to show that we can drill the horizontal and R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 33 • • 1 2 3 4 5 6 7 8 9 10 11 12 13 i 14 15 16 17 18 19 20 21 22 23 24 25 have integrity within the sand and the casing shoe. Drill the horizontal section with the mineral oil mud, clean the well up. We plan slotted liners for the Qannik. If we do encounter significant shale beds we'll run blank pipe across the shale. And then we have what we call constrictors which are small, swellable packing elements so we can blank off that shale and won't get fine movement within the horizontal section and plug up the well. The injectors, we plan to submit quality log before we run our packer and tubing. And then on the producers you've heard we did experience some hydrates in the first well so we plan to install thermo centralizers which are plastic centralizer on the tubing so we get stand off from the casing wall and that modeling shows will give us enough extra temperature in the tubing to keep us out of hydrate window. On slide 35 the two wellbore schematics are shown. On the left if the producer and on the right is the injector. The t~fJo main differences are the producers, we plan gas lift so there's gas lift mandrills (ph) in the tubing string right here. And the base plan is it just two given the shallow depth were at to lift the well adequately. The producers will also have like all the other wells at Alpine a subsurface -- a surface controlled subsurface safety valve and also a fail-safe surface safety valve. On the injector we have a profile at the same depth as the R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 34 i t 1 2 3 4 5 6 7 8''I 9 i 10 ~ 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 producer's subsurface safety valve, but it accepts a wireline run injection valve. And we'll also have a surface safety valve. And then consistent with Alpine and the Alpine satellites, there was two waivers we are asking to be incorporated in the pool rules. The first one was in lieu of the regulation on what is required to be submitted for the directional plan. Our proposal was -- is more comprehensive and has become the accepted standard with the permit to drill packages where we have the plan view vertical section, all the close approach data and a very detailed directional drilling program and any close approaches involved. And the second waiver in lieu of obtaining logging data from the conductor to the reservoir on every well out here since they're all in close proximity on the same pad, we were proposing just to obtain data at least on one well out there to meet that regulation's requirement. And that was it from the drilling completions unless there are any questions. CHAIRMAN SEAMOUNT: Any questions? COMMISSIONER FOERSTER: I have a few. Are you proposing any special safety valve system rules or are you anticipating that the amendments we're making to the statewide safety valve rules will be adequate for you guys? MR. NOEL: Those will be fine with us. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 35 • ~ 1 2 3 I 4j 5 6 7 8 9 10 11 12 13 14 15 ~ 16 17 18 I 19 20 21 22 23 i 24 25 COMMISSIONER FOERSTER: Okay. And the second one is did you encounter any of the unconsolidation concerns that you anticipated and if so how did you deal with them and what -- is there anything you're going to have to do for them? MR. NOEL: The production tests we didn't see any formation fines during the production and also we injected water and flowed it back and had very little solids coming back. COMMISSIONER FOERSTER: Thank you. MR. NOEL: And drilling the well we didn't see any issues with the -- trying to keep the horizontal open, that was one big concern. COMMISSIONER FOERSTER: That's all. I have no questions. CHAIRMAN SEAMOUNT: Commissioner Norman, do you have any questions? COMMISSIONER NORMAN: Mostly just about the sequence of your presentation. I'm guessing now that you will go into some of the material for which your asserted -- ConocoPhillips is asserting confidentiality, is that right? MR. FRAZER: What I'd like to do is address a couple questions, give an outline of some of the confidential material and then we'd like to go into the confidential section. COMMISSIONER NORMAN: Sure. CHAIRMAN SEAMOUNT: Okay. COMMISSIONER NORMAN: Good. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 36 r • 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16' 17 18 19 20 21 22 23 24 25 ~ CHAIRMAN SEAMOUNT: So you're going to generally describe what kind of information you want to present in camera? MR. FRAZER: Yes. CHAIRMAN SEAMOUNT: And confidentiality always adds some complication. So, yeah, that would be real instructive. Also could you point out the people in this room that you would allow to stay in for this presentation? MR. FRAZER: Let me first address a couple of questions. CHAIRMAN SEAMOUNT: Come on up to the table, please. MR. FRAZER: Commissioner Foerster asked about the fines and flowing back. There was no appreciable fines that flowed back during the production test when we were flowing oil. After we injected water we did have 1 to 2 percent fines flowing back. It's not necessarily indicative of what we'll see in the field with water breakthrough because we injected well above (indiscernible) pressure and we did not attempt to gradually bring the well on, we just opened the choke and everything came back. So yes, we did have fines with water. COMMISSIONER FOERSTER: But not -- it's not something that you expect to see is it, to continue with -- the situation to..... MR. FRAZER: Nothing that we would expect to see with continuous oil production. We recognize there's a risk that we will see it with water production, it's not a certainty. If we do see it with water production we believe that we can handle R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 • ~ 1 2 3 4 5 6 7 8 9~ 10 11 12 ~ 13 14 15 16 17 18 19 20 21 22 , 23 24 I 25 it with chemicals to break any type of emulsions and vessel clean out. COMMISSIONER FOERSTER: And you're not -- you don't anticipate that i just fill us your MR. FRAZER: COMMISSIONER MR. FRAZER: COMMISSIONER is going to be so severe that it's going to wells, sand up your wells? Oh, no . No . FOERSTER: Okay. It's a -- no. FOERSTER: Obviously with no screens in your liners..... MR. FRAZER: The other thing I was going to address is you'd asked about ownership earlier, was there an ownership change. The specialized waiver in that case was more of a consistency request because it is similar to what we have with our other oil pools in the Colville River Unit and if we were to expand this pool so we don't get confused in having different rules to follow, that was the logic behind it. COMMISSIONER FOERSTER: And so if you're really lucky and it does extend to a greater area than you anticipated..... MR. FRAZER: It's possible. It's possible. COMMISSIONER FOERSTER: So we don't rule -- you know, to throw in rules that don't -- that we don't think will ever apply. MR. FRAZER: Right. The logic there, if the Commission agrees, was one of consistency. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 ~g • • 1 2 3 4 5 6 7' 81 I 9~ I 10 11 12 13 14 15 16 17 18 19 20 21 22 23 I 24 II 2 5 II COMMISSIONER FOERSTER: Thank you. MR. FRAZER: With regard to the confidential section, we had submitted a confidential written section with our application. That was a document that was intended to serve as a stand alone document. It contained both public and confidential figures in there. I think much of what -- or some of the key items that were placed in that document have been brought forth today during the testimony. If the Commission feels that there are either confidential figures in there that you need to have brought forward as public domain or in the confidential section that we're about to have, if you let us know I'm relatively optimistic given a relatively a short period of time, a week maybe two, we could with permission through our management system to get those in the public domain. We just ask that you let us know if there's any figures that you would like for us to try to put through the approval process. COMMISSIONER FOERSTER: Okay. Let me understand. The reason that you're asking confidentiality isn't that they need to be confidential for trade secret purposes or..... MR. FRAZER: The reason -- no. The reason we're asking for confidentiality is trade secret, they're interpretive data, they're trade secrets data, they're considered proprietary. However if the Commission feels it's necessary to make a ruling to move some -- a figure or two into the public domain we can R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 39 • • 1 2 3 4 5 6 ~I 8 9 10 i 11 12 13 I 14 15 16 17 18 19 20 21 22 23 24 25 I -- there hasn't been a final determination by our management to say no, under no circumstances, these will be held confidential. CHAIRMAN SEAMOUNT: So it's -- they're the figures, right, not the wording within the document or the..... MR. FRAZER: It would be both. CHAIRMAN SEAMOUNT: It would be both? MR. FRAZER: It would be both. CHAIRMAN SEAMOUNT: And what kinds of data are they, are they..... MR. FRAZER: In terms of the confidential data? CHAIRMAN SEAMOUNT: Like are they seismic data, are they maps? MR. FRAZER: There's seismic data, there's -- there's seismic data, there's core data. MR. KNOCK: There's some maps that show the trend of the sand body outside the unit area, you know, away from..... CHAIRMAN SEAMOUNT: Okay. MR. KNOCK: .....maybe where we hold acreage. CHAIRMAN SEAMOUNT: Okay. So they go onto unleased acreage? MR. KNOCK: I can't state that specifically, but certainly outside..... CHAIRMAN SEAMOUNT: But it might? MR. KNOCK: .....certainly the trend of the sand body on R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 40 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 I 21 22 23 24 25 one of the displays would suggest it goes outside the unit. MS. SORIA: If I may address that comment, this is Dora Soria, staff landman for ConocoPhillips. The lands are pretty secure, they're all leased either by us or by others. In addition to the confidentiality of this information being vital to proprietary data, interpretative data that is outside the scope that we usually provide to AOGCC, we also have partners to consider in this area and we have not had approval from partners to expose any of this data. And like I said it is proprietary to the company and it is subject to trade secrets, et cetera. So the fact that you would ask for us, still may not be that we would respond that we will make it public, we would just make a big effort to try to make it public in the event that you requested that. CHAIRMAN SEAMOUNT: Okay. Well, you hit on something that -- it seems like so far and we're going to have to go into recess to discuss this among the staff, but so far you've given a very -- I think a very complete presentation. And we may not need to look at the confidential information although we would love to see it, but it may not be necessary. COMMISSIONER FOERSTER: And we have a concern with accepting information as confidential, but, you know, then it becomes vaccinated as confidential forever and that may not be an appropriate move for us to make. So we would rather err on the side of not accepting data that we don't need and then R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 4i 1 2 3~ 4 5 6 7 8 9 10 11 12 13 14 15 16 I 17 18 19 20 21 I 22 23 24 25 deeming it confidential. MR. FRAZER: Okay. MS. SORIA: Well, we would appreciate your ruling one way or the other and like I said we..... CHAIRMAN SEAMOUNT: Okay. MS. SORIA: .....we will defer to you. Thank you. CHAIRMAN SEAMOUNT: I..... COMMISSIONER NORMAN: I have one question. CHAIRMAN SEAMOUNT: Commissioner Norman? COMMISSIONER NORMAN: Yeah. My question is -- relates to a different subject that I don't think is confidential. So if it's appropriate I'd like to ask it now before we start talking about the confidential. CHAIRMAN SEAMOUNT: Okay. COMMISSIONER NORMAN: Mr. Frazer, you used the term gas cap expansion and you also mentioned in a different context gas cap encroachment. MR. FRAZER: Yes. COMMISSIONER NORMAN: And can -- could you explain to me a little more the encroachment, your use of the term gas cap encroachment..... MR. FRAZER: Yes. COMMISSIONER NORMAN: .....as opposed to expansion? MR. FRAZER: They're basically synonymous. What I'm trying to illustrate though is that we can produce R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 42 • • 1 2 3 4 5 6 7 i 8~ 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 I (indiscernible) above solution gas up to a limit. Our facility limits right now are nominally a 5,000 GOR in the summer. Our projections are that we won't have appreciable facility limits around 2012, 2013, time frame from a gas handling standpoint. So as long as we can maintain a GOR below 5,000 through 2012, 2013 time frame, we don't view that as a concern. If we too much gas coming at us in the next couple of years and the GOR~s rise four or 5,000, that is a concern, we'll have to try to stem the gas encroachment. COMMISSIONER NORMAN: And my final question, all the gas we're talking about in this particular context is situated and confined within the proposed pool? MR. FRAZER: Yes. The..... COMMISSIONER NORMAN: In other words there's no one else's gas that you see coming from the..... MR. FRAZER: There is no one else's gas I can see coming in. There is a very poor quality, non-reservoir quality zone that is gas saturated above the Qannik interval. It's possible that trace amounts from sub one millidarcy rock could expand in, but nothing appreciable. COMMISSIONER NORMAN: That's all, Commissioner. CHAIRMAN SEAMOUNT: G~TeIl, what I -- anything else, Commissioner Forester? COMMISSIONER FOERSTER: I wanted to compliment the entire suite of presenters on a very clear to understand and complete R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 =? 3 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 I 18 19 20 21 22 23 24 I 25 • presentation of the information. But no other questions right now. CHAIRMAN SEAMOUNT: Ditto. So what I'd propose right now is we'll go into a 10 to minute recess and the discussion will be whether we have enough information in order to make a decision on this application and also whether we have some questions of clarification. And we may come back and want to go into the confidential section or we may come back with just a -- with some questions. And if any of those questions involve confidential information be sure to let us know. MR. FRAZER: Very good. Thank you. CHAIRMAN SEAMOUNT: Okay. COMMISSIONER FOERSTER: And while we're at recess there are cookies out there. I've tested them, they're high quality. CHAIRMAN SEAMOLTNT: There's coffee too. MS. SORIA: If I may address the Commissioners, please, this is Dora Soria again, ConocoPhillips. You had earlier asked that -- you would ask the public if there were additional comments, would this be the appropriate time or would you prefer that those comments be addressed after the recess? CHAIRMAN SEAMOUNT: Do you -- do you have any public testimony following the in camera session? MR. FRAZER: I don't know. I'm sorry, I didn°t understand your question. CHAIRMAN SEAMOUNT: (Indiscernible) area injection order. