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Home My WebLink AboutCO 639 • Pool Rules Nikaitchuq CO 639 1. August 18, 2010 ENI Pool Rules Application (Exhibits A -P Confidential) 2. August 26, 2010 Notice of Hearing, Affidavit of Publication, bulk mail list, email list 3. September 15, 2010 Emails requesting copies of ENI Pool Rules Application 4. September 29, 2010 Public Hearing Transcript 5. Email from Robert Province re: ENI Pool Rules Application 6. October 24, 2010 Application for Qualification of a Multiphase Metering System (639.001) 7. January 21, 2011 Email from BP Krissell Crandall Requesting ENI Application 8. March 23, 2012 ENI email request re: surface casing setting requirement (CO 639.002) Pool Rules Nikaitchuq STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7 th Avenue, Suite 100 Anchorage Alaska 99501 Re: THE APPLICATION OF Eni US Operating ) Docket CO -10 -17 Company, Inc. for an order for classification ) Conservation Order No. 639 of a new oil pool and to prescribe pool rules ) for development of the Nikaitchuq Schrader ) Nikaitchuq Field Bluff Oil Pool within the Nikaitchuq Field, ) Nikaitchuq Unit Nikaitchuq Unit, East Harrison Bay, ) Nikaitchuq Schrader Bluff Oil Pool Beaufort Sea, Alaska ) November 19, 2010 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 19th day of November, 2010. BY DIRECTION OF THE COMMISSION 1 i Jody ombie pecial Assistant to the Commission ! • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7"' Avenue, Suite 100 Anchorage Alaska 99501 Re: THE APPLICATION OF Eni US Operating ) Docket CO -10 -17 Company, Inc. for an order for ) Conservation Order No. 639 classification of a new oil pool and to ) prescribe pool rules for development of the ) Nikaitchuq Field Nikaitchuq Schrader Bluff Oil Pool within ) Nikaitchuq Unit the Nikaitchuq Field, Nikaitchuq Unit, East ) Nikaitchuq Schrader Bluff Oil Harrison Bay, Beaufort Sea, Alaska ) Pool November 19, 2010 IT APPEARING THAT: 1. By application dated August 18, 2010, Eni US Operating Company, Inc. (Eni), in its capacity as operator of the Nikaitchuq Unit on behalf of Eni Petroleum US LLC, the 100% working interest owner, requests an order defining a new oil pool, the Nikaitchuq Schrader Bluff Oil Pool, within the Nikaitchuq Unit and prescribing rules governing the development and operation of that pool. 2. A notice of a public hearing was published August 27, 2010 in the ANCHORAGE DAILY NEWS, on the State of Alaska's Online Public Notice Web site, and on the Commission's Internet website. 3. The Commission held a public hearing on the pool rules application on September 29, 2010. 4. At the conclusion of the hearing, the record was held open until October 8, 2010 to allow Eni to submit additional information requested by the Commission. 5. On October 8, 2010, Eni submitted the requested information and the record closed. FINDINGS: 1. Operator Eni is the operator of the leases in the Affected Area, which is defined below. 2. Affected Area The Affected Area lies offshore in East Harrison Bay, Beaufort Sea, northwest of Oliktok Point, within the Nikaitchuq Unit (see Figure 1, below). The Nikaitchuq Schrader Bluff Oil Pool will be developed initially from the onshore Oliktok Point Pad Drill Site (OPP), which is located in Section 5, Township (T) 13N, Range (R) 09E, Umiat Meridian (UM). Eni's future development plans include construction of an offshore gravel drilling island in about six feet of water near Spy Island. Conservation Order No. 639 • Page 2 November 19, 2010 NIKAITCHUQ UNIT TUVAAQ ST 1 NIKAITCHUQ 1 NIKAITCHUQ 4 NI ITCHUQ 2 . Spy Island NIKAITCHU 3 KIGUN 1 OP03 P05 Simpson t, OLIKTOK PT I -2 Lagoon OP26 DSP02 East HCl riso 1 BC[ v OLIKTOK PT 1 -1 K OPP 1:30000 iktok Poi t Figure 1. Proposed Affected Area for Nikaitchuq Schrader Bluff Oil Pool' (highlighted with yellow) 3. Owners and Landowners Eni Petroleum US LLC is 100% working interest owner and the State of Alaska (State), Department of Natural Resources is the landowner of the Affected Area, which encompasses the Nikaitchuq Unit. 4. Exploration and Delineation History Eni drilled the Nikaitchuq No. 1 discovery well from a surface location in Section 16 to a bottom hole location in Section 9 of T14N, R09E, UM during 2004. The discovery was confirmed by the Nikaitchuq No. 2 exploratory well, also drilled in 2004. To date, nine wells have penetrated the Nikaitchuq reservoir within the Nikaitchuq Unit. Two- and three - dimensional seismic survey and well data have been used to determine the geologic structure and reservoir distribution of the Nikaitchuq Schrader Bluff Oil Pool. Well log data, conventional and sidewall core data, Modular Formation Dynamics Tester data, and production test data were used to establish reservoir and fluid properties for the pool. This map is for illustration purposes only. Refer to the legal description for the precise representation of the proposed Nikaitchuq Oil Pool. Nikaitchuq Unit outline from AK Division of Oil and Gas, Nikaitchuq Unit Map, published June 15, 2010. Conservation Order No. 639 0 • Page 3 November 19, 2010 Correlation Depth Resis GR(DGR) <TVD SEDP API 250 12 OHW 200 SP(WA) TVDSS> SESP 150 50 D.2 OHMvI 200 TVD Measured <MD depth TVDSS 3400 3300 -3300 3500 3600 -3500 `N" sand � Nikaitchuq Schrader Bluff 3700 3600 Oil Pool -3600 1 3800 3700 -3700 3900 3800 -3800 4000 -3900 Figure 2. Kigun No. 1— Type Well Log for Nikaitchuq Schrader Bluff Oil Pool 'Figure 2 is for illustration purposes only. Refer to the Electromagnetic Wave Resistivity (EWR) well log measurements recorded in well Kigun No. 1 exploratory well for the precise representation of the proposed Nikaitchuq Schrader Bluff Oil Pool. The horizontal grid lines in this figure represent increments of five feet true vertical depth subsea. The acronym TVDSS refers to true vertical depth subsea (true vertical depth below sea level). Conservation Order No. 639 • Page 4 November 19, 2010 5. Pool Identification The proposed Nikaitchuq Schrader Bluff Oil Pool is the accumulation of hydrocarbons common to, and correlating with, the interval between the measured depths of 3,530 and 3,867 feet in exploratory well Kigun No. 1 (see Figure 2, above). 