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 4 4 • • 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 i 23 24 25 MR. FRAZER: We have an area injection order. CHAIRMAN SEAMOUNT: Yeah, I'm wondering whether to go to the area injection order, the public part of that right now. That may answer some questions that we come up with or should we take a recess? COMMISSIONER NORMAN: I would -- excuse me, I think it's cleaner if we finish this part of it and..... COMMISSIONER FOERSTER: Yeah, that's what I think. Take a recess. CHAIRMAN SEAMOUNT: Okay. Off the record. (Off record) (On record) CHAIRMAN SEAMOUNT: Okay. The time is 10:33. We just came back from recess and we have a number of questions. And then we will reach a decision on whether the application for pool rules -- we have enough information to make a decision. Okay. So first we'll start with Commissioner Foerster. COMMISSIONER FOERSTER: I apologize, this is more of a curiosity question than anything. As you're drilling to the north where you -- and Brian goes that would be me. As you're drilling to the north you're going into an area where you don't have well control and certainty. If you're still drilling in pay when you reach the -- your projected end, are you going to keep drilling or are you going to stop? MR. NOEL: The current plan is to stop or -- we're about R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 45 1 2 3 4 5 6 7 8 9 10 11 ~ 12 I 13 ~ i 14 15 16 17 18 19 20 21 22 23 24 25 at our limits of torque and drag to reach out that far. COMMISSIONER FOERSTER: That's all I had. CHAIRMAN SEAMOUNT: Commissioner Norman? COMMISSIONER NORMAN: Yes. My question -- I think probably slide eight would -- do you have the ability to recall the slides? If you don't it's all right. The question just relates to the ownership in the southwest corner of the area, just to be sure that we're clear in that southwest corner of the proposed pool area. MS. SORIA: This is Dora, ConocoPhillips, is this the corner that you were referring to? COMMISSIONER NORMAN: Yes, generally the south -- that -- yes, right there. MS. SORIA: Okay. All of that is ConocoPhillips 78 percent, Anadarko 22 percent. Below the line there is different ownership, but other -- like I said the entire box is 78 and 22. COMMISSIONER NORMAN: Okay. And the lessor is ASRC, the lessor? MS. SORIA: The lessor varies, I don't have this outlined by ownership. Up in this area there's 100 percent state lands..... COMMISSIONER NORMAN: Uh-huh. MS. SORIA: .....and just for the public, I am looking at slide number one. This area in here is 100 percent state or R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 46 ~ ~ 1 2 3 4 5 6 7 8~ 9 10 11 12 13 14 15 !, 16 17 18 19 20 21 22 23 24 25 some of it. There's a combination of ..state and ASRC ownership in the center section, primarily the whole of new PA and then some of the boundaries on this is 100 percent ASRC land. COMMISSIONER NORMAN: Okay. MS. SORIA: Thank you. CHAIRMAN SEAMOUNT: Okay. I have a question for Mr. Knock. Is it mister or doctor? MR. KNOCK: Mister. CHAIRMAN SEAMOUNT: Mister. MR. KNOCK: I'm sorry. CHAIRMAN SEAMOUNT: Do you see any significant faulting or fracturing that would affect the reservoir performance and if you do is that why you're drilling in the direction you're drilling? MR. KNOCK: Very good questions, Commissioner Seamount. No, we -- seismically we do not have any mapped faults in the development -- in the nine well development area. In fact, we've only been able to map one fault to date that's sort of on the west side of the box there, but outside of our planned development. And that fault is a north-south fault. Based on regional data and just knowledge of normal breakout and whatnot, we feel strongly we have a north-south dominant horizontal stress, a maximum horizontal stress north-south to north-west. So we had oriented the wells with that in mind and, of course, our fairway with the gas to the east and to the R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 47 • • 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 I'. 18 19 20 21 22 23 I 24 25 west really makes us want to go north-south. CHAIRMAN SEAMOUNT: Okay. That -- okay. Now let's see. On your delineation well, did you say you ran any fracture indicator -- indicating logs? MR. KNOCK: Not to my knowledge. We ran just density, neutron and then we have the core and the whole core did not show significant fractures at all. So no, we don't have any real evidence from image logs of any significant fracturing. I believe we may have one image log across the zone in Alpine 1 and I don't recall seeing any fractures. It..... MR. FRAZER: If I may supplement? We ran a production log in the well and got about two-thirds down the lateral section and we saw no indication of flow into the well that would suggest fracturing. It's a relatively even distribution based on KH. CHAIRMAN SEAMOUNT: You're running liners all the way? MR. NOEL: That's correct. To total depth. MR. FRAZER: Slotted liners with blank pipe along the non- pay sections and then we can use the blank pipe as an indication of flow. CHAIRMAN SEAMOUNT: So -- but you don't do that in the Alpine pool, do you, those are just open hole completions, is that correct? MR. KNOCK: Correct. Although we're switching to running more liners because we're fracking more wells and if we find -- R& R C O U R T R E P O R T E R S 811 G STREET (907)Z77-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 48 • • 1 2 3 4 5 6 7 8) 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 we can focus the fracks with the perforated liner. CHAIRMAN SEAMOUNT: And I believe Commissioner Foerster has another question. COMMISSIONER FOERSTER: On slide number 10, you know, just so Dora gets enough exercise, I know she's not going to hike this evening, this one's for Dora. On slide number 10 there's a hole in your ownership or a hole in the unit boundary? MS. SORIA: This I think -- this is Dora Soria, ConocoPhillips. I think we're looking at slide 10 and. you're referring to this north western area. That is a -- not a hole in ownership, ConocoPhillips and Anadarko own that 78/22, it is just a hole in the unit, it is not part of the unit currently. COMMISSIONER FOERSTER: Is there a reason for that? MS. SORIA: Because in order to bring something in the unit usually we either have to have a well that compels that or we have to have evidence that they're -- that it is part of a PA expansion and so forth and to date we have not gotten to that point. We hope to with this area or some other area. COMMISSIONER FOERSTER: Thank you. MS. SORIA: You're very welcome. CHAIRMAN SEAMOUNT: Any more questions, Commissioner Norman? Okay. As far as the confidential section, obviously we would like to get as much as we can into the public record, but having heard your very complete presentation today, we're going to give you the opportunity to withdraw the confidential R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 49 • • 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 I 16 17 18 19 20 21 22 23 24 25 section. We don't feel we need any more information to make a decision. So would it be your preference to withdraw it? MR. FRAZER: Yes. CHAIRMAN SEAMOLTNT: Okay. So be it. MR. FRAZER: I had a follow-up question though. The hard copies of the presentation we gave you as well as the CD had the confidential section attached. Would you destroy that then, is that the procedure that would..... COMMISSIONER FOERSTER: We'll give all that to you. MR. FRAZER: Oh, you'd give it to us? COMMISSIONER NORMAN: We'll return it~so you can cancel it all, we'll..... MR. FRAZER: Okay. COMMISSIONER NORMAN: .....we'll return every copy to you that way they'll be no misunderstanding. MR. FRAZER: Thank you. COMMISSIONER FOERSTER: In fact before you leave today I would prefer that you walked out the door with it. MR. FRAZER: Okay. CHAIRMAN SEAMOUNT: Okay. So I guess that concludes the pool rules part of this hearing. And I understand that you want to go to the area injection order? MR. FRAZER: Yes, sir. CHAIRMAN SEAMOUNT: Okay. And you're all under oath still and you're all still experts. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 50 ~ • 1 21 31 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 section. We don't feel we need any more information to make a decision. So would it be your preference to withdraw it? MR. FRAZER: Yes. CHAIRMAN SEAMOUNT: Okay. So be it. MR. FRAZER: I had a follow-up question though. The hard copies of the presentation we gave you as well as the CD had the confidential section attached. Would you destroy that then, is that the procedure that would..... COMMISSIONER FOERSTER: We'll give all that to you. MR. FRAZER: Oh, you'd give it to us? COMMISSIONER NORMAN: We'll return it so you can cancel it all, we'll MR. FRAZER: Okay. COMMISSIONER NORMAN: .....we'll return every copy to you that way they'll be no misunderstanding. MR. FRAZER: Thank you. COMMISSIONER FOERSTER: In fact before you leave today I would prefer that you walked out the door with it. MR. FRAZER: Okay. CHAIRMAN SEAMOUNT: Okay. So I guess that concludes the pool rules part of this hearing. And I understand that you want to go to the area injection order? MR. FRAZER: Yes, sir. CHAIRMAN SEAMOUNT: Okay. And you're all under oath still and you're all still experts. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 5G • • 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 II 22 23 24 25 ~ (Off record comments) MS. SORIA: This is Dora Soria again, ConocoPhillips. And still staying with the same matter I would like to make a correction to some of my earlier testimony. This is in regard to a question that was asked with regard to the submittal of the application for the Qannik participating area. I had already moved onto my next project and my next state, but the actual submission of the Qannik PA application was April 30 of this year. Thank you. COMMISSIONER NORMAN: As opposed to June..... MS. SORIA: Correct. Which is the next project. COMMISSIONER NORMAN: Okay. Good. Good. MS. SORIA: Apologies for the confusion. COMMISSIONER FOERSTER: That's forward thinking, forward thinking. MR. FRAZER: I'd like to start the testimony for the Qannik area injection order. On slide two I have an outline of the topics that we're going to talk to. I'll start off providing an overview and sundry information on various regulations. Doug Knock will address geoscience and the associated regulations with that. Brian Noel will talk about wellbore integrity and then Jack Walker will talk about injection confinement. With regard to regulation 25.402(c), there's 15 requirements that we need to meet. Six of those were covered R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 51 • • 1 2 3 4 5 6'~ I 7 I 8 9~ 10 11 12 13 14 15 16 17' 18 19 20 21 r 22 23 24 I 25 during the pool hearings and we'll refer to the pool hearings testimony if that's okay. And then nine we'll provide additional testimony for. The pool hearing reference will include these six regulations, namely -- I'm on slide four, this has to do with surface owners within a quarter mile, a description of the proposed operation, description and depth of affected pool, casing description and testing methods for injectors, the quality of the formation water and incremental increases associated with ultimate recovery. With regard to additional testimony we'll start out with 25.402{1) This is a plat showing existing penetrations within a quarter mile. There's 125 that fall within the quarter mile. This is slide number -- it's actually covered up a little bit by the map, it was slide number 5. On slide number 6 providing an affidavit of notification. I did on April -- I believe it was during Aprii, I provided notification to the operator, ConocoPhillips as well as state owners state of Alaska and Kuukpik of our intent to file for an application for an area injection order. Injection fluid analysis and rates. What this slide shows is our drilling brine, a synthetic formulation that provides cation and ations (ph) for -- or this is cations for our synthetic drilling brine, a synthetic mixture representing summer Beaufort Sea water and a synthetic mixture representing typical Colville River produced water. R& R C O U R T R E P O R TER S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 ~2 • • 1 2 3 4 5 6 7 8 i 9 10 11 12 13 I 14 I 15 16 ~, 17 18 19 20 21 I I 22 I 23 24 25 ~ The point I want to make here is if you look at the summer Beaufort Sea water and the Colville River produced water, in terms of total dissolved solids, I'm on slide seven, nominally 25,000 versus 23,000, very, very similar. In terms of salinities, calculated chlorine is 13,600 for Beaufort Sea water versus 13,000 for Colville produced water, very, very similar. We did a lab study looking at impacts on cores associated with injecting the waters. This is a slide showing permeability as a function of cumulative injection volume. Our cores have a core volume of about 15 cubic centimeters so thes` are numerous core volumes. What it illustrates is that with the synthetic drilling brine there's no indication suggesting we have any kind of damage whatsoever. With regard to the synthetic Beaufort Sea water, what you see here is that initially there's an increase in permeability that's a relative perm effect (ph) as we're displacing the mineral oil from the core. As we begin to flush the core you'll see that permeability does decrease with time. This 500 cubic centimeters, it's about 33 core volumes right here. What this suggests is that there is slight damage mechanism, nothing catastrophic. COMMISSIONER FOERSTER: Mr. Frazer, you called it synthetic Beaufort Sea water, was that a slip of the tongue or are you creating Beaufort Sea water in this case? R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 ~3 • • 1 2 3 4 5 6 71 8' 9~ 10 11 12 ~ 13 14 15 16 17 18 19 20 21 ~I 22 23 24 25 MR. FRAZER: We created a brine in the lab that is representative from an ion..... COMMISSIONER FOERSTER: So it is a synthetic? MR. FRAZER: It is a synthetic. COMMISSIONER FOERSTER: Okay. I heard you correctly. MR. FRAZER: This is a -- this was an interesting core. What we did is we took one of the worst cores that we had that we could flood. And you look at the permeability here, this is very poor quality rock, nominally .1 millidarcy. This is the rock that would be most suspectable to fines migration to -- which we expected we were having when we saw the decrease in perm. If you look at this it confirms that we do have fines migration. When you suddenly reverse flow as we have here, going from a forward flow to a reverse flow and you see large step changes, you're mobilizing fines, pushing them against the core throats and causing dramatic decreases in your injection. This confirms that we do have some fines migration that's occurring. In the written application we had numerous plots that showed a variety of cores. It's typical that you in those core flood that the stabilized rate was nominally about one-fourth what the initial permeability was and that's what you'll see here, .08 to .02. So with regard to injection waters, they are compatible with Qannik, there is absolutely no catastrophe permeability R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 54 ~ • 1 2~ I 3~ 4 i 5~ 6j I 71 8 I I 9 10 11 12 13 14 15 16 17 , 18 19 20 21 22 I 23 I 24 I 25 loss from the synthetic brines that were used in the lab study. And in addition we did pump Beaufort Sea water into CD2-404 as a short term infectivity test. Jack Walker will provide additional details on that test later in the talk, but we injected about 26,000 total barrels of Beaufort Sea water, we saw no indication suggesting damage. In terms of the produced Colville water what we were seeking is the ability to also inject that. We did not run any specific lab studies looking at Qannik core with the synthetic produced Colville River Unit water, but given that the compositions are so similar to the synthetic Beaufort Sea water, we're asking that the Commission accept that as indications that there is not going to be a catastrophic failure and that the brines are compatible with the reservoir. We had no significant adverse affects -- or I should say (indiscernible) adverse affects expected from fines. The reason we don't expect it is that if you look in the lab we have numerous core volumes before we see damages. In the field you expect to pump it at -- we'll be lucky if we got one core volume of water through the reservoir. The only places in the reservoir that we're going to see numerous core volumes pumped is either new wellbore injectors or new wellbore producers. Well, at the injectors we have the ability to exceed (indiscernible) pressure so that's not an issue. In the reservoir itself actually diversion is beneficial because it R& R C O U R T R E P O R T E R S 811 G STREEt (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 i i i lj helps -- it's a self diverting agent that will help improve 2~ your flood. At the producers we have tremendous flow area. v~7e 3 have opened whole sections between 7,500 and 9,000 feet. We 4 don't expect to have any appreciable problem there. Hopefully 5i with better quality rock we'll be able to flow some of these i 6+ fines out so we don't have them plugging us. And in addition 7~ if we do have problems we have the ability to stimulate the 8 i wells . I 9 With regard to injection fluid rate analysis, I'm on slide l0i 12, with our initial nine well development we expect an average 11 injection rate of about 5,000 barrels of water a day. Our I 12 maximum injection rate is going to be about 12,000 barrels of i 13 water per day. If we go to our 18 development upside scenario 14~ case, there we expect the average injection to be about 7,000 15 barrels of water per day and our maximum rate to be about 'I 16~ 17,000 barrels of water per day. ~ I 17 Aquifer exemption reference on slide 13. Actually this is 18~ a incorrect titled slide. What this slide actually refers to 19 is discharge pressures. We expect the Alpine central facility 20 discharge pressure to be about 2,500 pounds. By the time it 21 reaches the Qannik the surface injection pressure is about I 22 2,400 pounds which translates into a subsurface injection ! 