6. Geology: a. Stratig_raphy The Nikaitchuq Schrader Bluff Oil Pool encompasses (in ascending order) the informally named "OA" and "N" sands of the late Cretaceous -aged Schrader Bluff Formation. In exploratory well Kigun No. 1, the OA sand lies between 3,780 and 3,822 feet and the N sand occupies the interval from 3,627 to 3,663 feet. These sediments consist of laminated sandstones and siltstones deposited as marine shelfal lobes within a foreland basin. They were sourced from the southwest, where the Schrader Bluff Formation interfingers with the marginal marine to non -marine sediments of the Prince Creek Formation. Four distinct lobe deposits are currently interpreted by the operator, and these lobes are separated by layers of siltstone, calcite- cemented siltstone, or mudstone. The OA and N sands appear to persist throughout the Nikaitchuq Unit. Within the Nikaitchuq Unit, reservoir sandstones occurring in the proposed Nikaitchuq Schrader Bluff Oil Pool are typically fine- to very fine - grained and lithic- rich. Gross thickness for the OA sand ranges from 30 to 40 true vertical feet. Porosity ranges from 25% to 35 %, permeability ranges from 100 to 600 millidarcies, and water saturation ranges from 23% to 45 %, with 45% likely representing a transition zone near the oil -water contact (see Reservoir Fluid Contacts, below). Properties of the N sand reservoir are less well understood at present: porosity ranges from 23% to 33 %, and water saturation ranges from 13% to 22 %. b. Structure Within the proposed development area, the structure of the proposed Nikaitchuq Schrader Bluff Oil Pool forms a monocline that dips gently toward the northeast and is cut by numerous, northwest - trending, normal faults that have vertical displacements ranging up to 80 feet. Within the Nikaitchuq Unit, the top of the pool lies between about -3,000 and -5,000 feet true vertical depth below sea level (true vertical depth subsea, or TVDSS c. Trap Configuration ation Well log and seismic information indicate that the Nikaitchuq Schrader Bluff Oil Pool accumulation is trapped by both structural and stratigraphic elements. The Nikaitchuq reservoir sandstones appear to undergo a facies change toward the southwest, becoming shale. To the north and northeast, structural dip and diminishing sand content in the sediments control oil accumulation extent. To the southeast, the Nikaitchuq structure and the OA and N sands appear to continue beyond the Nikaitchuq Unit boundary toward the Milne Point Unit. d. Confining Intervals The top confining interval for the Nikaitchuq Schrader Bluff Oil Pool is formed by 50 to 100 true vertical feet of shale between the N sand and the overlying Lower Ugnu sands. A shaley layer ranging from 50 to 150 true vertical feet thick separates the N -sands reservoirs from the underlying OA Sand. The OA 3 Depths presented herein represent measured depths unless otherwise stated. 4 To avoid confusion, when depths presented in the text represent true vertical depth subsea, the footage will be preceded by a minus sign and followed by the acronym TVDSS (e.g., -3,000 feet TVDSS). Conservation Order No. 639 Page 5 November 19, 2010 sand is underlain by about 2,000 true vertical feet of Canning /Hue shale and siltstone. e. Reservoir Compartmentalization The Nikaitchuq Schrader Bluff Oil Pool reservoir is likely separated into compartments based on the lobate nature of the reservoir sandstones the intervening iltstone and mudstone layers, and faults having g Y g displacements that exceed the thickness of the OA and N reservoir strata. £ Permafrost Within the proposed current development area, the base of permafrost is interpreted to lie between about -1,800 and -1,900 feet TVDSS. 7. Reservoir Fluid Contacts In the OA sand, an oil -water contact is estimated to lie at about -4,177 feet TVDSS in the Nikaitchuq No. 2 well. The depth of the oil -water contact in the N sand reservoirs is less certain, lying somewhere between the deepest - known -oil depth of -3,643 feet TVDSS in well Oliktok Point No. I -1 and the shallowest - known -water depth of -3,949 feet TVDSS in well Nikaitchuq No. 4. At present, there is no evidence of different oil -water contacts within separate reservoir compartments. 8. Reservoir Fluid Properties Oil samples recovered from the Nikaitchuq No. 4, Kigun No. 1, Oliktok Point No. I -1, and Oliktok Point No. I -2 exploratory wells measure between 16° and 19° API gravity, with viscosity ranging from about 100 to 200 centipoise. The solution gas -oil ratio (GOR) measures from 80 to 140 standard cubic feet per stock tank barrel, and the bubble point pressure ranges from about 1,150 psia in the reservoir compartment containing Oliktok Point No. I -1 to about 750 psia in the compartment containing Oliktok Point No. I -2. Initial Nikaitchuq reservoir pressure is about 1,700 psi at a depth of -3,760 feet TVDSS in Kigun No. 1 and Oliktok Point No. I -1. The bubble point pressures of the reservoir compartments vary between 750 and 1,150 psi. Reservoir temperature is about 80° F. 9. In -Place and Recoverable Oil Volumes and Production Rates Hydrocarbon Volume (MMSTB) Original Oil in Place (OOIP) — OA Sand 800-930 Primary Recovery (4 — 5 % OOIP) 30-45 Primary + Waterflood (a total of 15% to 22% 120-200 of OOIP) First oil from the pool is expected during 2011. The production rate for the Nikaitchuq Schrader Bluff Oil Pool over the project life of 30 years is expected to average about 7,000 barrels of oil per day (BOPD), with a peak production rate of about 28,000 BOPD and 2.2 million cubic feet of gas per day early in the project life. Original oil in place for the N sand reservoir within the Nikaitchuq Unit is currently estimated to be between 300 and 600 million barrels. This reservoir may be developed later depending upon drilling results. Conservation Order No. 639 0 Page 6 November 19, 2010 10. Reservoir Development Drilling Plan The OA sand within the Nikaitchuq Schrader Bluff Oil Pool will be developed initially using 26 horizontal production wells, 21 horizontal injection wells, two disposal wells and three water source wells. Most of the production and injection wells will trend northwest, parallel with the normal faults that cut the reservoir. The horizontal sections of these wells will range in length from 4,000 to 8,500 feet within the reservoir, will be spaced about 1,200 feet apart, and will be arranged end -to -end, forming alternating rows of producers and injectors in a line -drive flood pattern flanked by outboard production wells. Development of the N sand reservoir may occur in the future, depending upon drilling results. 11. Reservoir Management Eni proposes to develop this oil pool as a water - injection enhanced oil recovery project. Production and injection voidage will be balanced to maintain reservoir pressure at or near the original measured pressure. Injection water will consist of produced water and water derived from the underlying Ivishak Formation. 12. Reservoir Surveillance Plans Eni proposes to meet bottom -hole pressure survey requirements by obtaining stabilized, static pressure measurements at bottom -hole or by 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. Eni proposes to meet the annual bottom -hole pressure measurement requirement by conducting bottom -hole pressure surveys in each reservoir compartment. Pressures will be referenced to a datum of -3,760 feet TVDSS. Eni proposes to report the data and results from the pressure surveys annually. 13. Wellbore Construction Eni proposes that the surface casing of wells drilled in the Nikaitchuq Schrader Bluff Oil Pool be set at approximately -2,400 feet 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 Nikaitchuq Schrader Bluff Oil Pool will be developed using horizontal wells with a 5 -1/2 -inch liner that is slotted across sandstone intervals and blank across shale intervals. These wells will undulate upward and downward within the reservoir to ensure complete coverage should any vertical flow barriers exist. Production wells will be equipped with ESPs, but not packers. Injectors may be equipped with 4 -1/2 -inch tubing and liner. Eni proposes that all wells within the Nikaitchuq Schrader Bluff Oil Pool be equipped with a fail -safe automatic surface safety valve (SSV). Eni proposes that all injection wells be equipped with a landing nipple at a depth below permafrost, which is suitable for the future installation of a down -hole flow control device. 14. Waivers Eni requests that the Commission grant the following waivers: a. Directional Wellbore Plans Eni 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). Conservation Order No. 639 Page 7 November 19, 2010 b. Well Spacing Eni 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 Eni seeks an exemption from the GOR limits of 20 AAC 25.240(a) in accordance with the provisions of 20 AAC 25.240(b). d. Packer Placement Eni seeks exemption from the placement requirements of 20 AAC 25.412(b) requesting instead that packers may be located more than 200 feet above the top of the injection zone, but not above the confining zone, with production casing cement volume sufficient to ensure cement placement is a minimum of 300 feet measured depth above the planned packer depth. 15. Sustained Casing Pressure Rules Eni proposes to operate Nikaitchuq Schrader Bluff Oil Pool wells in compliance with previous Commission orders addressing sustained casing pressures for active wells. CONCLUSIONS: I. Pool Rules for the development of the Nikaitchuq Schrader Bluff Oil Pool within the Nikaitchuq Unit and the Nikaitchuq Field are appropriate. 2. The Nikaitchuq Schrader Bluff Oil Pool is likely compartmentalized and will require unrestricted well spacing to optimize waterflood efficiency and resource recovery. Eliminating spacing restrictions on wellbores within 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. 3. Correlative rights of owners and landowners of offset acreage will be protected by a 500 - foot set -back requirement that conforms with regulation 20 AAC 25.055(a)(1). 4. Initial development will be limited to the OA sand of the Schrader Bluff Formation. No plan has been provided for development of oil accumulations within the N sands of the Schrader Bluff Formation. 5. Water injection into the Nikaitchuq Schrader Bluff Oil Pool will preserve reservoir energy and increase ultimate recovery. 6. 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. 7. 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. 8. 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 Conservation Order No. 639 Page 8 November 19, 2010 wellbore to prevent well intersection, to comply with spacing requirements, and to ensure protection of correlative rights." 9. A GOR limitation waiver is appropriate under 20 AAC 25.240(b)(1) because the Nikaitchuq Schrader Bluff Oil Pool will be developed as a waterflood -only enhanced recovery project. Injection of gas or miscible injectant to maintain reservoir pressure and enhance recovery is not considered feasible because of the low -GOR oil and the anticipated fuel gas requirements of the processing facility. Once the pressure maintenance waterflood commences it should prevent GORs from exceeding the limits imposed by 20 AAC 25.240(a). However, before the waterflood commences the injectors will be pre - produced to ensure there is adequate oil flow to operate the processing facilities and create reservoir voidage to accommodate water injection. During this period there may be some wells that will exceed the GOR limits. 10. Modification of the packer placement requirements of 20 AAC 25.412(b) proposed by ENI will ensure that injection of fluid is limited to the injection zone. 11. Surface - controlled subsurface safety valves are appropriate for all producing wells that are capable of flowing hydrocarbons to the surface. Requests for the approval of alternate types of subsurface safety valves should be addressed through the permit to drill or, if the well is already drilled, through the administrative action rule (i.e., Rule 14, below) implementation of new regulations effective December 3, 2010. NOW, THEREFORE, IT IS ORDERED: The development and operation of the Nikaitchuq Schrader Bluff 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 Lease Number Township, Ranize Sections i Section 31: protracted, all tide and submerged lands shoreward of the line fixed by coordinates found in Exhibit A of the final decree in U.S. vs. Alaska, No. 84 ADL 390433 Original, 431.61 acres; (Nikaitchuq T15N, R09E Section 32: protracted, all tide and submerged lands Unit, Tract 1) shoreward of the line fixed by coordinates found in Exhibit A of the final decree in U.S. vs. Alaska, No. 84 Original, 489.36 acres; Tract 1 contains 920.97 acres, more or less. Section 33: protracted, all tide and submerged lands shoreward of the line fixed by coordinates found in Exhibit A of the final decree in U.S. vs. Alaska, No. 84 ADL 389720 Original, 448.39 acres; (Nikaitchuq T15N, R09E Section 34: protracted, all tide and submerged lands Unit, Tract 2) shoreward of the line fixed by coordinates found in Exhibit A of the final decree in U.S. vs. Alaska, No. 84 Original, 545.63 acres; Tract 2 contains 994.02 acres, more or less. Conservation Order No. 639 Page 9 November 19, 2010 Lease Number Township, Range Sections Section 25: protracted, all tide and submerged lands ADL 389719 shoreward of the line fixed by coordinates found in Exhibit A of the final decree in U.S. vs. Alaska, No. 84 (Nikaitchuq T15N, R09E Original, 160.10 acres; Unit, Tract 3) Section 26: protracted, all tide and submerged lands shoreward of the line fixed by coordinates found in ADL 389719 Exhibit A of the final decree in U.S. vs. Alaska, No. 84 (Nikaitchuq Original, 98.90 acres; Unit, Tract 3) T15N, R09E Section 35: protracted, all, 640.00 acres; Section 36: protracted, all, 640.00 acres; Continued Tract 3 contains 1,539.00 acres, more or less. Section 5: protracted, all tide and submerged lands, 640.00 acres; ADL 388581 Section 6: protracted, all tide and submerged lands, 609.00 (Nikaitchuq T14N, R09E acres; Unit, Tract 4) Section 7: protracted, all tide and submerged lands, 611.00 acres; Section 8: protracted, all tide and submerged lands, 640.00 acres; Tract 4 contains 2,500.00 acres, more or less. Section 3: protracted, all tide and submerged lands, 640.00 acres; Section 4: protracted, all tide and submerged lands, 640.00 ADL 388580 acres; (Nikaitchuq T14N, R09E Section 9: protracted, all tide and submerged lands, 640.00 Unit, Tract 5) acres; Section 10: protracted, all tide and submerged lands, 640.00 acres; Tract 5 contains 2,560.00 acres, more or less. Section 1: protracted, all tide and submerged lands, 640.00 ADL 388579 acres; (Nikaitchuq T14N, R09E Section 2: protracted, all tide and submerged lands, 640.00 Unit, Tract 6) acres; Tract 6 contains 1,280.00 acres, more or less. Section 17: unsurveyed, all tide and submerged lands, 597.76 acres; Section 18: unsurveyed, all tide and submerged lands, ADL 388583 584.52 acres; Section 20: protracted, all tide and submerged lands, (Nikaitchuq T14N, R09E 640.00 acres; Unit, Tract 7) T. 14 N., R. 09 E., Umiat Meridian, Alaska — Tract A Section 17: unsurveyed, all uplands, 42.24 acres; Section 18: unsurveyed, all uplands, 29.48 acres; Tract 7 contains 1,894.00 acres, more or less. Conservation Order No. 639 -" 0 Page 10 November 19, 2010 Lease Number Township, Range Sections Section 16: unsurveyed, all