23 pressure of about 4,100 pounds. 24 Now we're at slide 14 talking about the aquifer exemption. I 25j reference. As previously mentioned there are no underground ~~ i R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ~ ANCHORAGE, ALASKA 99501 S v • • 1 2 3 4 5 6 7 8' i~ 9j 10 11 12 13 14 15 16 17 18 19 20 , 21 22 23 i 24 25 sources of drinking water that exist below the permafrost in the Colville River Unit area. And that is a determination that was published in area injection order 18B in October of '04, conclusion number 3. And with that I'll turn it over to Doug Knock who will talk about geoscience. COMMISSIONER FOERSTER: Before you do that I have one question, Mr. Frazer. You mentioned on slide five that there are 125 penetrations within a quarter of a mile. Is the future testimony going to discuss the mechanical integrity of the request? MR. FRAZER: Yes. COMMISSIONER FOERSTER: Okay. Great. CHAIRMAN SEAMOUNT: Commissioner Norman? MR. KNOCK: I'm not sure that was quite correct, 125 within a quarter of a mile. I think it may be 20. COMMISSIONER FOERSTER: Well, we can look back at slide five, but that's what was said. MR. NOEL: There's 20 wells within a quarter mile of the three proposed injection..... MR. KNOCK: Yeah, there's 125 in both pads, but they're about two, three miles apart, the two pads. So..... MR. FRAZER: The 125, I made the mistake and I got that count from looking at everything that when the -- that fell within the pool area..... R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 51 • 1 2, 31I 4 5~ i 6~ 7. 8 9~ I 10 I 11 • MR. KNOCK: The big area. MR. FRAZER: .....which is the larger area on that map with all those red dot penetrations. COMMISSIONER FOERSTER: But within the area that we need to be concerned with, what's..... MR. FRAZER: Within the area that we need..... COMMISSIONER FOERSTER: That we need to be concerned with for this area injection order? MR. KNOCK: We have a display coming up that shows that. We're going to talk..... COMMISSIONER FOERSTER: Was that a statement or a 12 ~~ question? 13 14 15 16 17 18 19 20 21 22 23 24 ~ 25 MR. KNOCK: It -- we do (indiscernible) section, we have a map, it's under -- well, that one will work to. MR. FRAZER: The 125 that I was referring to is everything that fell within this out -- larger boundaries. COMMISSIONER FOERSTER: Okay. So within the quarter mile of the Qannik participating area and the area injection order area, it's a smaller..... MR. FRAZER: The area for the injection order is this blue outline. COMMISSIONER FOERSTER: Okay. So the 125 is a valid number? MR. FRAZER: If it -- if we're referring to within the blue outline it's a valid number to the best of my knowledge. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/fax 274-8982 ANCHORAGE, ALASKA 99501 58 • • 1 2 3 4 5 6 7i 8 i 9 i 10 ~ 11 12 13 I'~ 14 15 ~ 16 17 18 19 ~ 20 i 21 22 23 24 25 COMMISSIONER FOERSTER: If you want your area injection order to be for the blue outline then that's a valid number. MR. FRAZER: Thank you. MR. KNOCK: This slide shows the lithologies above and below the Qannik formation. The Qannik -- this is slide number -- looking at the bottom, let me see what it would have been, it's slide number 16, I believe. The Qannik is at 4,000 foot depth. This lithology is taken from the Burgeon (ph) 1 mud log. And looking at the log data so that the Qannik is here where we have a sandy interval approximately, you know, 40 feet of potential sand. Going to the upper part of that being prospective. Above that we have 1,500 feet of largely mudstor~e interval with some thin sand interbeds and what we're calling the CB formation. And then we get up to the 2,400 foot TVD level and that's where we have a sand package that's oh, 100, 200 feet thick. Not an impressive sand, but a sand based on mud log analysis from cuttings. And that we call the C-30 interval. And that is our annular disposal interval below 2,350, 2,400 foot TVD. We've been disposing annularly in that interval in -- throughout the Alpine CD1, CD2, CD3 and CD4 drill sites. Again that's about 1,500 feet above the 4,000 foot depth Qannik. Below Qannik, a couple hundred feet below it, there is a sand, not real well developed over here in this part of CD1, but a little better developed underneath the CD2 pad and we call that the lower K-2 sand for lack of a better R& R C O U R T R E P O R TER S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 ~a • • 1 2 3~! 4 I 5i 6i 7~ 8 9~ 10 I 11 j I 12 ~ 13 14 15 16 i 17 j 18 19 '. 20 ~ 21 I 22 23 24 I 25 name. And that sand is water bearing. And it's aerially (phi restricted and most impressive under CD2 which I'll show on the next slide. Below that we go for really 2,000 feet down towards some sands in the basal torok above HRZ. So there's just a lot of mudstone and siltstone below Qannik other than. that more isolated sand at about 4,200 feet. And that sand is shown a little better on more of a blowup here. This goes across the CD2 pad, this cross section goes from southwest to northeast across CD2 and on it you can see the C- 30 disposal interval is this sand here. Here's where we set service casing at in all these wells, you can see the gamma ray go hot or the resistivity (ph) go off scale where we've set casing at. So we successfully are disposing of cuttings into that interval. Qannik is down here at 4,000 feet. Here's the sequence -- the (indiscernible) upper sequence that makes up Qannik. Down here is the sand at about 4,200 feet that we find in the CD2 area and it is wet by all indications on the resistivity log. So those are really the other sands that are in the vicinity of the Qannik interval. Other than that you -- like I said you've got to go way deep to run into more sands in the column down to 6,00 feet or so. And you can see that the other point of this slide is that the stratigraphy is very continuous in the upper part of the cretaceous here from surface down to below 4,000 feet we have very continuous stratigraphy. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 ri 0 • • 1 2 3 4 5 6 7 8 9' 10 11 12 13 14 15 16 17 18 19 20 ; 21 , 22 23 24 25 CHAIRMAN SEAMOUNT: That cretaceous section sure looks like Rocky Mountain cretaceous. MR. KNOCK: Yeah, and we -- we're a -- we don't have the tertiary (ph) they have over in Prudhoe, some of the nice sands over here, that's been scrubbed off. We've got mostly cretaceous from surface down. So the C-30 interval here in summary, there's 1,500 feet of interval above the Qannik, we call that the CD. The C-30 thickness is 100 to 200 feet thick, it's not an impressive sand, but it's well enough to dispose of our cuttings into. There's some log model analysis saying it's 28 percent porosity, 4 millidarcies perm from an RFT mobility, but this lower K-2 and is 200 feet below. It can be oh, up to 50 feet thick or so, it is wet, it is aerially (ph) restricted and it is completely separate from the Qannik formation 200 feet above it. And that's all I'm going to really say about the surfisual (ph) geology above and below Qannik. CHAIRMAN SEAMOUNT: Any questions, Commissioner Foerster? COMMISSIONER FOERSTER: None. CHAIRMAN SEAMOUNT: Commissioner Norman? Thank you, Mr. Knock. MR. NOEL: And I have two slides on the wellbore integrity. As you've already seen in the pool rules hearing, here's a schematic of the proposed injector completion again. R& R C O U R T R E P O R TER S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 5i • • 1 2 3 4 5 61 7 SI 9~ 10 11 12 13 14 ~I 15 16 17 18 19 20 21 22 23 24 25 And as previously discussed, this is drilled, cased and cemented per all the existing regulations and would have the cement quality log. And the tubing factor completions are all pressured tested and show a mechanical integrity prior to injection. There is one regulation, 412 (b) that requires a packer to be placed within 200 feet of your injection zone. Given the high departure and high angle of these wells, we were asking for a waiver just like we did on Alpine and the Alpine satellites to allow us to move that packer up for more efficient wireline access. And in this case the packer's still below -- 300 feet below the cement. And that only applies to one of the furthest north wells at this point. And so that's the plan for the two remaining injectors of the nine well initial development plan. The CD2-404 which will be the third injector was drilled, cased and completed just like the two future planned ones. And then our three injectors in the nine well program, there are 20 wells drilled to the Alpine sand. They're within a quarter mile of those three horizontal injectors. The one, NEVE number 1, was plugged and abandoned, the other 19 are Alpine wells that are currently operational, either producers or injectors. And they all have current integrity, there are no mechanical issues with them. COMMISSIONER FOERSTER: These 20 plus the ones that you're R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 62 • • 1 2' 3 4~ 51 i 6 7 8I 9~ 10 11 12 13 i 14 15 16 17 i 18 I 19 20 21 22 , 23 24 25 talking about on the page before, the slide before, cover the whole 125. So all 125 wells within the area of interest you can assure have mechanical integrity? MR. NOEL: Of the 125 I'm not aware of any on CD1 or the other wells on CD2 that have mechanical problems. And all of the exploration wells have been P&A'd. COMMISSIONER FOERSTER: Okay. There's a difference between not being aware of a problem and being aware that there's no problem. MR. NOEL: Okay. COMMISSIONER FOERSTER: Are you -- can you -- do you understand my question? MR. NOEL: Right. COMMISSIONER FOERSTER: My mother's not aware of any problems with any of these wells either, but that doesn't ma}ce me feel better about it. MR. NOEL: I'd have to ask our production engineers there for -- on CD1. We only looked at the wells that were within a quarter mile of the proposed injectors we're drilling..... COMMISSIONER FOERSTER: Well..... MR. NOEL: .....and verify those records. COMMISSIONER FOERSTER: Well, that will be information that we'll be looking forward to getting from you. MR. NOEL: Okay. We can -- we'll research that. COMMISSIONER FOERSTER: Thank you. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 '~ 3 • • 1 2 3 4 5 6 7 8~1 9 10 I 11 ~ 12 13 14 15 16 17 I 18 19 20 21 22 23 24 25 MR. NOEL: Those were the two slides I had and Jack Walker's going to talk about the remainder of the injection plans. CHAIRMAN SEAMOUNT: Commissioner Norman? Thank you, Mr. I Noel. (Off record comments) CHAIRMAN SEAMOUNT: Are you giving sworn testimony? MR. WALKER: Yes, sir. CHAIRMAN SEAMOUNT: Please raise your right hand. (Oath administered) MR. WALKER: Yes, sir. CHAIRMAN SEAMOUNT: Okay. Please state your name, who you represent, whether you want to be an expert witness in what discipline and what your qualifications are? MR. WALKER: Okay. My name is Jack Walker and I would like to be qualified as an expert witness. I am currently employed by ConocoPhillips as a staff production engineer and I have been employed by ConocoPhillips and predecessor companies in Alaska since 1980 with supervisory and engineering assignments at the Prudhoe Bay Field, the Kuparuk River Field, and most recently the Colville River Field with the focus on the -- what we call the western North Slope satellites. I have a bachelor of science in mechanical engineering from the University of Tulsa in 1979 and also hold a master of science in petroleum engineering from the University of Alaska R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 64 • • 1 2 3 i 411 5 i 6~ I 7 I 81 9~ 10 11 12 13 i 14 15 ~ 16 17 18 19 20 21 I 22 23 24 25 Fairbanks that was earned in 2005. I think that answers your questions. CHAIRMAN SEAMOUNT: Any questions? COMMISSIONER FOERSTER: Well, I feel obligated to have some problems with Mr. Walker because of this kind of tradition that we have. But since he has a mechanical engineering degree from the other UT I guess I'll let him go. CHAIRMAN SEAMOUNT: Commissioner Norman? COMMISSIONER NORMAN: Just curious, I have no questions regarding your qualifications. There was a Jack Walker very active in the Alaska oil industry some years ago, are you in any way related to him? MR. WALKER: Well, I've been active in the oil industry for quite a while, but I'm not sure I'm the right..... COMMISSIONER NORMAN: I mean -- let's say pre 1980, pre -- in the '70s? MR. WALKER: No, before 1980 I was not in Alaska. So..... CHAIRMAN SEAMOUNT: Okay. Well, Mr. Walker, you are considered an expert witness. MR. WALKER: Thank you. TESTIMONY BY JACK WALKER MR. WALKER: Okay. I'm going to cover two topics that relate to injection confinement and the first one will be fracture and modeling and then the second one would be open annuli in some of the existing Alpine wells that we've been R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 55 • • 1 2 3 4 5 6 7 8'~, 9 10 I 11 12 i 13 14 15 16 17 18 19 20 21 22 i I 23 24 25 referencing earlier. Fracture modeling of the Qannik injection wells was based on simulations using the Nolte Smith international software called Stem Plan (ph) and I use version 5.51. The fracture pressure from the CD2-404 injection test conducted in 2007 was used to calibrate the model also using -- or actually calibrate the Alpine 3 dipole sonic log, in situ stress and other mechanical properties from the Dipole sonic log at Alpine 3 were used for creating a fracture model. Shown on this slide are -- this is slide number 23, are -- on the left-hand side is the in situ stress that was used in the model, but was based on the Alpine 3 dipole sonic log. And the stress is shown on the horizontal axis and the depth is shown on the vertical axis. And that's the most sensitive element in the fracture containment at the Qannik injector well or in the injector well for that matter. Stem Plan includes a implicit finite difference solution for the fracture geometry and in this particular case for Qannik injection modeling was based on a vertical well injecting at 4,320 barrels per day and this would simulate a much greater stress than the expected stress in a horizontal well. Expected stress on the confining layers that is. After modeling of 2 million barrels of injection, the model revealed the graph on the right side as a summary of the injector confinement. Its width profile and vertical profile R& R C O U R T R E PORTER S 811 G STREET (907)277-0572/fax 274-8982 ANCHORAGE, ALASKA 99501 56 • ~ 1 2 3 4 5 6 7 8 9 I 10 11 i 12 13 ~ 14 15 ~ 16 ~ 17 18 ', I' 19 20 21 22 i 23 ~ 24 25 ~ with a width of approximately 0.2 inches and the stress profile and the model indicate that the confine -- the fracture induced by water injection would be confined to the Qannik interval and invested in the siltstone overlying the Qannik and then the shaley intervals underlying the Qannik. With that I'd like to move on to the -- some open annuli if there are no questions. And I'll define open annuli in a moment, but when we approached this project like any project that ConocoPhillips operates, our guiding principles were to have safe and environmentally prudent operations and to maximize