tide and submerged lands, 618.37 acres; ADL 388582 Section 21: unsurveyed, all tide and submerged lands, 633.08 acres; (Nikaitchuq T14N, R09E T. 14 N., R. 09 E., Umiat Meridian, Alaska — Tract A Unit, Tract 8) Section 16: unsurveyed, all uplands 21.63 acres; Section 21: unsurveyed, all uplands 6.92 acres; Tract 8 contains 1,280.00 acres, more or less. ADL 390615 Section 28: protracted, all, 640.00 acres; (Nikaitchuq T14N, R09E Section 33: protracted, all, 640.00 acres; Unit, Tract 9) Tract 9 contains 1,280.00 acres, more or less. ADL 390616 Section 29: protracted, all, 640.00 acres; (Nikaitchuq T14N, R09E Section 32:, protracted, all, 640.00 acres; Unit, Tract 10) Tract 10 contains 1,280.00 acres, more or less. T. 14 N., R. 08 E., Umiat Meridian, Alaska Section 1: protracted, all tide and submerged lands, 640.00 acres; Section 2: protracted, all tide and submerged lands within the computed territorial sea, listed as state acreage on Alaska's seaward boundary diagram approved by the state on April 5, 1996, 539.63 acres; Section 11: protracted, all tide and submerged lands, 640.00 acres; ADL 388571 Section 12: protracted, all tide and submerged lands, (Nikaitchuq T14N, R00E, 640.00 acres; T15N, R8E Unit, Tract 11) T. 15 N., R. 08 E., Umiat Meridian, Alaska Section 35: protracted, all tide and submerged lands within the computed territorial sea, listed as state acreage on Alaska's seaward boundary diagram approved by the state on April 5, 1996, 24.00 acres; Section 36: protracted, all tide and submerged lands within the computed territorial sea, listed as state acreage on Alaska's seaward boundary diagram approved by the state on April 5, 1996, 282.73 acres; Tract 11 contains 2,766.36 acres. Conservation Order No. 639 Page 11 November 19, 2010 Lease Number Township, Range Sections T. 14 N., R. 08 E., Umiat Meridian, Alaska Section 3: protracted, all tide and submerged lands within the computed territorial sea, listed as state acreage on Alaska's seaward boundary diagram approved by the state on April 5, 1996, 170.91 acres; Section 4: protracted, all tide and submerged lands within the computed territorial sea, listed as state acreage on Alaska's seaward boundary diagram approved by the state ADL 388572 on April 5, 1996, 516.41 acres; T15N R0 (Nikaitchuq T14N, R00E, Section 9: protracted, all tide and submerged lands, Unit, Tract 12) , 8E 640.00 acres; Section 10: protracted, all tide and submerged lands, 640.00 acres T. 15 N., R. 08 E., Umiat Meridian, Alaska Section 33: protracted, all tide and submerged lands within the computed territorial sea, listed as state acreage on Alaska's seaward boundary diagram approved by the slate on April 5, 1996, 0.92 acres; Tract 12 contains 1,968.24 acres. T. 14 N., R. 08 E., Umiat Meridian, Alaska Section 5: protracted, all tide and submerged lands, 640.00 acres; Section 6: protracted, all tide and submerged lands, 609.00 acres; Section 7: protracted, all tide and submerged lands, 611.00 acres; Section 8: protracted, all tide and submerged lands, ADL 388573 T14N R08E 640.00 acres; (Nikaitchuq T15N, R08E T. 15 N., R. 08 E., Umiat Meridian, Alaska Unit, Tract 13) Section 31: protracted, all tide and submerged lands within the computed territorial sea, listed as state acreage on Alaska's seaward boundary diagram approved by the state on April 15, 1996, 177.20 acres; Section 32: protracted, all tide and submerged lands within the computed territorial sea, listed as state acreage on Alaska's seaward boundary diagram approved by the state on April 15, 1996, 109.39 acres; Tract 13 contains 2,786.59 acres. Section 13: protracted, all tide and submerged lands, 640.00 acres; ADL 388574 T14N, R08E Section 14: protracted, all tide and submerged lands, (Nikaitchuq 640.00 acres; Unit, Tract 14) Section 23: protracted, all tide and submerged lands, 640.00 acres; Tract 14 contains 1,920.00 acres. Conservation Order No. 639 Page 12 November 19, 2010 Lease Number Township, Range Sections Section 15: protracted, all tide and submerged lands, 640.00 acres; Section 16: protracted, all tide and submerged lands, ADL 388575 640.00acres; (Nikaitchuq T14N, R08E Section 21: protracted, all tide and submerged lands, Unit, Tract 15) 640.00 acres; Section 22: protracted, all tide and submerged lands, 640.00 acres; Tract 15 contains 2,560.00 acres. Section 26: protracted, all tide and submerged lands, ADL 388577 640.00 acres; ( (Nikaitchuq T14N, R08E q Section 35: protracted, all tide and submerged lands, Unit, Tract 16) 640.00 acres; This tract contains 1,280.00 acres, more or less. Section 27: protracted, all tide and submerged lands, ADL 388578 640.00 acres; (Nikaitchuq T14N, ROSE Section 34: protracted, all tide and submerged lands, Unit, Tract 17) 640.00 acres; Tract 17 contains 1,280.00 acres. T. 14 N., R. 08 E., Umiat Meridian, Alaska Section 24: Protracted, All, 640.00 acres; Section 25: Protracted, All, 640.00 acres; ADL 391283 T14N, R08E Section 36: Protracted, All, 640.00 acres; (Nikaitchuq T14N, R09E T. 14 N., R. 09 E., Umiat Meridian, Alaska Unit, Tract 18) Section 19: Protracted, All, 617.00 acres; Section 30: Protracted, All, 620.00 acres; Section 31: Protracted, All, 623.00 acres; Tract 18 contains 3,780.00 acres, more or less. Rule 1 Field and Pool Name The field is the Nikaitchuq Field. Hydrocarbons underlying the Affected Area and within the interval of the Schrader Bluff Formation identified in Rule 2, below, constitute the oil pool named the Nikaitchuq Schrader Bluff Oil Pool. Rule 2 Pool Definition The Nikaitchuq Schrader Bluff Oil Pool is the accumulation of hydrocarbons within the Affected Area that are common to, and correlating with, the interval between the measured depths of 3,530 and 3,867 feet on the Electromagnetic Wave Resistivity (EWR) log recorded in exploratory well Kigun No. 1. Rule 3 Well Spacing There shall be no restrictions as to well spacing except that no pay shall be opened in a well within 500 feet of an external property line where the owners and landowners are not the same on both sides of the line. Conservation Order No. 639 Page 13 November 19, 2010 Rule 4 Casing and Cementing a. Conductor casing shall be set at least 75 feet below ground level and cemented to surface. b. To provide proper anchorage for the blowout prevention equipment, surface casing shall be set at least 500 measured feet below the permafrost and cemented to surface. Rule 5 Wellbore Construction Injection wells may be completed with slotted liner across the injection interval provided a sealbore, packer or other mechanical isolation device is positioned below the top of the overlying confining interval and at least 300 feet measured depth below calculated top of cement. Each packer installation shall be approved on a case -by -case basis. Each production well must pass a Commission - witnessed "No Flow" test to qualify for a packerless ESP completion. Rule 6 Permit to Drill and Well Logging Practices All permits to drill deviated wells within the Nikaitchuq Schrader Bluff 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). In addition to the requirements of 20 AAC 25.071(a), a complete, open -hole petrophysical log suite acceptable to the Commission is required from below the conductor to total depth for at least one well per drill site. Rule 7 Automatic Shut -in Equipment Pending implementation of new regulations effective December 3, 2010, subsurface safety valves shall be addressed on a well -by -well basis either through the permit to drill or, if the well is already drilled, through the Administrative Action rule (i.e., Rule 14, below). Rule 8 Production Facilities a. Schlumberger VX multi -phase meters will be used to measure produced oil, gas and water volumes during well testing operations. b. Production shall be allocated to wells within the Nikaitchuq Schrader Bluff Oil Pool based on well tests. c. The Commission may require more frequent or longer testing if the summation of the calculated monthly production volume for the pool is not within 10 percent of the actual LACT metered volume. d. The operator shall submit a monthly report and electronic file(s) containing daily allocation data and daily test data for agency surveillance and evaluation. e. 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 12, below. Rule 9 Reservoir Pressure Monitoring a. A bottom -hole pressure survey shall be taken on each well prior to initial production or injection. Conservation Order No. 639 Page 14 November 19, 2010 b. The operator shall obtain annual pressure surveys within each reservoir compartment. Continuous pressure measurements from downhole gauges shall be averaged and reported monthly according to paragraph (e), below. The operator shall notify the Commission within one working day after the operator identifies a well as having a pressure that deviates significantly from its historical average. c. The reservoir pressure datum shall be -3,760 feet TVDSS. d. Pressure surveys may consist of stabilized static pressure measurements at bottom -hole 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, 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 submitted for all surveys. All data necessary for a complete analysis of each survey need not be submitted with the report but must be available to the Commission upon request. Results and data from any special reservoir pressure monitoring tests or surveys shall be submitted in accordance with this paragraph. Rule 10 Gas -Oil Ratio Exemption Wells producing from the Nikaitchuq Schrader Bluff Oil Pool are exempt from the GOR limits of 20 AAC 25.240(a) during the period from initial startup to the commencement of the pressure maintenance waterflood as required by Rule 11. Rule 11 Pressure Maintenance Proiect A pressure maintenance waterflood must be initiated within twelve months after the start of regular production from the Nikaitchuq Schrader Bluff Oil Pool. Production and injection must ensure the average reservoir pressure in any isolated reservoir compartment is maintained at, or above, the bubble point for that respective reservoir compartment. Rule 12 Annual Reservoir Review An annual reservoir surveillance report must be filed by April 1 St of each year. The report must include future development and surveillance plans, reservoir depletion plans, and surveillance information for the prior calendar year, including: a. Voidage balance by month of produced fluids and injected fluids on a standard and reservoir volume basis with yearly and cumulative volumes; b. a reservoir pressure map at datum and a summary and analysis of the reservoir pressure surveys within the pool; c. the results and, where appropriate, an analysis of any production and injection log surveys, tracer surveys, observation well surveys, and any other special monitoring; d. a review of pool production allocation factors and issues over the prior year; e. a review of the progress of the enhanced recovery project; I, Conservation Order No. 639 • Page 15 November 19, 2010 £ a reservoir management summary, including the results of any reservoir simulation studies; and g. updated future development plans including an estimated development schedule, progress report and basis of timeline for the complete pool development. By June 1 st of each year, Eni shall provide the Commission the opportunity to attend a technical review meeting to discuss report contents and review items that may require Commission action within the coming year. Rule 13 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 p P lanned 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 retained and 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 prig, or (ii) sustained outer annulus pressure that exceeds 1,000 psig. d. The Commission may require the operator to submit in an Application for Sundry Approvals (Form 10 -403) a proposal for corrective action or increased surveillance for any development well having sustained pressure that exceeds a limit set out in paragraph (c) of this rule. The Commission may approve the operator's proposal or may require other corrective action or surveillance. The Commission may require that corrective action be verified by mechanical integrity testing or other Commission - approved diagnostic tests. The operator shall give the Commission sufficient notice of the testing schedule to allow the Commission to witness the tests. e. If the operator identifies sustained pressure in the inner annulus of a development well that exceeds 45% of the burst pressure rating of the well's production casing for inner annulus pressure, or sustained pressure in the outer annulus that exceeds 45% of the burst pressure rating of the well's surface casing for outer annulus pressure, the operator shall notify the Commission within three working days and take corrective action. Unless well conditions require the operator to take emergency corrective action before Commission approval can be obtained, the operator shall submit in an Application for Sundry Approvals (Form 10 -403) a proposal for corrective action. The Commission may approve the operator's proposal or may require other corrective action. The Commission may also require that corrective action be verified by mechanical integrity testing or other Commission - approved diagnostic tests. The operator shall give the Commission sufficient notice of the testing schedule to allow the Commission to witness the tests. £ Except as otherwise approved by the Commission under (d) or (e) of this rule, before a shut - in well is placed in service, any annulus pressure must be relieved to a sufficient degree (i) that the inner annulus pressure at operating temperature will be below 2,000 psig, and (ii) Conservation Order No. 639 Page 16 November 19, 2010 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, i. "inner annulus" means the space in a well between tubing and production casing; ii. "outer annulus" means the space in a well between production casing and surface casing iii. "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 14 Administrative Action 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 November , 2010. OIL ANp n o a taston o servation o r A a O n ommission z Gz, c �'►s�, �� Cathy '. Foerster, Commissioner Alask Oil and Gas Conservation Commission 0 ! Conservation Order No. 639 Page 17 November 19, 2010 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 tiled. 