resource recovery. Our strategy with regard to Qannik in particular was to implement enhanced recovery operations, waterflood only with no plans to inject gas into the Qannik interval. That we..... COMMISSIONER FOERSTER: Why is that? MR. WALKER: The gas has a lower viscosity and can tend to migrate more freely in other strata or in the near wellbore region. And so we believe that it's a more prudent course to inject only water. Coupled with that is our plan to refine some well monitoring. on the existing Alpine wells and if we see any communication with the Qannik injectors and the Alpine wells with open annuli or uncemented annuli, we'll remediate if necessary. This is a -- slide number 25 showing a schematic of the -- R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8482 ANCHORAGE, ALASKA 99501 07 • • 1 2 3 4 5 6 7 8, 9I 10 11 12 13 j I 14 15 16 17 ~ 18 ~ 19 I I 20 21 22 23 24 25 what we call the open annuli. Before recognizing Qannik as -- interval as a significant hydrocarbon zone, several wells were drilled and completed in the Alpine Oil Pool underlying the proposed Qannik Oil Pool. And those wells were constructed with nine and five-eighths in surface casing, cemented to surface with a casing shoe (ph) at about 2,400 feet TVD. And the production casing, seven inch production casing, cemented into the top of the Alpine interval and with the designed cement jobs at more than 500 feet cement top -- top of the cement more than 500 feet above the top of the Alpine interval. Between the surface casing shoe and the design top of cement for the Alpine wells there's an open annuli. In other words the Qannik interval is not cemented in the existing Alpine completions. We don't -- do not expect that cross flow has occurred or is occurring from the Qannik either to the lower K-2 sand that Doug Knock referenced earlier nor the C-30 disposal interval that Mr. Knock also referenced earlier. We have -- the reason we believe there's no cross flow is that the annuli began as a freshwater based mud earlier when the well was constructed and then we believe that the shales have collapsed around that casing and that several hundred -- or a few thousand feet of shale between the Qannik interval and the other zones. Further we conducted some annuli monitoring during the 2007 injection test of well CD2-404, Qannik injection test, a~:~d R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 08 • • 1 2 3 4 5 6 7 8 9 10 11 I 12 13 14 ~ 15 16 17 18 19 20 21 22 23 24 25 we saw no evidence of cross flow during that injection test and I'll discuss that in more detail. But nevertheless we have some monitoring planned over the long term of the Alpine wells with open or uncemented annuli near the proposed Qannik injectors. This next slide is slide 26, it's a graph that shows -- is an example of monitoring that will be done in the future and was actually done during the CD2-404 injection test in 2007. And plotted on this slide are several curves and I'll try to describe those. On the left-hand vertical axis pressure is plotted and the right-hand vertical axis rate is plotted for the CD2-404 injection tests. And the horizontal axis is time. So the blue curve shows the CD2-404 injection rate plotted on the vertical -- right-hand vertical scale, injection rate versus time for the CD2-404. The red curve shows the CD2-404 wellhead injection pressure plotted on the left-hand vertical axis. And while we were conducting the CD2-404 injection test we were monitoring the -- what we call the outer annuli or that nine and five-eighths by seven inch annuli in the off -- nearest offset Alpine well, CD2-11 and CD2-23. And those curves are shown in the purple color the CD2-11 outer annulus and in the pinkish color in the CD2-23 outer annulus. And there's no relationship between the outer annulus pressures in CD2-11 nor CD2-23 and the injection pressure, injection rate of CD2-404. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 59 • ~ 1 2 3 4 5 6 7i i 8~ I 9~ 10 11 12 13 ; 14 1 15 I 16 17 18 19 20 21 22 , 23 24 ; 25 I CHAIRMAN SEAMOUNT: How far apart are those wells? MR. WALKER: Mr. Chairman, the wells are shown on the -- the Qannik penetrations of the CD2-11 and the CD2-23 well are shown on this snap, this is CD2-23 penetration and CD2-11 Qannik penetration. This would be the CD2-404 injection .well penetration in the Qannik interval. So there's 700 feet, CD2- 11 and CD2-23 are both 700 feet from the -- what we call the production hole and CD2-404, the penetration of the CD2-404 in the Qannik interval. COMMISSIONER FOERSTER: Were they selected because they were the closest? MR. WALKER: Yes. COMMISSIONER FOERSTER: Okay. MR. WALKER: Yes. They were selected to monitor during that test because they were the nearest wells to CD2-404. If I may move on to the open annuli monitoring plan. We plan to install pressure transmitters on the outer annuli of the Alpine wells within a quarter mile of the Qannik injectors and that is the same list that Mr. Noel showed you earlier that he had testified had no mechanical integrity or problems that happen with mechanical integrity. COMMISSIONER FOERSTER: Okay. If in the review of the additional however many wells, you discover that there are ar~1• with mechanical integrity concerns would you be willing to put monitoring on those wells as well? Would it be acceptable to R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 ~fl • • 1 2 3 4 5 6i 7I i 8~ 9 10 ~ 11 12 I 13 14 15 16 17 18 19 20 21 22 23 24 25 you to have that be part of the area injection order that any wells that are discovered that have mechanical integrity issues to also be part of the monitoring program? MR. WALKER: I believe it would be acceptable to us depending on the nature of the mechanical integrity problem. I'm not sure if -- if we have catalysts. We have rule -- you know, pool rules or (indiscernible) inspection order for the Alpine Oil Pool addresses the (indiscernible) casing pressures and we follow those rules very carefully. And so I don't believe we will have -- find a mechanical problem. So depending on the nature of the problem I think it would be acceptable to us that -- it's hard to say without defining what the problem is. Anyway the -- these pressure transmitters would be connected to automated monitoring system we call it (indiscernible) and we have (indiscernible) capabilities in that system and we do a quarterly review of those outer annuli pressures to investigate the trends and look for communication. And just to summarize the open annuli presentation is we do not expect cross flow will occur in the Qannik interval with the other zones open in the existing Alpine wells. We plan to enhance the outer annulus monitoring of those wells that are I within a quarter of a mile of the planned Qannik injectors. j And then if we do observe any communication we would remediat as necessary. And the first step would be reduce Qannik R& R C O U R T R E P O R TER S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 ~~ ~~ • • 1 2 3 4 5 6 7 8 91 10 11 12 13 14 15 16 17 18 ~ 19 20I 21 Ii 22 23 I 24 25 i injection and then there are some concepts that we've discussed for creating barriers in the existing Alpine wells if we see communication. And that concludes my prepared testimony. CHAIRMAN SEAMOUNT: Commissioner Foerster, any questions? COMMISSIONER FOERSTER: I rudely interrupted Mr. Walker will all my questions. Thank you. CHAIRMAN SEAMOUNT: Okay. We'll -- you'll be chastised later. COMMISSIONER FOERSTER: Oh, good. CHAIRMAN SEAMOUNT: Commissioner Norman? COMMISSIONER NORMAN: Just one question. In simple terms for the public record and for my understanding, what could go wrong in this operation if you were asked to play devil's advocate, what could go wrong that would allow cross flow and migration of fluid to a place where it's not intended? Is this fail-safe or what -- and the word expected is used there understandably. What could go wrong here that we'd get these fluids into a zone where they're not intended? MR. WALKER: The question about the -- what could go wrong from a public safety perspective I think is fail-safe as you put it. There's really no -- with the surface casing cemented to surface I don't think there's any chance of injection fluids reaching the surface. So I would say it's fail-safe in that regard. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 ~2 • • 1 2 3 4 5 6i ~~I 8~ 9! 10 11 12 13 14 15 16 17 18 19 '' 20 21 22 23 I'' 24 25 CHAIRMAN SEAMOUNT: Okay. I don't have any questions, Mr. Walker, thank you very much. Now I'm wondering do we need to take another recess? COMMISSIONER FOERSTER: I'm looking at that (indiscernible - simultaneous speech)..... CHAIRMAN SEAMOUNT: Yeah, I want a vote from down there too. Do you guys have any questions? You're all satisfied and happy? Well, I am too then. COMMISSIONER NORMAN: I have one last..... CHAIRMAN SEAMOUNT: Okay. COMMISSIONER NORMAN: .....technical question. There is a requirement that the surface owner be notified and there is a proper affidavit in the file showing that notification was sent to the surface owner. But I wasn't able to see from that whether that was sent certified mail. And so my question is does the -- do you have evidence that that notification was received and the surface owner is aware of these proceedings? MS. SORIA: This is Dora Soria responding to your question and yes, I do and we will provide it to the Commission. COMMISSIONER NORMAN: It won't, I -- we will accept your..... MS. SORIA: Thank you. COMMISSIONER NORMAN: .....your representation. Thank you. CHAIRMAN SEAMOUNT: Okay. Any other questions, comments? R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 %3 • • 1 2 3 4 5 6 7' 8~I 9 ZO 11 i 12 13 14 15 ~ 16 17 ~I 18 ~ 19 20 21 22 23 I 24 25 COMMISSIONER FOERSTER: Once again I just want to thank you for a technically superior and clearly conveyed presentation. CHAIRMAN SEAMOUNT: Commissioner Norman? COMMISSIONER NORMAN: And I just want to join in that very briefly, but we see a lot of presentations and it was very good to receive a thorough presentation like this. It's what we would expect of an operator as experienced in here, but it is appreciated, it makes our job easier and I think it helps set a standard for what is expected in presentations before the Commission so we thank you. COMMISSIONER FOERSTER: And don't forget to get your confidential material before you leave. CHAIRMAN SEAMOLTNT: Yeah, I'd like to -- well, I agree with what the other two Commissioners have said about your professional testimony today. I think I'll make Mr. Steve Davies the team leader on getting the confidential stuff baclc to you guys before you leave. And you guys probably have some too in your -- in your area. Is there anyone else that wished to testify with the public? Other interested parties? Hearing none, I'm wondering do -- do you have something? COMMISSIONER FOERSTER: I was going to move to adjourn. CHAIRMAN SEAMOUNT: No, it's -- you're too early. I -- and I'm doing this for you. I think that you're waiting for an R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/fax 274-8982 ANCHORAGE, ALASKA 99501 ~~ • 1 2 3 4 5 6 7 8 9 10 11 12 ~ 13 I 14 15 I I 16 ~ 17 18 19 I 20 21 22 2 3 L' 24 2 5 illy answer so we need to hold the record open until you get that answer..... COMMISSIONER FOERSTER: Yes, we do. CHAIRMAN SEAMOUNT: .....and what is the question? COMMISSIONER FOERSTER: The question is what is the mechanical integrity in all 125 wells in -- within a quarter of a mile of the area injection order area. And if any of the wells lack adequate mechanical integrity what is the plan to address that. CHAIRMAN SEAMOUNT: Okay. And then my question to the lawyer Commission is it appropriate to adjourn the hearing or do we not adjourn it until we get the question answered? COMMISSIONER NORMAN: We can adjourn the hearing, but leave the record open for a fixed period of time to get the answer to that one last question. CHAIRMAN SEAMOUNT: So be it. COMMISSIONER FOERSTER: So how long do you guys think it'll take you to get that? MR. NOEL: A few days. CHAIRMAN SEAMOUNT: Let's give them 10 days. COMMISSIONER FOERSTER: Ten days. CHAIRMAN SEAMOUNT: Okay. Ten days. Again is there anyone else wishing to testify, ask questions or make a comment? Okay. It's your turn. COMMISSIONER FOERSTER: I move we adjourn. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 ~~ 1 2 3 4 5 6 7 I 8 I 9j 10 11 ~ 12 13 14 15 16 17 ~ 18 19 20 ~ 21 ~ 22 23 24 25 ~ • CHAIRMAN SEAMOUNT: So be it, we are adjourned. (Adjourned - 11:24 a.m.) (END OF PROCEEDINGS) * ~ ,~ R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 ~6 i 1~ C E R T I F I C A T E 2 UNITED STATES OF AMERICA ) SS. 3i STATE OF ALASKA ) 4 I, Rebecca Nelms, Notary Public in and for the State of Alaska, residing at Anchorage, Alaska, and Reporter for R & R 5) Court Reporters, Inc., do hereby certify: 6 THAT the annexed and foregoing Public Hearing held on May 15th, 2008 was taken by William P. Rice, commencing at the hour 7) of 9:00 o'clock a.m, at the Alaska Oil and Gas Conservation Commission of Alaska in Anchorage, Alaska; 8 THAT this Public Hearing, as heretofore annexed, is a true 9 and correct transcription of the proceedings taken by William P. Rice and transcribed by Lynn Hall. 10 IN WITNESS WHEREOF, I have hereunto set my hand and 11~ affixed my seal this 20th day of May 2008. I 12 13 Notary Public in and for Alaska My Commission Expires:l0/10/10 14 15 16 17 18 19 I 20 21 22 23 24 25 i i R& R C O U R T R E P O R T E R S ~ 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 • ~ STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION QANNIK HEARING May 15, 2008 AT 9:00 AM NAME AFFILIATION PHONE # TESTIFY (Yes or No) ~~E f~~c~~/ /4~r~a~-2uv ~~~ a~~eKN, ~1't_ G3L 3~1~~ n/~ ~c1~-c=- c P ~Z Z~ ~ - ~ ~ 7~ GG' ZCJ'-~~S`G ~' _. ~~A~~~~ Fv11..rnc~e. ~P~~~ ~(~~ 13y( ~ May 15, 2008.. - • ~. ;- 1 '~tyC1tJCO~~'t1~~1~5 QanniK Pool Rules Hearing :: ~ ..: • Introduction Lamont Frazer • Ownership & Development Area Dora Soria • Geoscience Doug Knock • Geology ~ • Exploration History , • Reservoir Description • Reservoir & Productior+ Lamont Frazer • Fluid Properties • Development Plans • Production & Recovery Projections • Reservoir Management & Surveillance • Specialized Waivers • Surface Facilities Lamont Frazer ;~ • Drilling and Completions Brian Noel • Practices & Plans • Specialized Waivers '~~~~_\ D~tGa~'~~ WI ~i.`6~1 1 pp~~~G~~~.11 I ~ ~Ii.A V ~ ~~.IA~AI l I~tt ~ • • "" .:May 15, 2008; 2 ~++~ ~ '~r+~~~C~Pi !~ ~' ~ pS • Promote Maximum ultimate Kecovery • Consistency with Other CRU Pools May 15, 2008 3 ~CanocoPhlli s ! r Qannik Pool Rules Hearing ,%~-~~~~ ~ :: ~ ~ i ntrod u~fiion Proj~Cfi ®v~rview ~,,__,.~ • CD2 Expansion • Add 7.5 Acres of Gravel to CD2 • Share Existing Infrastructure • 9 Horizontal Well Initial Development • 5000 Acres • Waterflood • 79 MMBO OOIP • 17 MMBO EUR • Up to 9 Upside Wells • Working Interest Same as Alpine May 15, 2008 4 Covi~l~ F~~v~~ ~'~it ,~ ~. .r CD3 CD1 CD2 ' C D4 ConocoPhillips U • Qannik Pool Rules Hearing .. .. .. t roj ~ • Drilled Appraisal Well June `06 • Obtained All Permits March '07 ~ • Filed PA Application May `08 • Facility construction Feb -Aug `08 • Initiate Development Drilling June '08 • First Production July `08 /~* , , May 45, 2008 << 5 ~r~! ~~~r.~Ph~~'~p~ 0 0 0 Qannik Pool Rules Hearing 0. Ownership and • Development Area Dora Soria • MaY,s. 2008 6 ConocoPhillips Qannik Pool Rules Hearing e~ ~ ~ ••• Unit Boundary ,!'~ - ~ + r _6s~Y ~ "`- Tract Boundary ~ Es~s ~ E ~ i h,n ~ ,- ~+ + ~- Proposed ~ i.; E Participating Area ~~\`\. ~ i QQ Tract Number _ ~-- ~- ----- 6,1~~„ ~ 6.6E/ s Eh52. 6563 ,. _+ , 6.E4 - t + r = a_~~'+ + + ~ ~% t + I i ts€~jr66rq~ TOI ¢~/Ut P+, + `~_r + + ~ } n g ' 1 e~ + ~~ Q° ~ ~ Proppoosed ~ennik Participating Area ,~j, " ~. ~ C> C 5~~ " ~ w~:~ ® < ~.~ ,, o ~Colville~ River Urtik ~ „ + si " ~ 'J ~ ~> rw~ ~~~.~ ~ - _ , ~a~ ~ ~,' ~ ,o ® c~ ~ ® ~~ ~ ~ a, ® ~, -T_ ~ ~~ i (3.t~ ~3~ ® i+ ~, sz~ ®c,;, ... ~ G ~) 89 6] t~J e ,~ ~ C~ " „ t~ ~~; ,~ - _ ;. _ i F p~ +~ ~ ~ ConocoPhillips - ~~ - ~~ Maska Inc. _ ~ ~ ~ ~ ~ _ Exhibit D m__:, Colville River Unit Agreement + - + ~ K~~ES Proposed Qannik ~ ~ ~ ~ ~ + s I Participating Area ~~ yg - K[IONETEflS N __ ___ ~ 12-17-07 0&091901HOU May , ~~ ~~ .. Q~ann~ A ~~~~s ~~~a~iiiiiiii ~i iii.. it i ii~irir nAAii~in Leases within Colville River Tn.t ~onocoF~hillips is Unit~.A Q!