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]be 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. Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Friday, November 19, 2010 3:15 PM To: 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); (foms2 @mtaon line. 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 Gillespie; Brian Havelock; Bruce Webb; carol smyth; Chris Gay; Cliff Posey; Crandall, Krissell; 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; eyancy; Francis S. Sommer; Fred Steece; Garland Robinson; Gary Laughlin; Gary Rogers; Gary Schultz; ghammons; Gordon Pospisii; Gorney, David L.; Greg Duggin; Gregg Nady; gspfoff; Harry Engel; Jdarlington Qarlington @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 S. Haworth; John Spain; John Tower; Jon Goltz; Judy Stanek; Julie Houle; Kari Moriarty; Kaynell Zeman; Keith Wiles; Kim Cunningham; Larry Ostrovsky; Laura Silliphant; Marilyn Crockett; Mark Dalton; Mark Hanley (mark.hanley @anadarko.com); Mark Kovac; Mark P. Worcester; Marquerite kremer; Michael Dammeyer; Michael Jacobs; Mike Bill; Mike Mason; Mikel Schultz; Mindy Lewis; MJ Loveland; mjnelson; mkm7200; nelson; Nick W. Glover; NSK Problem Well Supv; Patty Alfaro; Paul Decker (paul.decker @alaska.gov); Paul Figel; PORHOLA, STAN T; Randall Kanady; Randy L. Skillern; rob.g. drag nich @exxonmobil.com; Robert Brelsford; Robert Campbell; Rudy Brueggeman; 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 O (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; Aubert, Winton G (DOA); Ballantine, Tab A (LAW); Brooks, Phoebe; Davies, Stephen F (DOA); Fisher, Samantha J (DOA); Foerster, Catherine P (DOA); Johnson, Elaine M (DOA); Laasch, Linda K (DOA); Maunder, Thomas E (DOA); McIver, Bren (DOA); McMains, Stephen E (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); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Shartzer, Christine R (DOA) Subject: co 639 (ENI Nikaitchuq Pool Rules) Attachments: co639.pdf Jody J. Colombie Special Assistant Alaska Oil and Gas Conservation Commission 333 West 71h Avenue, Suite 100 Anchorage, AK 99501 (907)793 -1221 (phone) (907)276 -7542 (fax) 1 Mary Jones David McCaleb XTO Energy, Inc. IHS Energy Group George Vaught, Jr. Cartography GEPS P.O. Box 13557 810 Houston Street, Ste 200 5333 Westheimer, Suite 100 Denver, CO 80201 -3557 Ft. Worth, TX 76102 -6298 Houston, TX 77056 Jerry Hodgden Richard Neahring Mark Wedman Hodgden Oil Company NRG Associates Halliburton 408 18 Street President 6900 Arctic Blvd. Golden, CO 80401 -2433 P.O. Box 1655 Anchorage, AK 99502 Colorado Springs, CO 80901 Bernie Karl CIRI K &K Recycling Inc. Land Department Baker Oil ho o fs 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 • • a r1 [An, SEAN PARNELL, GOVERNOR O ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COM2'HSSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 ADMINISTRATIVE APPROVAL CO 639.001 Mr. David K. Johnston Facilities Engineering Manager Eni US Operating Co., Inc. 1201 Louisiana, Suite 3500 Houston, TX 77002 RE: Application for the qualification of a Multiphase Metering System for Well Testing at the Nikaitchuq Field Dear Mr. Johnston: In accordance with Rule 14 of Conservation Order (CO) 639 governing the Nikaitchuq Schrader Bluff Oil Pool, Nikaitchuq Field, the Alaska Oil and Gas Conservation Commission (Commission) APPROVES Eni US Operating Co., Inc.'s (Eni) application for qualification of a well testing and allocation system for the aforementioned pool. CO 639 was issued by the Commission on November 19, 2010. Rules 8(a) and 8(b) of that order touched on well testing and allocation at the field. Specifically these rules stated: a. Schlumberger VX multi -phase meters will be used to measure produced oil, gas and water volumes during well testing operations. b. Production shall be allocated to wells within the Nikaitchuq Schrader Bluff Oil Pool based on well tests. By letter dated October 24, 2010, and received by the Commission on October 29, 2010, Eni submitted an application for the qualification of a multiphase metering system for well testing at the Nikaitchuq Field (October 24 Application). The October 24 Application supplemented the information contained in the Pool Rules application that was the basis for CO 639 and provided more specific details on the Schlumberger VX multiphase meters, including the operation and maintenance procedures and the allocation methodology to be used at Nikaitchuq. The Schlumberger VX multiphase meters have been put into service in numerous locations on the North Slope and have demonstrated themselves to provide acceptable accuracy and reliability for well testing and allocation purposes when operated and maintained properly. The system and procedures proposed by Eni in the October 24 Application are comparable to the other installations on the North Slope and therefore should be expected to provide adequate results. CO 639.001 • • January 19, 2011 Page 2 of 3 In addition to providing information about the Schlumberger VX multiphase metering system and the operation and maintenance of that system, the October 24 Application also provided a detailed description of the production allocation methodology proposed to be used for Nikaitchuq. This methodology is comparable to allocation methodologies used satisfactorily in other fields in Alaska and as such should be expected to provide acceptable results for allocation of production to the individual wells. In order to ensure that the metering system is operated and maintained appropriately over the life of the field it is appropriate to incorporate the components of the October 24 Application into the Pool Rules established by CO 639. Therefore, in accordance with Rule 14 of CO 639 the Commission administratively amends CO 639 to incorporate by reference the October 24 Application and the operation and maintenance procedures and production allocation methodology contained therein. Rule 8 of CO 639 is repealed and readopted to read as follows. Rule 8 Production Facilities a. Schlumberger VX multi -phase meters will be used to measure produced oil, gas and water volumes during well testing operations. The metering system must be operated and maintained in accordance with the procedures described in the "Application for the Qualification of a Multiphase Metering System for Well Testing at the Nikaitchuq Field" dated October 24, 2010. i. Any changes to the operation and maintenance procedures must be approved by the Commission prior to being implemented. b. Production shall be allocated to wells within the Nikaitchuq Schrader Bluff Oil Pool based on well tests. The production allocation methodology shall be performed as described in the "Application for the Qualification of a Multiphase Metering System for Well Testing at the Nikaitchuq Field" dated October 24, 2010. i. Any changes to the production allocation methodology must be approved by the Commission prior to being implemented. c. The Commission may require more frequent or longer testing if the summation of the calculated monthly production volume for the pool is not within 10 percent of the actual LACT metered volume. d. The operator shall submit a monthly report and electronic file(s) containing daily allocation data and daily test data for agency surveillance and evaluation. e. 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 12, below. CO 639.001 • • January 19, 2011 Page 3 of 3 ENTE' A • orag:, Alaska, and dated January 19, 2011. /� ; . 0 rr ,4 . �• ` � w� OIL4� orman Cathy P Foerster li Commis ' • ner Commissioner - rtOSI 0 ,11147 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), "Mlle 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: Wednesday, January 19, 2011 3:31 PM To: 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 (DOA sponsored); Johnson, Elaine M (DOA) (elaine.johnson @ alaska.gov); Jones, Jeffery B (DOA) (jeff.jones @alaska.gov); Laasch, Linda K (DOA) (linda.laasch @alaska.gov); Maunder, Thomas E (DOA) (tom.maunder @alaska.gov); McIver, Bren (DOA) (bren.mciver @alaska.gov); McMains, Stephen E (DOA) (steve.mcmains @alaska.gov); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA) (bob.noble @alaska.gov); Norman, John K (DOA) (john.norman @alaska.gov); Okland, Howard D (DOA) (howard.okland @alaska.gov); Paladijczuk, Tracie L (DOA) ( tracie.paladijczuk @alaska.gov); Pasqual, Maria (DOA) (maria.pasqual @alaska.gov); Regg, James B (DOA) (jim.regg @alaska.gov); Roby, David S (DOA) (dave.roby @alaska.gov); Saltmarsh, Arthur C (DOA) (art.saltmarsh @alaska.gov); Scheve, Charles M (DOA) (chuck.scheve @alaska.gov); Schwartz, Guy L (DOA) (guy.schwartz @alaska.gov); Seamount, Dan T (DOA) (dan.seamount @alaska.gov); Shartzer, Christine R (DOA); '(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'; 'Brandow, Cande (ASRC Energy Services)'; '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'; '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'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; 'Kelly Sperback'; 'Kim Cunningham'; 'Larry Ostrovsky'; 'Marilyn Crockett'; 'Mark Dalton'; 'Mark Hanley (mark.hanley @anadarko.com)'; 'Mark Kovac'; 'Mark P. Worcester; 'Michael Dammeyer'; 'Michael Jacobs'; 'Mike Bill'; 'Mike Mason'; 'Mikel Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'nelson'; 'Nick W. Glover'; 'NSK Problem Well Supv'; 'Patty Alfaro'; 'Paul Decker (paul.decker @alaska.gov)'; 'Paul Figel'; 'PORHOLA, STAN T'; 'Randall Kanady'; 'Randy L. Skillern'; ' rob.g.dragnich @exxonmobil.com'; 'Robert Brelsford'; 'Robert Campbell'; 'Ryan Tunseth'; 'Scott Cranswick'; 'Scott Griffith'; Scott, David (LAA); 'Shannon Donnelly'; 'Sharmaine Copeland'; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); 'Sondra Stewman'; 'Steve Lambert'; 'Steven R. Rossberg'; 'Suzanne Gibson'; 'tablerk'; 'Tamera Sheffield'; Taylor, Cammy 0 (DNR); 'Teresa lmm'; '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) Subject: AIO 36 (Nikaitchuq) Attachments: aio 36.pdf Saincmthai fisher A taisica, Oa/ Caat Cona-eNvatw-wC (907)793 -1 223 (907)276-754'2 (fww) 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 a. Anchorage, AK 99515 -4295 Fairbanks, AK 99711 Anchorage, AK 99503 North Slope Borough Jill Schneider Gordon Severson US Geological Survey P.O. Box 69 3201 Westmar Circle 4200 University Drive Barrow, AK 99723 Anchorage, 99 508 -4336 Anchorage, AK 99508 AK 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 \KC' VA.\ cds • • AlASEA SEAN PARNELL, GOVERNOR O 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 APPROVAL CONSERVATION ORDER 639.002 Mr. Joseph Longo Drilling Engineer Eni US Operating Co. Inc. 3800 Centerpoint Drive, Suite 300 Anchorage, AK 99503 RE: Request for Administrative Approval Nikaitchuq Unit OP21 -WW01 (PTD 2101870) Dear Mr. Longo: In accordance with Rule 14 of Conservation Order (CO) 639.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS Eni US Operating Company Inc. (Eni)'s request for administrative approval to place the surface casing shoe within 500 feet of the base of permafrost in the subject well. While running equipment into Nikaitchuq OP21 -WW01 (water supply well) for the purposes of casing and cementing the surface section of the well, surface casing became stuck before reaching the bottom of the open hole section. Attempts to pull the casing free were unsuccessful, requiring the surface casing to be set at its stuck point. Conservation Order 639, Rule 4.b. requires the surface casing setting depth to be "at least 500 feet measured feet below the permafrost "; the stuck depth of the casing is approximately 260 feet below permafrost. AOGCC has approved revised plans submitted by Eni to cement the surface casing in place and to establish the mechanical integrity of the surface casing before installing blowout prevention equipment and drilling ahead in Nikaitchuq OP21 -WW01. Allowing the surface casing to be set at a depth less than required by Conservation Order 639 will not promote waste, will not compromise the integrity of the well or prevent the ability to continue drilling in a safe and efficient manner, will not jeopardize correlative rights, and will not increase the risk of fluid movement into fresh water. DONE at Anchorage, Alaska and dated March 23, 2012. ,/ OIL Cathy P Foe ter D:rr' el T. Seamount, Jr. K. No Chair, ommissioner Commissioner ' o • Toner �� 4 rioN C( CO 639.002 • • March 23, 2012 Page 2 of 2 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited to the questions presented to the AOGCC 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. • • Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Friday, March 23, 2012 2:09 PM To: Ballantine, Tab A (LAW); Brooks, Phoebe; Colombie, Jody J (DOA); Crisp, John H (DOA); Davies, Stephen F (DOA); Fisher, Samantha J (DOA); Foerster, Catherine P (DOA); Grimaldi, Louis R (DOA); Herrera, Matt F (DOA); Johnson, Elaine M (DOA); Jones, Jeffery B (DOA); Laasch, Linda K (DOA); Makana Bender; Matt Herrera; Maunder, Thomas E (DOA sponsored); McIver, Bren (DOA); McMains, Stephen E (DOA); Mumm, Joseph (DOA sponsored); 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); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); 'Aaron Gluzman'; 'Ben Greene'; 'Bruce Williams'; Bruno, Jeff J 'CA Sullivan; 'Dale David Lenig; 'Donna Vukich'; Eric Lidji; Erik (DNR); CA Underwood ,Casey Sullivan, Dale Hoffman , a g, 1, Opstad; Franger, James M (DNR); 'Gary Orr; 'Graham Smith'; 'Greg Mattson'; Heusser, Heather A (DNR); 'Jason Bergerson'; Jennifer Starck; 'Jill McLeod'; 'Joe Longo'; King, Kathleen J (DNR); 'Lara Coates'; Lois Epstein; Marc Kuck; 'Marie Steele'; 'Mary Aschoff; 'Matt Gill'; Maurizio Grandi; Ostrovsky, Larry Z (DNR); 'Patricia Bettis'; Perrin, Don J (DNR); Peter Contreras; Pexton, Scott R (DEC); Richard Garrard; 'Ryan Daniel'; 'Sandra Lemke'; Talib Syed; 'Ted Rockwell'; 'Wayne Wooster; 'Wendy Wollf; 'William Hutto'; 'William Van Dyke'; (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; Brandon Gagnon; Brandow, Cande (ASRC Energy Services); Brian Havelock; Bruce Webb; caunderwood; Chris Gay; 'Claire Caldes'; Cliff Posey; Crandall, Krissell; 'D Lawrence'; dapa; Daryl J. Kleppin; 'Dave Harbour; 'Dave Matthews'; David Boelens; David House; 'David Scott'; David Steingreaber; 'ddonkel @cfl.rr.com'; 'Dennis Steffy'; Elowe, Kristin; Erika Denman; 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'; 'Gregory Geddes'; gspfoff; 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 Easton'; John Garing; John Katz (john.katz @alaska.gov); John