~erator SPA encompasses ~18,11~ acres ins ~ T11N-R4E 'T11N-R5E T'lN-R4E T12N-RSE all Umiat Meridian ~annik PA ownership •PA Working Interests (VVIs~, CPAI 78% ~ Anadarko 22% ~~~Is in tr~,~ts a~.~ aunt to ~"A A~ / Q ~/O Ana~.arkQ Z~ /ro ° '"~ ~onocoPh~ll~ps i' ~ ,~ ~ ~~ ~~" ``t ,_, ~/ ~ p® .~ O vI 0 O O • s 4, ~"; - ( o m ~~ ~ ~ o 0 ~ p ~_ a o a c ~ rn ~1~ O \\ iL ~~ ~ ~ ~m ~ t C3 ~ o C n wW _ /~ w ~ YWC~U ~ ~~.. f.~U C " p ~ \\/ ~ s <5 a ~~x ~? a y ~ V a N W ~~ \~~~ j ~ O x a ^ V_ Q O l~f. ~ ~N `~ - V a` a ^N N ~a m ... a va ,: ~ m o 4 mN ~ N ~N C.a ~ ~ 9N :0 N -~ p m p a ~ ^N _ _ as ~ J aU a Ca "~ ~ ~ `~ C7 m ^ Ua "a oa g $ ©N o ~ U ~I --- _I~ ~ °' p ¢ a a ~ ~ G m UJ O ~ m Q UQ N J __ i N ,:~, m 0 '~ r.. ~. i k F jl ((~~ ~^' a mN ~ oJN v'v~" ^O mN I N a~C ~ p ~ ~F U~ ~` ~ ~ t~t^ N mN O d c ^N UQ omit UQ _~M '~n ...., m ~ ~~ ~, dd m' d ~ ~ - UQ "~I .,_' ~ ~ u` ~ ~"• ,". N o o m N r~---1~-I u"S y~~ ''!` ~- v°'i I a s '& g ~ c7 - o r_ - ~ ~ ~n V Np ~ ~ ~ N m ~ `-' i~ m~v a'~' n U a U ,;,, a~ ~ N N~ a V N a U= a^ m^ > "~z ~ I ~~ a .,~ o ~ ~ - ~~ ~ U US~ N ., i., _ ~~ ~ ~ a a i ~ ~ a a^oN J ~~ ~m^~ ~ ~' k m.^ ~. ~~.. ' ° ~7 ~ m ~ N m ~ _ i .,Q ,,, ~'. c~ Q~ ~ N e4i ^~ m r a =~3 y --U~-. '' 1-_ _~ - "gym ~O m. N U .... °' ~. ..,. o ~ '~ - a m ha ~ ~ ~I ,., u L a~ m ~QUI cmi a a I ~ ~ y _ ~ .~. i ~/~~ V KU. I - p ~- ~ ~ mid ~.N .Q ~' m o a ~~~ _ ~~ _r~ mN ~: ^h. U x ~ r ~F ~ ~ 1 `, -; 1 I N '~ , yy^^ N NN m < ; ~' F$ ~ y.> ^N {... ~ ~ ',~U f .M ~'. 1Qmi ~ aaN ~ d p i~ . N ~ ~ V a /~ U U~ ~ m J I •- J UQ ~~ a ~. O a }},~~~ ~ p 4 a ~ ¢ a ON 8 ~N` m .?G V. F3 ~N N d d rnp as ~ ~ip - _ _.. d~ r ~~ IAN ~' aU a Ua qN gg 4 S t Z r' - m Ua ~ ^N t~ ~N oQ ~ ~ Ua m ~ ~ Q ai °~ as u;~ U ^ Uz _ I m .. ~~ iV ~ ~ ~ NU N U p~~'~ m -3v ~ --- - ~¢ _ a _ ~ a N ca a e rn ~ ~~ N rn~ W N av ^N _ mci r N Ua ~ O ~ Ua rnN d ~ H~ ~ a _.. -- U Q nNi p ~ ~N O O Vl '!~ I !~'~1 ~ fn N ~ a0 m '. U ';~ ~ caaia ~ (/~1 /1l ~ O dU NO OpN 4 m C O ~1 Vr~/ ~ ,n O ~..~. (~ Q Qmj 4 U ~: ~ ~ Q 8 o Q ,~ Q ~ N +~~.,t , , a 4 ~ __ ~.f``~' UQ ,,~ QU ~~ U Q rn b~ ,o Qannik Pool Rules Hearing ueoscience Doug Knock • May ,s.2oo8 9 ConocoPhillips • • Qannik Pool Rules Hearing ;%"_--~~ ~ .. -~ = 1 Pool l~. ~,_~ ---- Colville River Unit ~ i 1 -1 t-- ' 1 1--------, 1-- ---1 1-- 1 1 --- ~---- 1 CD3 ~ ~ - i ~.:j i ~ Qannik Pool Area ~ 1 . ~ 1 1 ~ ! 1 1 1 1 •1 1 CD2 CD1 1 1 • - F '~ • `' • '•'~ ~ 1 1 1 1 1--- I 1 C D4 1 MILES ' ••+~• • ••; 1 1 0 S 1 ---- 1 I I --"~1 1 ~1 1 -~ May 15, 2008 1 Unit: Colville River Unit Pool: Qannik Oil Pool Reservoir: Qannik Reservoir ConocoPhillips • ~ , Qannik Pool Rules Hearing ;; ~ -~~~~~ .. ~~ ~ Qannik Coil Pool Definition -CD2-11 ~,__;~ Measured Depth rn~ ~ V ~_ ~ O ~ ~ ~ ~ Z May 15, 2008 OH.NPHIS DEPTH ' oHMM - :~, eo Pu-s v OH.GR MWD S 1 _ ~~I I RH013 0 GAPI 150 1 OHMM 100 !. C_' 6030 6040 6050 6060 6070 6080 6086 6090 6100 6110 6120 6130 6140 6150 6160 6170 6180 6190 6200 6210 6220 6230 6240 24 ' 6 9 K-3 Basal K-2 The Qannik Oil Pool is defined as the accumulation of oil and gas common to and ~, correlating to the stratigraphic interval between 6086 and 6249 feet measured depth in the CD2-11 well, and its lateral equivalents. TVD -Subsea SSND I OHMM 0 PU-S 0 GAPI 150 1 OHMM 100 3990 4000 4010 4020 4030 4040 4050 4060 4070 4080 4090 K-2 Basal 11 K-3 Basal K-2 K-2 Basal ~` ~onocoPhillips • Qannik Pool Rules Hearing ~ :--~~ •' North Slo e Stratibr~ ~ahy '~~,,v, p Alpine Area Reservoirs SW NE o MA ` N O ~ SO 65 OI t --'_ y 0 96 -z~ Qannik W Nan s .~ocoKF`"~ ~ Nanuq _ ==~--.. Kuparuk C 144 -- ~ Alpine C, A y T---- Nechelik Kingak Fm Say Niver ~ 1 Shublik Fm. ~,JI TRIASSIC s , -s- - ~~; SadlerocFui_G{~~ --- 245 PERMIAN 286 ``~- PENNSYLVANIAN 32o Lisburne Gp~ MISSISSIPPIAN Erma GQ~ _~- May 15, 2008 I Z .~~,., ConocoPhillips • • Qannik Pool Rules Hearing ; ~'--~~~ I '' = ~ Geology Overview ~~,~i •. ~. w w ~ U l~cd~1f11K Jlf UGLUf C IVId ~'~ ~ ~ °1 ~i( '" ° i f~ `~ ~~ .. -~ c '- v 1 ~ Q a. ',_ .( ~~ „ , G a r. \ ~ e ~, ~ 0 `~ ~ ~~ 0 _~, __ ~fl ~~~~. ~~ ' ; ~; I\~..o `~ J C 0 May 15, 2008 13 • Dep Environs Shallow Marine • North-South elongate • • Depth: ~ 4000' sstvd • Trap: Structural / Stratigraphic - onlap to west, shale-out to east • Fluid Contacts: GOC ~ 4000' sstvd • Lithology: vf-grained, lithic-rich ss -equal parts quartz & lithics • Net Pay: up to 22 feet • Porosity: 20-25% • Permeability: 10-50 and S ,- ' ConocoPhillips • ~ • Qannik Pool Rules Hearing ;,%--~, I == I Qannik Data & Ex loration Hirt r ~~~;~ p ~/ May 15, 2008 14 • Well Penetrations - 120 w/ GR, Res; 60 w/ Porosity Logs • Mud Logs - All delineation wells i • RFT /MDT -Alpine 1, (1995), Nanuk 2 (2000) -Nigliq 1A (2001), Nanuq 5 (2002) • Rotary Sidewall Cores - Alpine 1 (1995) - Nigliq 1A (2001) • Whole Core -CD2-11(2005) • Oil Samples - Nanuq 2, Nanuq 5, CD2-11, -CD2-404 (2006) • Well Test -CD2-404 (2006) • 3D seismic (1996) ~,~ ConocoPhillips • Qannik Pool Rules Hearing CD2-11 Log Model Analysis • too y = 0.0023eo 3eai. ~ j -p R2 = 0.9061 ~ • ~ • T ._ •~ •p 10 • d ~ ~ d ~ a ~. as • U ~ • 1 15.0 17.0 19.0 21.0 23.0 25.0 27.0 Core Porosity Net Pay 11.5 ft Ave Poro 22.2 Ave Perm 16.4 and Ave Sw 36.8 ConocoPhillips • • May 15, 2008 1 5 Qannik Pool Rules Hearing ,, ~ -~'~~ .. ~ •` ~ I CD2-404 Cross Section ~~~_--- Horizontal Section (6 3/4" hole) - 5,979 Feet Net Sandstone - 4,094 Feet • CD2-404 May 15, 2008 16 ~~ ConocoPhillips • ,,.~o 5561 Qannik Pool Rules Hearing f\ Frazers UA�, r ulw UAO�, mu" & r o a um c t o n Lamont • May 15, 2008 17 ConocoPh illi s rrCll VG11111.JIG /"~~ ~ v~fap~a~r _Nanuk #5 MDT 29.9°API CD2-404 Production Test 29.4°AP1 CD2-11 Core Extract 31-32°APl Nanuk #2 MDT 27.2°API Qannik Oil Properties • Reservoir Temperature: 89° F Saturation Pressure: 1850 psig (Initial Pressure at 4000' TVD SS) Reservoir Fluid Viscosity: 2.0 cp Density of Reservoir Fluid: 0.877 g/cc Differential Vaporization Solution Gas-Oil Ratio.: 404 scf/bbl residual oil (97° F) Differential Vaporization Relative Oil Volume: 1.19 bbl /bbl of residual oil (97° F) Sing a Phase Compressibility at Saturation Pressure: 8..04 x 10-6 /psi (97° F) Cor1t?Ct.~P~1111t s May 45, 2008: 1 g Qannik Pool Rules Hearing ftk Reservoir iProperties 0 Nanuq #2 Torok Formation Water Component Amount (ppm), Sodium 79000 Potassium 150 Calcium 200 Magnesium 0 Bicarbonate 800 Sulfate0 Chloride 109600 r May 15, 2008 19 1 onocoPhillips • Qannik Pool Rules Hearing Development Plans Proposed Qannik •• Participating,Qrea Proposed Qannik Pool Rules 8~ Area Injection Order • Initial Development • CD2-404 Appraisal Well • 8 New Horizontal Wells • Recovery Mechanism • Waterflood from Inboard Injectors • Gas Cap Expansion May 15, 2008 Zo CD 3 AI ine PA • Gas Cap ' Expansion ~ cD ~ ~ Drive . .• • ~•. . • • .•r . .• • • r ~ ••M •i • •.• • CD 4 • • • Legend u • • • • ~ Ewsting Well • • • ~-~ Intial Phase InjeUa • Inllal Phase Produav • Existing WeN Penetration Waterflood from Inboard Injection o ~ W@IIS Miles ~~ ConocoPhillips • Qannik Pool Rules Hearing Developmefi n • Phased Development • 9 Well Initial CD2 Development • 3 CD2 Upside Wells • 6 CD4 Upside Wells • Recovery Mechanism • Waterflood • Potential Gas Cap Expansion • ~_ /~ ' ~~ ,.. ~ .. -_ Proposed Qannik Pool Rutes & Area Injection Order CD 3 Proposed Qannik .• Participating area AI ine PA CD1= .`. •. ,. , , •. •'CD Z .•r .• •~: . •s N • ~ •' ,~ CD 4 ~ • Legend •• • ~ • ~ ~ Existing WeX • ~ ~~ Intial Phase InJedor Intial Phase Producer ------- Planned Future Producer Planned Future Inledor • Existing WeN Penetiatbn ~ 2 ( Miles May 15, 2008 21 ConocoPhillips ~' ~ •' .•. \ s .~. ~~__~~ • ~® . O L 0. r~'7 L 'i G~ ^~ ~~ O / V ~ ~ .~ ~- • ~ ~ 0 .~ V O L. Q. 0 1 N 0 V • • i ca $ J ~ 0 ~ aU c o aUi .~ O a~ ~ I • ~ ±o ~ ~~ ~a '' 1 ~ ~ I, 0 0 0 0 0 0 0 0 0 o~O CO ~ ~N O 0~0 ~ ~' N r ~ ~ r ~ad08) uoi~onpoad 0£16 5Z/6 OZ/6 5 4/6 04/6 5/6 4£/8 9Z/8 4Z/8 - 9 418 - 4 418 9/8 ,a; 4/8 ~ LZ/L ZZ/L L 4JL Z 4/L L/L Z/L LZ/9 ZZ/9 L 4/9 Z 4/9 L/9 0 Q •~ ~~ ~~ O O O V N N 0 0 N T f4 ~ • ! Qannik Pool Rules Hearing %--~~ .. ~ ® ®_ r ~ c' z~ y ~~~~ ~ 3 ~ • Initial 9 Well Development (Simulation) • 001P: 79 MMBO • Expected Ultimate Recovery: 17 MMBO (11 - 25 MMBO) ~ • Expected Recovery Factor: 22% OOIP • Incremental Benefit of Waterffood: 5 MM60 (7% OOIP) • Expected Peak Annual Rate: 4 MBOPD (3 - 6 MBOPD) • Total 18 Well Upside Development (Scaled) • OOIP: 127 MMBO • 28 MMB 18-40 MMBO Expected Ultimate Recovery.. ( ) • Expected Recovery Factor: 22% OOIP • Incremental Benefit of Waterflood: 9 MMBO (7% OOIP) r ~onoCt~Phill s May 15, 2048_ 23 • Future Drilling • Average Reservoir Pressure ± 200 psi of Initial. Conditions within Flood • Surveillance • Well Tests • Pressure Measurements •__Surveillance Logs May 15, 2008 24 • ,~ '~C) r1C)COP~1 ~ ~ ~ 1 ~?S • Qannik Pool Rules Hearing .. ~ f /\ e. ® ® ® g / wetl Spacing {Rule 3) • Requirements of 20 AAC 25.055 waived (1000' Wefl Spacing) • No Minimum Vllell Spacing (Allows Close Heel-to-Toe Arrangement) • No Closer than 500' from Ownership Change without Prior Notification .. May 45,:2008 25 ~~! io~o~I f~~~~p~ • • • Qannik Pool Rules Hearing .. GOR Exemption (Rule 9) Wells producing from the Qannik OiI Pool are exempt from the gas-oil ratio limits of 20 AAC 25.24o(a) in accordance with the provisions of 20 AAC 25.240(b). ., May 15, 2008 26 ~t3Clt)C4~'~11~~~~JS ~r~~ ~~~ ~.. May 15, 2008 27 V~~V~VI ~~~~~~J Qannik Pool Rules Hearing ' ., ~ .. .. u c ii ® ' +e la ~ " ~ v .y Existin CD2 • .y ~ 9 Site Insert. i~;~'~~k~~ 4 ~~I.~~i ~~~~~n~.. , Facilities -' "~ ~ qtr ~°~~ ~~i;~~~ (Expanded) .. ,. ,. Chem. lnj. ;~ , . - ,. ;. .~.- ~~.~J=f,~ ~ ~ ~~ti_~o ~- ~t~~ ~:F~..s_ _, ~ - - ~~ ~ ~ Electrical ~~.f~ ~ ~ ~, a ~~" ~~ Instrument ~ ,.,.~ ~~~ ~. ~ _ ----- b ;~- , --s ..~ . .. , . -.. iY1F42 F,. `:af". .._.,- _,...-... ,... ~. icy w r = `• 1 ~ 1 1 ` ~. .,. ~- - . , . iT? (3-~~'~ [~ ~ ~ ~ z ... ~ ~•~ ~ •~ ~ MIIAC:m+ iiI ' ', (~ @ ,' , . b I .. X1171 4 x .. ..~~ C~anr~ik Wel~l~Row. ~ Gravel Pad - ~ : ~; ,~~ ,; Expansion :: ~ . , „~ (Hatched Area) ~. ~~.~ ~9 May 151 2008 2g ~~[ l~C~~~~~~~~~ • Produced Gas • Coriolis Mass Meter • Corrected to STP • Produced Liquids • Coriolis Mass Meter • In-Line Microwave Water-Cut Analyzer • Corrected to STP • Other Fluids • Water Injection-Orifice. Plate Meters for each Well Lift Gas-Coriolis Klass Meters for each Well (Corrected to STP) ~t~C1C>CC~F~'k1 I I 1 pS May 15, 2008 29 0 0 0 Qannik Pool Rules Hearing �'"0--w-F 1 Surfacen Standard CiRiver Unit Methodology Vti Theoretical volume for well i VtCRU = Total theoretical volume for CRU VtCRU = Vt1 + Vt2 + ``.. Vtn Vaggregate = Aggregate volume transferred for the CRU AF = Allocation factor AF = Vaggregate / VtCRU VAi = Allocated volume for well i VAi = AF Vti May 15, 2008 30 ConocoPhillips 0 0 0 Qannik Pool Rules Hearing O-W. mwftL ■ Uri iingAm- O*ftna-m %,00-m-mpietions Brian Noel May 15, 2008 31 Co11ocoPhill1 s ~~ Qannik Pool Rules Hearing ,%:---~~~ .• w ( / QannAk 9 v1-eII Dwel~prr~nfi ~____;~ • • Directional surveys with MWD • Open hole logging by LWD • .Horizontal wellhead system -single BOP rig up • Typical North Slope muds - Water based spud mud (surface hole) - Low solids non-dispersed (intermediate hole) - Mineral oil base drill-in fluid (horizontal hole) Annular disposal - No USDW's - Ball mill: wash surface gravels, grind cuttings for slurry - .Disposal interval (top Seabee Formation) exists below surface casing shoe - Wells permitted and approved under 20 AAC 25.080 for annular disposal • • 20' Well centers • 80' Insulated conductor, cemented in place and thermo-siphons • Surface casing at +/-2400' tvd and cemented back to surface • Install & test BOPE before drilling out casing shoe • Drill ahead <50' and perform LOT • Directional drill intermediate hole to land horizontal in reservoir • Set production casing in zone and cement • Drill out <50' and perform FIT • Drill horizontal section • Run slotted liner • Run cement quality log on injectors • Run packer and tubing. with thermal centralizers i May 15,:2008 3L~. ~Ct~'1~JGC'i~~"11~~I~S • Qannik Pool Rules Hearing ;.-~~--~-~\ ;; ~ Qannik Completion S~h~matic~ ~'~~~ ~~;~ Alpine CD2 -Qannik Producer Completion Alpine CD2 -Qannik Injector Completion 16" Insulated Conductor to 114' 16" Insulated Conductor l0 114' 4-1/2" DB Nipple at +/_ 2000' TVD w/ A-1 injection valve 3-1l2" Tubing retrievable, surface (differential pressure controlled SSSV) • controlled SSSV at +/_ 2450' ND 10.3/4" 45.5 ppf L-80 BTCM Surface Casing 10-3/4" 45.5 ppf L-80 BTCM Surface Casing at +/-2400' TVD, cemented to surface at +/-2400' TVD, cemented to surface 3-1/2" 9.3 ppf L-80 EUE 8rd Mod. tubing ~ ~ ~ ~ 4-112" 12.6 ppf L-80 IBT Mod. tubing 3-1/2" GLM w/ 1"valves GLM w/ dummy • valve above Packer Slick stinger w/fluted Production WLEG and shear sub Slick stinger w/fluted Packer Production yyLEG and shear sub Packer XN nipple Liner top hanger w/ XN nipple tieback rece table Liner top hanger w/ P tieback receptable =_= =-= =====_=_=- =- ========'-- a __ _ _ _----_-_--_-_-_--_ ---- ---- -------- --- - -- -- fop Qannik Reservoir 6000 - 9000' MD Horizontal at+/-4050' TVD _:.__.. _ Top Qannik Reservoir 6000 9000 MD Honzontal - - - 3-1/2" 9.3 ppf L-80 SLHT liner at +/- 4050' TVD -. 7-5/8" 29 ppf L-80 BTC Mod ~,,~/ slots across sand and blank across shale Production Casing @ +/-85° 7-5/8" 29 ppf L 80 BTC Mod 4-1/2" 12.6 ppf L-80 SLHT liner Production Casing @ +/-85° w/ slots across s~d blank across shale May 15, 2008 3 5 ConocoPh i l l i ps Qannik Pool Rules Hearing ... .. ,, ci i i Casing & Cementing Practices {Rule 4) • In Lieu of 20 AAC 25.:050 (b) • Permit(s) to drill deviated welly shall include a plat wi h a plan view, vertical section, close approach data and a directional program description. • In Lieu of 20 AAC 25.071 (a) • Petrophysical logs obtained from nearby exploration wells or wells drilled to other oil pools from the drilling pad may be submitted to meet these requirements. The Commission may, in its discretion, require additional wells on a pad to be logged and specify the log type. '~ May 15,:2008: 3 6 ' "~t"~}I'1C1COP~"11I ~ I ~JJS .l~ STATE OF ALASKA ADVERTISING ORDER SEE BOTTOM FOR INVOICE ADDRESS F AOGCC R 333 W 7th Ave, Ste 100 ° Anchorage, AK 99501 M 907-793-1238 o Anchorage Daily News PO Box 149001 Anchorage, AK 99514 NOTICE TO PUBLISHER ADVERTISING ORDER NO. INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED A O_02814043 AFFIDAVIT OF PUBLICATION (PAR72 OF THIS FORM) WITH ATTACHED COPY OF M ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE AGENCY CONTACT DATE OF A.O. Jod Colombie A ri18 2008 PHONE PCN DATES ADVERTISEMENT REQUIRED: April 9, 2008 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED tN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Advertisement to be published was e-mailed Type of Advertisement Legal® ^ Display Classified ^Other (Specify) SEE ATTACHED SEND INVOICE IN TRIPLICATE AOGCC, 333 W. 7th Ave., Suite 100 TO Anchora e AK 99501 REF TYPE NUMBER AMOUNT 1 VEN ~ Aim 02910 FIN AMOUNT SY CC PGM ~ 08 02140100 2 I REQUISITION PAGE 1 OF I TOTAL OF 2 PAGES ALL PAGES LC ACCT 73451 DIVISION APP FY ~ NMR 02-902 (Rev. 3/94) ~/ Publisher/Original Copies: Department Fiscal, Department, Receiving DATE AO.FRM Notice of Public Hearing • State of Alaska Alaska Oil and Gas Conservation Commission Re: Request for Pool Rules and Area Injection Order for proposed Qannik Oil Pool, Colville River Unit, Arctic Slope, Alaska ConocoPhillips Alaska Inc. (CPAI), by letter and application dated and received on April 3, 2008, requests the Alaska Oil and Gas Conservation Commission (Commission) establish pool rules in accordance with 20 AAC 25.520 and issue an area injection order in accordance with 20 AAC 25.460 for the proposed Qannik Oil Pool. CPAI's application may be reviewed at the offices of the Commission, 333 West 7th Avenue, Suite 100, Anchorage, Alaska, or a copy may be obtained by phoning the Commission at (907) 793-1221. The Commission has tentatively scheduled a public hearing on this application for May 15, 2008 at 9:00 am at the offices of the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. A person may request that the tentatively scheduled hearing be held by filing a written request with the Commission no later than 4:30 pm on April 28, 2008. 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 ca11793-1221 after May 9, 2008. In addition, a person may submit a written protest or written comments regarding this application and proposal to the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. Protests and comments must be received no later than 4:30 pm on May 12, 2008, except that if the Commission decides to hold a public hearing, protests or comments must be received no later than the conclusion of the May 15, 2008, hearing. If you are a person with a disability who may need special accommodations in order to comment or to attend the public hearing, please contact the Commission's Special Assistant Jody Colombie at 793-1221. Daniel T. Seamount, Jr. Chair • ~ Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Tuesday, Apri108, 2008 1:34 PM To: Ads, Legal Subject: Public Notice Attachments: D00080408.pdf; Ad Order ADN form.doc Please publish tomorrow. Jody Colombie Special Assistant Alaska Oil & Gas Conservation Commission Direct: 907-793-1221 Fax: 907-276-7542 '`Note new email address Page 1 of 1 4/8/2008 ~nchora a Dail .News ~ ~~loiz~xls g Y Affidavit of Publication 1001 Northway Drive. Anchorage. AK 99508 PRICE OTHER OTHER OTHER OTHER OTHER GRAND AD # DATE PC} ACCOUNT PER DAY CHARGES CHARGES #2 CHARGES #3 CHARGES #4 CHARGES #5 TOTAL 461323 04/09/2008 02814043 STOF0330 $199.20 $199.20 $0.00 STATE OF ALASKA THIRD JUDICIAL DISTRICT Angelina Benjamin, being first duly sworn on oath deposes and says that she is an advertising representative of the Anchorage Daily News, a daily newspaper. That said newspaper has been approved by the Third Judicial Court, Anchorage, Alaska, and it now and has been published in the English language continually as a daily newspaper in Anchorage, Alaska, and it is now and during all said time was printed in an office maintained at the aforesaid place of publication of said newspaper. That the annexed is a copy of an advertisement as it was published in regular issues (and not in supplemental form) of said newspaper on the above dates and that such newspaper was regularly distributed to its subscribers during all of said period. That the full amount of the fee charged for the foregoing publication is not in excess of the rate charged private individuals. Signed r c~ Subscribed and sworn to me before this date: Notary Public in and for the State of Alaska Third Division. Anchorage, Alaska ~ MY COMMISSION EXPIR $0.00 $0.00 $0.00 $0.00 $199.20 Notice of Public Hearing - State of Alaska Alaska Oll and Gas Conservation Commission Re: Request for Pool Rutes and Area Injection Order for proposed Qannik Oii Pool, Colville River Unit, Arctic Sk~pe,Alaska. ConocoPhillipsAlaska Inc: (CPAI), by letter and application dated and received on Apnl 3, 2008, requests, the Alaska Oil and Gas Conservation Commission (commission) establish pool rules in i accordance with 20 AC 25.520 and issue an area ~ injectionbrder in accordance with 20 AC 25.4b0 for. the proposetl Qanhik Oil Pool. CPAI's application may be reviewed at the offices of the Commission, 333 West 7th Avenue, suite 100, Anchorage, Alaska, or a copy may be obtained by phoning the Commission at (907) 793-1221: ~7he Commission has tehtativel¢ scheduled a public hearing on this application for May,15, 2008,' at 9:00 am at the offices of the Alaska oil and Gas Conservation Commission at 333 West 7th Avenue, suite 100, Anchorage, Alaska 99501: a person may requestthat the tentatively scheduled hetiring;be held by filing a written request with the Commission noiater than 4:30 pm on Apnl~8, 2008. If a request for a hearing is not timely filed, the Commission may considef the issuance of amorder without a hearing. To learn tf the Commission will hold the public hearing, please call 793-1221 after May 9, 2008: , In atldition, a person may submit a written protest or written cgmmentS regarding this. application and proposal to the Alaska Oil and.Gas Conservation Commission at 333 West7th Avenue, Suite 100; Anchorage, Alaska 99501. Protests'and comments must be received no later than 4:30 pm on May 12, 200, except that i# the Commission decides to hold a putilic hearing protests or comments must be received no later than the conclusion of the May 15„2008, hearing:. If you are a person with a disability who may need special accommodations in order to comment or to attend the public hearing, please contact the Commission`s Special Assistant`Jody Colombie at 793-1221. DanieiT. Seamount,Jr: Chair A17-02814043 Publishetl: April 9; 2008 $~ ~~.. .•~~TA:~ •f ~ .«.~ ~J.a • "• c tom' Ai.,!'; :' 4~~,~~'~ "'~~sDe~':f~ l ~ ADVERTISING INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED /~ 0 02814043 ORDER AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF _ /`1 ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE SEE BOTTOM FOR INVOICE ADDRESS F AOGCC AGENCY CONTACT DATE OF A.O. R 333 West 7~' Avenue. Suite 100 ° Anch~raLle. AK 995(11 PHONE PCN M 907-793-1238 DATES ADVERTISEMENT REQUIRED: o Anchorage Daily News Apri19 2008 , PO B ox 149001 L Anchora e AK 99514 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN g ~ ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Account # STOF0330 AFFIDAVIT OF PU6 LICATION United States DfAmerica REMINDER State of ss INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER. division. A CERTIFIED COPY OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMITTED WITH THE INVOICE. Before me, the undersigned, a notary public this day personally appeared ATTACH PROOF OF PUBLICATION HERE. 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 2007, and thereafter for consecutive days, the last publication appearing on the day of , 2007, 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 2007, Notary public for state of My commission expires Page 1 of 1 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Tuesday, April 08, 2008 1:41 PM Subject: Public Notice Qannik CO and AIO Attachments: Qannik Pool and AIO Public Notice.pdf BCC:'Arthur C Saltmarsh'; Birnbaum, Alan J (LAW); 'Catherine P Foerster'; 'Charles M Scheve ; 'Chasity R Smith'; 'Christine R Mahnken'; 'Cynthia B Mciver'; 'Daniel T Seamount JR'; 'Elaine M Johnson'; 'Howard D Okland'; 'James B Regg'; 'Jeffery B. Jones'; 'John H Crisp'; 'John K. Norman'; Latham, Tanya M (LAW); 'Louis R Grimaldi'; 'mail=linda_laasch@admin.state.ak.us'; 'Maria Pasqual'; 'Robert C Noble JR'; 'Robert J Fleckenstein'; Roby, David S (DOA); 'Stephen E Mcmains'; 'Stephen F Davies'; `Thomas E Maunder'; 'Trade Paladijczuk (tracie~aladijczuk@admin.state.ak.us)'; Williamson, Mary J (DOA); Joseph Longo; Maurizio Grandi; Tom Gennings; 'Aleutians East Borough'; 'Anna Raff ; Arion, Teri A (DNR); 'Arthur Copoulos'; 'Barbara F Fullmer'; 'bbritch'; 'Bill Walker'; 'Brad McKim'; 'Brandon Gagnon'; 'Brian Gillespie'; 'Brian Havelock'; 'Brit Lively'; 'Bruce Webb'; 'buonoj e'; 'Cammy Taylor'; 'Cande.Brandow'; 'carol Smyth'; 'Cary Carrigan'; caunderwood@marathonoil.com; 'Charles O'Donnell'; 'Chris Gay'; 'Christian Gou-Leonhardt'; 'Cliff Posey'; 'Dan Bross'; 'dapa'; 'Daryl J. Kleppin'; 'David Brown'; 'David Hall'; David House; 'David L Boelens'; 'David Steingreaber'; 'ddonkel'; 'Deanna Gamble'; 'Deborah J. Jones'; 'doug_schultze ; 'Eric Lidji '; 'Evan Harness'; 'eyancy'; 'foms2@mtaonline.net'; 'Francis S. Sommer'; 'Fred Steece'; 'Garland Robinson'; 'Gary Laughlin'; 'Gary Rogers'; 'Gary Schultz'; 'ghammons'; 'Gordon Pospisil'; Gould, Greg M (DEC); 'Gregg Nady'; 'gregory micallef ; 'gspfoff ; 'Hank Alford'; 'Harry Engel'; 'jah'; 'James Scherr'; 'Janet D. Platt'; 'jejones'; 'Jerry McCutcheon'; 'Jim Arlington'; 'Jim White'; 'Jim Winegarner'; 'Joe Nicks'; 'John Garing'; 'John S. Haworth'; 'John Spain'; 'John Tower'; 'John W Katz'; johnny.aiken@north-slope.org; 'Jon Goltz'; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles ; knelson@petroleumnews.com; 'Krissell Crandall'; 'Kristin Dirks'; 'Laura Silliphant'; 'Lois'; 'Lynnda Kahn'; 'mail=akpratts@acsalaska.net'; 'mail=Crockett@aoga.org'; 'mail=fours@mtaonline.net'; 'Mark Dalton'; 'Mark Hanley'; 'Mark Kovac'; 'Mark P. Worcester'; 'Marguerite kremer'; 'marty'r 'Matt Rader'; 'mckay'; 'Meghan Powell'; 'Mike Bill'; 'Mike Mason'; 'Mikel Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'Nick W. Glover'; NSK Problem Well Supv; NSU, ADW Well Integrity Engineer; 'Patty Alfaro'; 'Paul Decker'; 'Paul Winslow'; Pierce, Sandra M (DNR); 'Randall Kanady'; 'Randy L. Skillern'; 'rcrotty'; Rice, Cody J (DNR); 'rmclean'; 'Rob McWhorter '; rob.g.dragnich@exxonmobil.com; 'Robert Campbell'; 'Robert Fowler'; 'Robert Province'; 'Roger Belman'; 'Rudy Brueggeman'; 'Scott Cranswick'; 'Shannon Donnelly'; 'Sharmaine Copeland'; 'Sondra Stewman'; 'Sonja Frankllin'; 'Stan Porhola'; 'stanekj'; 'Steve Lambert'; 'Steve Moothart'; 'Steven R. Rossberg'; 'tablerk'; 'Tamera Sheffield'; 'Temple Davidson'; 'Terrie Hubble'; 'Tim Lawlor'; 'Todd Durkee'; Tony Hopfinger; 'trmjrl'; 'Walter Featherly'; 'Walter Quay'; 'Wayne Rancier' Attachments:Qannik Pool and AIO Public Notice.pdf; Jody Colombie Special Assistant Alaska Oil & Gas Conservation Commission Direct: 907-793-1221 Fax: 907-276-7542 *Note new email address 4/8/2008 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 Baker Oil Tools 4730 Business Park Blvd., #44 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 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 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle, WA 98119-3960 Schlumberger Drilling and Measurements 2525 Gambell Street #400 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 Cindi Walker 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 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 /s/g ~G ~~ ConocoPhillips Alaska, Inc. 700 G. ST. ANCHOR,4GE, ALASKA 99510-0360 Lamont Frazer North Slope Operations and Development, ATO 1754 Telephone 907- 263-4530 Facsimile 907- 265-1515 E-mail Iamont.c.frazerQconocophillips. com April 03, 2008 Commissioner Dan Seamount, Chairman Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Re: Qannik Oil Pool Dear Commissioner Seamount: L~ RECEtVEI~ APR 0 3 2008 Alaska O+i & Gas Cons. Commission Anchorage ConocoPhillips Alaska, Inc. (COP), in its capacity as operator of the Colville River Unit, submits this letter as an application for the Alaska Oil and Gas Conservation Commission to classify the Qannik oil accumulation in the Colville River Unit as an oil pool and establish pool rules for development of said oil pool pursuant to 20 AAC 25.520. Supporting documentation, which includes both public and confidential material for the Commission, is attached. The applicant requests a hearing at the earliest possible date in accordance with 20 AAC 25.540. COP briefed Commission Staff on Qannik during a January 16, 2008 meeting and is prepared to provide additional technical information supporting establishment of an oil pool at the commission staff's convenience. Please contact me if you have any questions regarding this application. .~ Sincerely, ~e''L Lamont Frazer Qannik Coordinator Cc: Mr. Kim Bowen General Manager -Alaska Anadarko Petroleum Corporation 3201 C Street, Suite 603 Anchorage, AK 99503 • April 03, 2008 Commissioner Dan Seamount Re: Qannik Oil Pool Bcc: Dora Soria ATO-1468 Chris Wilson ATO-1770 C] • ICJ Information for the Alaska Oil and Gas Conservation Commission for the Classification and Rules for the Proposed Qannik Oil Pool Colville River Field ConocoPhillips Alaska, Inc Anadarko Petroleum Corporation Information for the Proposed Qannik Oil Pool Colville River Field Table of Contents 1.0 Introduction 2.0 Reservoir Structure and Trap 3.0 Fluid Descriptions 4.0 Drilling, Completion, and Well Operations 4.1 DRILLING PLAN 4.2 DRILLING AND LOGGING 4.3 WELL SPACING 4.4 WELL WORK PLAN 4.5 OPEN ANNULI IN EXISTING WELLS 5.0 Facilities Scope and Design 5.1 INFRASTRUCTURE REQUIREMENT DEFINITION 5.2 SITE SELECTION AND EVALUATION 6.0 Operating Agreements and Production Allocation 7.0 Proposed Conservation Order List of Fiaures Apri13, 2008 1 3 4 5 5 8 9 9 10 11 11 11 12 13 Figure 1-1 Proposed Area for Qannik Pool Rules .....................................................2 Figure 4-1 Spider Map of Horizontal Well Program (10,000-foot Departure Circle) ..5 Figure 4-2 Proposed Qannik Producer Well Schematic ............................................6 Figure 4-3 Annular Disposal Interval Type Log: Bergschrund 1 ...............................7 Figure 4-4 Qannik and West Sak Well Depth versus Departure ...............................8 Pagei Information for the Proposed Qannik Oil Pool April 3, 2008 Colville River Field 1.0 INTRODUCTION This document includes information for the Alaska Oil and Gas Conservation Commission to classify the Qannik reservoir in the Colville River Field as an oil pool, and to prescribe rules to govern development of the proposed oil pool in accordance with 20 AAC 25.520. The proposed Qannik Oil Pool is a Late Cretaceous north-south elongated sandstone deposited in an eastward prograding shallow marine environment that is broadly age equivalent to the Nanushuk Group. The proposed Qannik Oil Pool overlies existing Alpine, Nanuq-Kuparuk, Nanuq-Nanuq Oil, Fiord-Kuparuk and Fiord-Nelchelik Oil Pools. Concurrent with this application, ConocoPhillips Alaska, Inc., 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 authorize waterflood operations for the proposed Qannik Oil Pool. The WIOs plan to form a separate participating area within the CRU for the Qannik Oil Pool. The proposed boundary for the Qannik Pool Rules is shown on Figure 1-1. ConocoPhillips Alaska, Inc. as operator and on behalf of the WIOs, plans to apply to the State of Alaska and Arctic Slope Regional Corporation for the formation of a Qannik Participating Area. Development drilling is scheduled to commence during June 2008 at Drill Site CD2, creating the need to establish pool rules and an area injection order for the proposed oil pool. The project is located in the Colville Delta area. Initial planned Qannik development activities are to develop approximately 5000 acres of reservoir from Drill Site CD2. This would be accomplished by drilling eight new horizontal wells and utilizing the existing Qannik horizontal exploration well (CD2-404). The nine wells-six outboard producers and three inboard water injectors-would have horizontal well lengths ranging from 6000' to 9000'. The planned well spacing averages 3000'. The recovery scheme would involve waterflood from in-board injection wells supplemented with gas cap expansion drive from the east. Ultimate recovery is estimated at 17 MMBO with a range of 11 - 25 MMBO based on - reservoir simulation. Initial production is targeted for August 2008. The peak annual project rate is estimated at 4 MBOPD in 2009 with a corresponding range of 3 - 6 MBOPD. Successful results from this initial efforts will likely lead to expanded development activities at Drill Sites CD2 and CD4. The working interest partners in the project are the same as in the Alpine Oil Pool and Participating Area (i.e., ConocoPhillips Alaska, Inc. with 78% and Anadarko Petroleum Company with 22%). Qannik development will use existing infrastructure to the extent possible. The project expands Drill Site CD2 by 7.5 acres to allow up to 18 new development wells. Drill Site CD2 is located approximately three miles west of the Alpine Central Facility (ACF) and is accessible by an all-season gravel road. The surface production facility design is based on a standard trunk and lateral piping design with five common headers that support the respective well service requirements. These headers include the following: (1) Production, (2) Test, (3) Gas Lift, (4) Arctic Heating Fuel and (5) Water Injection. The Qannik wellhead shelters will contain the instrumentation and control valves needed for remote control of production, testing ~ injection. New Qannik surface facility equipment will include a REIM and chemical injection module. The ACF will process produced fluids. and supply electrical power. Page 1 Information for the Proposed Qannik Oil Pool Colville River Field April 3, 2008 Key milestones targets for the Qannik development project include the following: Conservation & Area Injection Orders Obtained May 2008 Drilling Operations Start June 2008 Facilities Installation Begins February 2008 First Oil July 2008 Drilling Operations End January 2009 Four sections follow this introduction: 1) Reservoir Structure and Trap, 2) Fluid Descriptions, 3) Drilling, Completion, and Well Operations, 4) Facilities Scope and Design, 5) Operating Agreements and Production Allocation, and 6) Proposed Conservation Order. Confidential information for this application is provided separately. a~ ~ I i7 1 tii'M; 17 s 1 8 1 •~ L J I I I ~ ~ _. " vmm' W 8! I - nn r SCALE I x NMILEB wt. •x '•n. 17~ n r ^ C~ 18 16 ~ ~ 1 `., IaY ~ ~ I Ode ~h.a..~~fl. A.~'i~ ~ T 10 6 ~ ,. _ 1 ~I_- _ uc. cn I -1-/ti vA4I!. 1fi~ { ~ ~a 10TjLw(`10 ~~~ (~- (ol/ ~@Z1 ~r~- I 1 F )r r h,~[~A 3Ii11 A~'oaa -( ~ 1 . 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I ,.,..~~, ~~ Qannik Pool ~,i-rOg UPA91901E01 Figure 1-1: Proposed Area for Qannik Pool Rules Page 2 Information for the Proposed Qannik Oil Pool Apri13, 2008 Colville River Field 2.0 RESERVOIR STRUCTURE AND TRAP The Qannik project will develop the Qannik sandstone. The Late Cretaceous Qannik sandstone represents anorth-south elongate sand body that is the shallow marine top-set component of an eastward prograding shelf edge sequence broadly age equivalent to the Nanushuk Group. The proposed Qannik development area is well defined by the Colville and Harrison Bay 3D seismic surveys, and by approximately 130 well penetrations in the CRU. Well log data, conventional core, sidewall cores, and RFT/MDT data were used to determine the reservoir properties. Additionally, a dedicated Qannik interval horizontal well (CD2-404) was completed from the Alpine CD2 pad and production tested for several weeks in 2006. In the CRU, the Qannik sequence is composed of thin marine sands that extend for at least twelve miles parallel to depositional strike (north-south) and six miles in the east-west depositional dip direction. The Qannik sands pinch-out to the west (updip) due to either onlap or truncation. The seismically defined time equivalent shelf-slope break is roughly five miles east of CD2 pad. The Qannik reservoir trap is stratigraphic and contains an oil and gas leg. No oil-water contact has been observed to date. Original oil in place in the nine well area targeted for development is estimated at 79 MMBO. Page 3 Information for the Proposed Qannik Oil Pool Apri13, 2008 Colville River Field 3.0 FLUID DESCRIPTIONS All available Qannik Interval API gravity measurements are summarized in Table 1. Oil properties of crude within the proposed Qannik Oil Pool are provided in Table 2. These properties were characterized from MDT samples obtained from the Nanuq #5 and augmented with recombined surface samples acquired from the CD2-404 flow test. Additional fluid samples are planned to be collected and analysed commensurate with development activities. Water has not been produced from wells in the proposed Qannik Oil Pool, nor have water-oil contacts been observed in the Qannik reservoir. Connate water resistivity was estimated using the same connate water salinity as was used for the Alpine and Fiord reservoirs. This equates to approximately 0.20 ohm-m at reservoir temperature. Salinities in the Colville River Unit were calculated in the Nechelik #1 approximately four miles northeast of the proposed Qannik Oil Pool in zones deeper than the proposed injection zone. 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 five miles south of the proposed Qannik Oil Pool, the Nanuk #2 well produced water from downdip, deep water equivalent Torok Formation sands. From perforations at 7,048 to 7,108 feet MD (approximately 6200' TVDSS), the Nanuk #2 well produced formation water with the composition shown in Table 3. Table 1: Qannik API Gravity Measurements Well Nanuk #5 CD2-404 CD2-11 Nanuk #2 Table 2: Qannik Oil Properties Sample API Gravity MDT 29.9°API Production Test 29.4°API Core Extract 31-32°API MDT 27.2°API Temperature: 89° F Saturation Pressure: 1850 psig Single Phase Compressibility: 8.04 x 10~ /psi (Constant Composition Expansion at Saturation Pressure) Reservoir Fluid Viscosity: 2.0 cp at 1850 psig and 89°F Density of Reservoir Fluid: 0.877 g/cc Differential Vaporization Solution Gas-Oil Ratio: 404 scf/bbl residual oil at 97°F Differential Vaporization Relative Oil Volume: 1.19 bbl /bbl of residual oil at 97°F Table 3: Nanuq #2 Torok Formation Water Component Sodium Potassium Calcium Magnesium Bicarbonate Sulfate Chloride Amount (qpm) 7,000 150 200 0 800 0 10,600 Page 4 Information for the Proposed Qannik Oil Pool April 3, 2008 Colville River Field 4.0 DRILLING, COMPLETION, AND WELL OPERATIONS Nine horizontal wells (six producers and three injectors) are the base plan for the Alpine CD2 Qannik sand development. One of the injectors, CD2-404 was drilled in May 2006 and the test results provided sufficient data to sanction this project. Except for the shallower target depth and slightly larger hole size, the Qannik well designs are almost identical to those being used for the other Alpine CD3/4 satellite developments. The surface and intermediate hole sections will be directionally drilled with water based mud systems and cased. The horizontal intervals will be drilled with a mineral oil based drill-in-fluid (DIF) and completed with slotted liners. The producers will have surface-controlled subsurface safety valves and the injectors will contain adown-hole differential pressure controlled check valve. Surface safety valves are planned for all wells. 4.1 DRILLING PLAN Since 1999 a steady horizontal well drilling program has been conducted at Alpine and its satellite drill sites with 129 horizontal wells completed by year-end 2007. A similar horizontal well design is planned for the Qannik sand development. The wells will be drilled from 20- foot centers on the new CD2 well row with the laterals oriented approximately north-south. parallel. The nine planned Qannik wells are shown overlying the CD2 Alpine sand wells (Figure 4-1 ). 75011]11 ?51875 t5768U 761486 JGS291 J6~M~~M 7]^_~xll ?76706 tR0511 787716 38 5989'_75 CD2-404 Qannik well ® Alpine CD2 Pad 5989245- 5985440 Qannik planned wells 5985JJ0- s981635 5981635 4 © 10,000' radius sm7Rw = ® sm7Rx z s974o2s s9]ao2s \. 597u22n ~. s9m2z6 - 5966) 15 ® 596641 S - ConocoPhillips ~~ I:esling ~ 11 1 Mile • 59Q)p000 i5J873 a5]6R0 761786 165'_91 J6~N 14,. i]?9111 ?h'ISII 787716 ?767'16 s96261 Figure 4-1: Spider Map of Horizontal Well Program (10,000-foot Departure Circle) Page 5 Information for fhe Proposed Qannik Oil Pool April 3, 2008 Colville River Field 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 (10-3/4") is planned at approximately 2400 feet true vertical depth and will be cemented back to surface. Intermediate hole will be drilled into the Qannik sand and production casing (7-5/8") will be cemented with the shoe in the target formation. Production casing will be cemented with sufficient volume to protect any significant hydrocarbon zones. 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 development plan for the proposed Qannik Oil Pool is based on long horizontal laterals of lengths from 6,000 to 9,000 feet. The horizontal section will be drilled with a reservoir drilling fluid and completed with 3%2 inch liner, slotted across sand and blank across any shale intervals. The liner will be tied back to surface with a packer and 3%2 inch tubing (Figure 4-2). Alpine CD2 -Qannik Producer Completion 18"Insulated Conductor to 114' 31/2" Tubing retrievable, surface controlled SSSV at +/- 2450' TVD 10-3/4" 45.5 ppf L-80 BTCM Surtace Casing at +/-2400' TVD, cemented to surface 3-1/2" 9.3 ppf L-80 EUE 8rd Mod. tubing 3-112" GLM w/ 1" valves Production Slick stinger w/ Fluted Pecker VVLEG and Shear sub XN nipple Liner top hanger w/ tieback receptable Reservoir \ r~ 6000 - 9000' MD Horizontal 0' TVD -"--r 7-5/B" 29 ppf L-80 BTC Mod 3-1/2" 9.3 ppf L-80 SLHT liner Production Casing (~ +/.g5° "+/ slots across sand and blank across shale Figure 4-2: Proposed Qannik Producer Well Schematic Page 6 Information for fhe Proposed Qannik Oil Pool Apri13, 2008 Colville River Field Injection wells will have similar completions except for the following: (1) injectors may have 4%2 inch tubing and liner, (2) the upper two gas lift mandrels will be omitted, and (3) a down- hole differential pressure-controlled check valve is planned. Disposal of drilling wastes in annuli of wells with surface casing set below the permafrost will be proposed for Drill Site CD2 in accordance with 20 AAC 25.080. No underground sources of drinking water exist beneath the permafrost in the Colville River Unit area (AOGCC Area Injection Order No. 18B, October 7, 2004.) The proposed annular disposal interval will be the Upper Cretaceous Seabee and Torok Formations (Figure 4-3). °~ ssrvo ~ ~~ Lithology Y .. .. .. . .. . .. O ~. : . . ~ .. ... .~ ~ H Y ~ X00 ... ... ............ ..... .. . SAND AND GRAVEL, ..... ~~~ 7 ~ ~ • • • • • • • • Z ~ am ............ .............. ' ~ ' '~~' ~ a ~ .:..:..:..:.. ..' . .. PERMAFROST ~ . , x_ -- ...~. ~... ~..~ .~..~ .~..~. (1500 ft) N ~ eos .... ............................. ~ .. Q ~ ~ ~•SAND~ N ~ 3 .rte ,:oo .m ,~ LL ~ -I - . SILTSTONE, m ea0 -COAL INTERBEOS- W ° y _ ~ - t~yp - ------ -- UPPER BARRIER ~ = ~ _ ~ - - - - - - - leoo nl zoaa --t ' -+_ N .._ ~_ _ ~ i' -_____-_____ -SNA L_E, VOLC A_NIC ASM _ "_ zxoo '~_ - __-_-_-___-_-__- - ----- ---- ~.... .. xwo C-3 - 0 ~ Ism .'~ -__-~ }. -_ ___ __ __ __-_-- -_ __- __- _ l _ s _ _ _ _ _____________ ~ _ _ •a-- '''~ ~INTERBEDDEO SANDSTONE -_~_ ~ AND SHALE _ mm ~ w ~ __ ___ _ __ ANNULAR DISPOSAL + ozm _ _ _ _ INTERVAL ~, _ _ _ _ _ _ _ ~,= ------------- Itaoonl _~r~ o.m ~ t ~ - - - - . ; - - _~ --~ ism s -~ = -_- -_-- --- -- ------ _-- ~. _ _ _ lBm K _ ~ I3 ~ - - - - - - - - - - - - - - - _ _ _ _ _ _ _ _ _ - asm ~ ~ I __~`____~__~- ~ r _ _ __ -____ _ - ~ ---_-_-- ----- Y 3 _ _ _ O ~ ~s _ _ _ _- -__ - - _ --_ ~ M00 ~ 1 _ __-____-__ ° ~ > ~ -- -_-------_- _ LOWER BARRIER ssm ~ ~ _ - MARINE SHALE'-_ _ (700 R) J ism ~ ~ - -_ -_-_ -- Figure 4-3: Annular Disposal Interval Type Log: Bergschrund 1 This interval contains over 1800 feet of interbedded sandstone and shale and is the horizon utilized when drilling the CD2 Alpine sand wells. Surface casing will be set 10-20 feet above the C-30 marker. The upper barrier is composed of 800 feet of shale and siltstone of the Page 7 Information for the Proposed Qannik Oil Pool Apri13, 2008 Colville River Field 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. 4.2 DRILLING AND LOGGING Preliminary slot assignments and directional plans for the eight planned Qannik wells have been generated. Drilling from 20-foot centers on the new CD2 well row alleviates shallow close approaches with existing Alpine wells and anti-collision scans show no major proximity issues. Assuming conservative build and turn rates of no more than 6 degrees/100 feet, all targets are reached with intermediate hole tangent (sail) angles of 30 - 75 degrees and then building to 90 degrees by production casing depth. The long horizontals will be geo-steered to optimize length in the better quality sand. These preliminary directional profiles were used for well modeling (torque, drag, casing/liner running, hydraulics, hole cleaning) and the results showed no major risks to drilling the wells that have not already been identified and overcome at Alpine or the West Sak shallow sand (3200 foot TVD) development in the Kuparuk field (Figure 4-4). Alpine CD2 Qannik vs. Kuparuk West Sak 1J 0 1,000 -1 J-174 - 1 J-176 ~ ----- 1J-162 1J-180 , -CD2-404 -CD2-468 « 2,000 a m 0 c~ > 3,000 ~ ~---- 4,000 5,000 0 2,000 4,000 8,000 8,000 10,000 12,000 14,000 16,000 18,000 20,000 Unwrapped Horizontal Departure Figure 4-4: Qannik and West Sak Well Depth versus Departure Maintaining horizontal borehole stability may require up to 10 ppg mud, thus managing equivalent circulating density (ECD) to avoid ballooning the formation and mud losses is key to completing the planned horizontal lengths. Drilling a 6-3/4" hole and weighting the mud Page 8 Information for the Pro osed Qannik Oil Pool A ri13, 2008 p p Colville River Field with micronized barite allows lower rheology for a given fluid density and modeling indicates the desired depths can be achieved. Geo-steering is critical to maximizing drilled footage in sand and recent experience gained with rotary steerable systems, including inclination and gamma at bit can be employed. Drilling and completing the Qannik wells is possible with current designs and drilling practices. The requirements described in 20 AAC 25.050(b) are requested to be waived for the proposed Qannik 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 for each well includes resistivity and gamma ray (GR) logs from surface casing shoe to total depth (TD). These logs can be obtained from measure-while- drilling tools in the drill string bottom-hole assembly. 4.3 WELL SPACING Well spacing requirements under 20 AAC 25.055 should be waived because the horizontal well development of the proposed Qannik Oil Pool will yield greater recovery than a conventional well development with a minimum spacing rule. Vertical wells would flow at lower rates relative to horizontal wells and would therefore be prone to more wax and hydrate deposition problems when producing from the Qannik Oil Pool. These types of deposition problems would ultimately lead to a lower ultimate resource recovery. Imposing a limit on the minimum interwell spacing, either heel to toe distance between horizontal wells, or lateral spacing between horizontal wells will not achieve conservation objectives. Very small heel to toe distance in the planned horizontal line drive flood would be similar to longer horizontal production or injection holes. Very small heel to toe distance or longer production/injection holes will not promote waste. Reservoir simulation indicates that longer horizontal wells will recover more oil; therefore, a minimum distance between development wells should not be imposed. 4.4 WELL WORK PLAN Well service operations are planned in accordance with 20 AAC 25 Article 03. Drill Site CD2 has year-round road access to the ACF. Routine reservoir surveillance activities including pressure measurement and production and injection profiles would 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. Insulated tubing centralizers are planned to minimize potential deposition of wax or hydrate. Remedial wax and hydrate management are planned with a combination of slickline and hot oil treatments. The subsurface safety valve will also be set deeper (2400 feet true vertical depth versus 2000 feet true vertical depth on Alpine wells). This provides the option to install a coiled tubing heater string of sufficient length inside the production tubing above the SSSV if additional wax/hydrate mitigation is needed. Page 9 Information for the Proposed Qannik Oil Pool April 3, 2008 Colville River Field 4.5 OPEN ANNULI IN EXISTING WELLS The Qannik interval was not considered a significant hydrocarbon bearing interval and was therefore not cemented during initial Colville River Field development efforts. However, improvements in horizontal drilling technology coupled with increased oil prices have caused Qannik to now be considered a viable development opportunity. Although typical Western North Slope depletion plans involve alternating water and miscible gas injection to maximize recovery, miscible gas injection is not planned for Qannik. The potential for injected gas to migrate through open annuli has resulted in water injection being selected as the only means of maintaining pressure support and maximizing recovery. The primary concern involves cross-flowing injected fluids from the Qannik reservoir into either the C-30 annular disposal interval, or the Lower K2 interval, via the open annuli of existing CD2 Alpine wells. The potential for this type of cross-flow is most prevalent in the near wellbore region of Qannik injectors, where Qannik reservoir pressures are at their highest. Although the cross-flow would have no appreciable impact on ultimate recovery, it would make the planned waterflood less efficient. Cross-flow is not expected to occur due to three main factors: (1) 1650' TVD of annulus is filled with dehydrated drilling mud, (2) shales likely collapsed along the casing from long-term exposure to water based drilling mud and (3) mud is in the hole, so leak-off pressure would need to be exceeded to initiate flow from Qannik to the C-30 or Lower K-2. Remedial zonal isolation techniques for CD-2 wells were .considered prior to initiating a waterflood, but have significant disadvantages. Potential remediation techniques include (1) block squeezing the Qannik interval in Alpine CD2 wells, (2) Arctic Packing, (3) injecting water conformance and/or matrix sealants, and (4) top cement squeezing the surface casing shoe to C-30. Each method of remediation listed eliminates any monitoring options to further understand cross-flow issues and each is unlikely to eliminate potential problems. Block squeezing the Qannik interval in existing Alpine wells is not considered a viable option as it takes wells with no mechanical integrity problems and introduces potential casing leak points. A comprehensive monitoring plan is incorporated in the Qannik development plan to address the Alpine CD2 well open annuli situation. The monitoring plan includes the installation of wireless pressure transducers on the outer annuli of the 19 Alpine CD-2 wells that fall within one quarter mile of planned Qannik injectors. This would allow continuous monitoring of the outer annuli in order to set pressure safety alarms in the Setcim SCADA system to alert operators to review well activities that may explain observed pressure changes. In addition, a quarterly review of pressure trends would be conducted in these Alpine CD2 wells with wireless pressure transducers. Unexplainable pressure changes would trigger a diagnostic process to identify the next course of action, whether it is reduced injection in offset Qannik wells, down-hole diagnostic services, or potential remediation of CD-2 wells. Page 10 Information for the Proposed Qannik Oil Pool April 3, 2008 Colville River Field 5.0 FACILITIES SCOPE AND DESIGN Qannik development will use existing infrastructure to the extent possible. Qannik oil resources would be developed from a 7.5 acre pad expansion of Drill Site CD2. This would provide space for up to a total of 18 additional wells with 20' centers (i.e., 8 new Qannik wells planned for '08, 3 potential upside Qannik wells drilled to the east, and 7 future wells for other targets). Drill Site CD2 is located approximately three miles west of the Alpine Central Facility (ACF) and is accessible by an all-season gravel road. The surface production facility design is based on a standard trunk and lateral piping design with five common headers that support the respective well service requirements. These headers include the following: (1) production, (2) test, (3) gas lift, (4) diesel and (5) water injection. The Qannik wellhead shelters will contain the instrumentation and control valves needed for remote control of production, testing and injection. New Qannik surface facility equipment will include a Remote Electrical and Instrumentation Module (REIM) and chemical injection module. The ACF will process produced fluids and supply electrical power. Unitized substances produced from the proposed Qannik Oil Pool will be commingled on the surface at Drill Site CD2 and the ACF with substances from existing Colville River Unit oil pools. Qannik production will be allocated based on periodic well tests and producing conditions as detailed in the Qannik Pool Rules. Water injection is scheduled to begin in during the third quarter of 2008. The injection may consist of either sea water or produced water from other oil pools within the Colville River Unit. Surface facilities will be installed to deliver and meter water at each injection well. Drill Site CD2 surface facility expansion details are provided below. • 7.5 acre gravel expansion • Production, test, artificial lift gas injection, diesel ,and water injection headers • Tie-in slots for 18 wells with wellhead shelters • Wellhead hydraulic panels (centralized, located in the Chemical Injection Module) • REIM with transformers, switch gear, and telecommunications • Chemical injection and storage 5.1 INFRASTRUCTURE REQUIREMENT DEFINITION The Qannik Development was designed to maximize use of existing facilities and infrastructure. By virtue of locating this development adjacent to the existing CD-2 Drillsite, no new roads, pipelines, powerlines or Fiber Optic cables are required. 5.2 SITE SELECTION AND EVALUATION CD-2 was selected as the site for this Qannik development based on its physical location, and because it allowed maximum use of existing facilities. Expanding the pad to the west from the edge of CD-2 minimized the environmental impact and allowed access to the Qannik Targets with the fewest close crossings with the existing 60 wells at CD-2. Tying into the existing CD-2 piperack allowed Qannik to be developed without constructing a new emergency shutdown module, production heater, and test separator. Page 11 1. Information for the Proposed Qannik Oil Pool Colville River Field • April 3, 2008 6.0 OPERATING AGREEMENTS AND PRODUCTION ALLOCATION All lands within the anticipated Qannik Participating Area (PA) are leased within the CRU. All Qannik PA leases have the same working interest as the CRU Alpine Field (78 percent CPAI and 22 percent Anadarko Petroleum Company). The equity re-determination schedule is defined by the Colville River Unit Agreement (CRUA). The entirety of the area covered by the anticipated Qannik PA became subject to the CRUA in March 1998 when the State and ASRC approved the CRU. The planned Qannik development area is also subject to the Colville River Unit Operating Agreement (CRUOA). The provisions of the CRUOA and the CRUA will control the development of the proposed Qannik Oil Pool. Development of the proposed Qannik Oil Pool is planned with development wells solely dedicated to a single pool with no subsurface commingling. Unitized substances produced from the proposed Qannik Oil Pool would be commingled on the surface with substances from existing oil pools within the CRU. Production would be allocated to each producing well using the same process regardless of the pool. The allocation method presently used for oil pools within the CRU would be adopted for the Qannik Oil Pool. A description of this methodology follows. Production and injection allocation is a daily process used to balance production and injection from individual wells to total metered CRU values. 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 ACF. 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: Vt; = Theoretical volume for well i VtcRU = Total theoretical volume for CRU VtCRU = Vt~ + V,~ + ... V~, Vass~9ate = Aggregate volume transferred (or used for injection, fuel, etc.) for the CRU AF = Allocation factor AF = Va99~9ate ~ VtCRU VA; = Allocated volume for well i VA; = AF Vt; Page 12 Information for the Proposed Qannik Oil Pool April 3, 2008 Colville River Field 7.0 PROPOSED CONSERVATION ORDER It is ordered that the rules hereinafter set forth, in addition to the statewide requirements under 20 AAC 25, apply to the following affected area referred to in this order. Umiat Meridian T11N R4E Sections 1-4, 9-16, 21-28, 33-36 T11 N R5E Sections 4-9, 16-21, 28-33 T12N R4E Sections 1-4, 9-16, 21-28, 33-36 T12N R5E Sections 4-9, 16-21, 28-33 T10N R4E Sections 1-4 T10N R5E Sections 4-6 Ruie 1. Field and Poo! Names The field is the Colville River Field and the pool is the Qannik Oil Pool. Rule 2. Pool Definitions The Qannik Oil Pool is defined as the accumulation of oil and gas common to and correlating to the stratigraphic interval between 6086 and 6249 feet measured depth in the CD2-11 well, and its lateral equivalents. Rule 3. Well Spacing The requirements of 20 AAC 25.055 are waived for development wells in the Qannik Oil Pool. Without prior notification, development wells may not be completed closer than 500 feet to an external boundary where working interest and land ownership changes. Rule 4. Casing and Cementing Practices (a.) After drilling no more than 50 feet below a casing shoe set in the Qannik Oil Pool, a formation integrity test must be conducted. The test must indicate sufficient pressure exists before drilling operations can be continued. (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.) Production casing cement volumes will be sufficient to place cement a minimum of 500 feet measured depth above the top of the Qannik Oil Pool in all wellbores. (d.) 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). (e.) In lieu of the requirements of 20 AAC 25.071(a), petrophysical logs obtained from nearby exploration wells or wells drilled to other oil pools from the drilling pad may be submitted to meet these requirements. The Commission may, in its discretion, require additional wells on a pad to be logged and specify the log type. .Rule 5 Injection Well Completion (a.) To facilitate wireline access, packers in injection wells may be located more than 200 feet measured depth above the top of the injection zone; however, packers must not be located above the confining zone. In cases where the distance is more than 200 feet, the '..production casing cement volume should be sufficient to place cement a minimum of 300 feet measured depth above the planned packer depth. Page 13 • Information for the Proposed Qannik Oil Pool Colville River Field • April 3, 2008 (b.) An approved injection order is required prior to commencement of injection in this pool. Rule 6. Automatic Shut-in Equipment (a.) All production wells must be equipped with afail-safe automatic surface safety valve (SSV) and asurface-controlled subsurface safety valve (SSSV). (b.) Injection 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. Asubsurface-controlled injection valve 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. Sufficient notice must be given so that a representative of the Commission can witness the tests, if desired. (d.) Subsurface safety valves may only be removed after demonstrating to the Commission that the well is not capable of unassisted flow of hydrocarbons. Rule 7. Common Production Facilities and Surface Commingling (a.) Production from the Qannik Oil Pool may be commingled on the surface prior to custody transfer. (b.) Allocation factors for produced fluids will be based on well tests, daily well allocation and total production as measured in the CRU ACF. (c.) Each producing well must be tested a minimum of twice per month. (d.) The Commission may require more frequent or longer tests if 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 8. Reservoir Pressure Monitoring (a.) A bottom-hole pressure survey shall be taken on each well prior to initial sustained production or injection. (b.) The Operator shall obtain pressure surveys as needed to effectively manage hydrocarbon recovery processes subject to an annual plan outlined in paragraph (e) of this rule. (c.) The reservoir pressure datum will be 4,050 feet TVDss for the Qannik Oil Pool. (d.) Pressure surveys may consist of stabilized static bottomhole pressure measurements, pressure fall-off, pressure buildup, multi-rate tests, drill stem tests, and 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. Page 14 Information for the Proposed Qannik Oil Pool April 3, 2008 Colville River Field Rule 9. Gas-Oil Ratio Exemption Wells producing from the Qannik Oil Pool are exempt from the gas-oil ratio limits of 20 AAC 25.240(a) in accordance with the provisions of 20 AAC 25.240(b). Rule 10 Annual Reservoir Review. An annual report must be filed on or before April 1 of each year. The report shall include an overview of reservoir performance, future development and reservoir depletion plans, and surveillance information for the prior calendar year. Report details shall include the following: (a.) Reservoir pressure maps at datum; (b.) Summary and analysis of reservoir pressure surveys; (c.) Reservoir pressure estimates; (d.) Results and, where appropriate, analysis of production, temperature, tracer surveys, observation well surveys, and any other special monitoring surveys; (e.) Estimates of yearly production and the reservoir voidage balance of injection and withdrawals at standard and reservoir conditions; (f.) Progress of plans and tests to expand the productive limits of the pool; and (g.) Results of surface safety valve testing. Rule 11. Well Mechanical Integrity and Annulus Pressures (a.) The operator shall conduct and document a pressure test of tublars and completion equipment in each development well at the time of installation or replacement that is sufficient to demonstrate that planned well operations will not result in failure of well integrity, uncontrolled release of fluid or pressure, or threat to human safety. (b.) The operator shall monitor each development well daily to check for sustained pressure, unless prevented from doing so by extreme weather conditions, emergency situations, or similar unavoidable circumstances. Monitoring results shall be made available for AOGCC inspection. (c.) The operator shall notify the AOGCC within three working days after the operator identifies a well as having (i) sustained inner annulus pressure that exceeds 2000 psig or (ii) sustained outer annulus pressure that exceeds 1000 psig. (d.) The Commission may require the operator to submit in an Application for Sundry Approvals (Form 10-403), a proposal for corrective action or increased surveillance for any development well having sustained pressure that exceeds a limit set out in paragraph "c" of this rule. The Commission may approve the operator's proposal or may require other corrective action or surveillance. The Commission may require that corrective action be verified by mechanical integrity testing or other Commission approved diagnostic tests. The operator shall give the Commission sufficient notice of the testing schedule to allow the Commission to witness the tests. (e.) If the operator identifies sustained pressure in the inner annulus of a development well that exceeds 45% of the burst pressure rating of the well's production casing for inner annulus pressure, or sustained pressure in the outer annulus that exceeds 45% of the burst pressure rating of the well's surface casing for outer annulus pressure, the operator shall immediately notify the Commission and take corrective action. Unless well conditions require the operator to take emergency corrective action before Commission approval can be obtained, the operator shall submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action. The Commission may approve the operator's proposal or may require other corrective action. The Commission may also require that corrective action be verified by mechanical integrity testing or other Commission approved diagnostic tests. The operator shall give the Commission sufficient notice of the testing schedule to allow the Commission to witness the tests. (f.) Except as otherwise approved by the AOGCC under paragraph "d" or "e" of this rule, before ashut-in well is placed in service, any annulus pressure must be relieved to a Page 15 • Information for the Proposed Qannik Oil Pool Colville River Field Apri13, 2008 sufficient degree that (i) the inner annulus pressure at operating temperature will be below 2000 psig, and (ii) the outer annulus pressure at operating temperature will be below 1000 psig. However, a well that is subject to paragraph "c", but not paragraph "e", of this rule may reach an annulus pressure at operating temperature that is described in the operator's notification to the AOGCC under paragraph "c", unless the AOGCC prescribes a different limit. Rule 12 Administrative Action Unless notice and public hearing are otherwise required, the Commission may administratively waive the requirements of any rule stated above or administratively amend any rule as long as the change does not promote waste or jeopardize correlative rights, is based upon sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater. Page 16