S. Haworth; John Spain; Jon Goltz; Jones, Jeffrey L (GOV); Judy Stanek; Julie Houle; Kari Moriarty; Kaynell Zeman; Keith Wiles; Kelly Sperback; 'Kim Cunningham'; Larry Ostrovsky; Laura Silliphant (laura.gregersen @ alaska.gov); Marc Kovak; Mark Dalton; Mark Hanley (mark.hanley @anadarko.com); Mark P. Worcester; Marguerite kremer (meg.kremer @alaska.gov); 'Michael Dammeyer; Michael Jacobs; Mike Bill; Mike Mason; 'Mike Morgan'; Mikel Schultz; Mindy Lewis; MJ Loveland; mjnelson; mkm7200; nelson; Nick W. Glover; NSK Problem Well Supv; Patty Alfaro; Paul Decker (paul.decker @alaska.gov); 'Paul Figel'; Randall Kanady; Randy L. Skiliern; 'Rena Delbridge'; 'Renan Yanish'; rob.g.dragnich @exxonmobil.com; 'Robert Brelsford'; Robert Campbell; '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; 'Tim Mayers'; Tina Grovier; Todd Durkee; Tony Hopfinger; trmjrl; Vicki Irwin; Walter Featherly; Will Chinn; Williamson, Mary J (DNR); Yereth Rosen Subject: Administrative Approval CO 639 -002 (0P21 -WW01) Attachments: co639 -002. pdf Jody d.. Colombie Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907)793 -1221 (phone) (907)276 -7542 (fax) 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 Borough Richard Wagner Gordon Severson Planning Department P.O. Box 60868 3201 Westmar Circle P.O. Box 69 Fairbanks, AK 99706 Anchorage, AK 99508 -4336 Barrow, AK 99723 Jack Hakkila Darwin Waldsmith James Gibbs P.O. Box 190083 P.O. Box 39309 P.O. Box 1597 Anchorage, AK 99519 Ninilchick, AK 99639 Soldotna, AK 99669 Penny Vadla Cliff Burglin 399 West Riverview Avenue 319 Charles Street Soldotna, AK 99669 -7714 Fairbanks, AK 99701 1\ it 8 eo 6 Regg, James B (DOA) From: Longo Joseph [joe.longo ©enipetroleum.com] Sent: Friday, March 23, 2012 10:38 AM qZ y To: Regg, James B (DOA) Subject: OP21 -WW01 CO 639 Administrative Approval Jim, Eni would like to request Administrative Approval, regarding the CO 639 surface casing setting requirement, to set the surface casing Tess than 500' below the base of the permafrost. While running the 13 -3/8" surface casing string the casing became stuck and all attempts to recover were unsuccessful. If you have any questions please do not hesitate to ask. Regards, Joseph Longo Drilling Engineer Anchorage, AK Office (Anchorage): (907) 865 -3323 Office (North Slope): (907) 685 -1226 Cell: (907) 947 -4323 Email: Joseph.Longo(aenipetroleum.com This message may contain information that is confidential, and is being sent exclusively to the Recipient. If you are not the designated Recipient, you are prohibited from utilizing, copying or divulging the information contained in this message,or taking any action whatsoever on the basis of the information herein. If you have received this message by mistake, we ask you to kindly inform the Sender and to delete the message. It is understood that, with regard to messages sent by its network, the Company is not responsible for any statements made or opinions expressed, that are not strictly related to the Company's operations. • • Fisher, Samantha J (DOA) From: Regg, James B (DOA) Sent: Friday, March 23, 2012 10:58 AM To: Fisher, Samantha J (DOA) Subject: FW: OP21 -WW01 CO 639 Administrative Approval ENI's request for admin approval Jim Regg AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907 -793 -1236 From: Longo Joseph j mailto :joe.longoOenipetroleum.coml Sent: Friday, March 23, 2012 10:38 AM To: Regg, James B (DOA) Subject: OP21 -WW01 CO 639 Administrative Approval Jim, Eni would like to request Administrative Approval, regarding the CO 639 surface casing setting requirement, to set the surface casing Tess than 500' below the base of the permafrost. While running the 13 -3/8" surface casing string the casing became stuck and all attempts to recover were unsuccessful. If you have any questions please do not hesitate to ask. Regards, Joseph Longo Drilling Engineer Anchorage, AK Office (Anchorage): (907) 865 -3323 Office (North Slope): (907) 685 -1226 Cell: (907) 947 -4323 Email: Joseph. Longo(aenipetroleum.com This message may contain information that is confidential, and is being sent exclusively to the Recipient. If you are not the designated Recipient, you are prohibited from utilizing, copying or divulging the information contained in this message,or taking any action whatsoever on the basis of the information herein. If you have received this message by mistake, we ask you to kindly inform the Sender and to delete the message. It is understood that, with regard to messages sent by its network, the Company is not responsible for any statements made or opinions expressed, that are not strictly related to the Company's operations. 1 �7 • Fisher, Samantha J (DOA) From: Crandall, Krissell [Krissell.Crandall ©bp.com] Sent: Friday, January 21, 2011 10:12 AM To: Fisher, Samantha J (DOA) Subject: Request for CO 639.001 application Samantha - Per CO 639.001, ENI filed an application for qualification of a multi -phase metering system at Nikaitchuq on October 24, 2010. Please send me an electronic copy of the application, and any subsequently filed materials that are publicly available. Thanks, Krissell Krissell Crandall, Financial Analyst Central Finance Organization, OBO /Bus Dev BP Exploration (Alaska) Inc., Office 478D (907) 564 -4315 (Direct) (907) 441 -0990 (Cell) 1 (.0 O s us operating Corporate Office: 1201 Louisiana, Suite 3500 Me ENE° Houston, Texas 77002 Phone: (713) 393 -6100 Fax: (713) 393 -6217 OCT 2 9 700 24 October, 2010 NSA Qa& +ionx.tor sion Anchorage Alaska Oil & Gas Conservation Commission 333 7 Ave., Ste. 100 Anchorage, AK 99501 Re: Application for the Qualificaiton of a Multiphase Metering System for Well Testing at the Nikaitchuq Field Gentlemen, In accordance with 20 AAC 25.230, Eni US Operating Co., Inc. hereby submits the attached application for the qualification of a multiphase metering system for well testing at the Nikaitchuq Field. If additional information is needed or clarification is required please contact the undersigned at 907.865.3300. Regards, ' / David K. Joh Ion Facilities Eng neering Manager Attachment /dj • • Application for the Qualification of a Multiphase Metering System for Well Testing at the Nikaitchuq Field October 11, 2010 ENI US Operating Co., Inc. Nikaitchuq Project ADL 391283, ADL 388571, ADL 388572, ADL 388573, ADL 388574, ADL 388575, ADL 388577, ADL 388578, ADL 388579, ADL 388580, ADL 388581, ADL 388582, ADL 388583, ADL 389719, ADL 389720, ADL 390433, ADL 390615, and ADL 390616. • • Table of Contents 1. Proposed application, location and installation schedule 3 2. Affected fields, pools, and wells3 3. Working interest, royalty interest, and tax treatment 3 4. Notifications 3 5. Multiphase meter description 4 P P 6. Field testing exemption 4 7. Meter performance during flow loop tests and field tests 10 8. Meter performance expected in proposed application 10 9. Production allocation methodology 12 10. Contingency plan in the event of meter performance failure 12 11. HSE management plan 13 12. Measurement quality assurance plan 14 13. Meter maintenance plan 15 1. Proposed application, location and installation schedule This document is an application to the State of Alaska for the qualification of a multiphase metering system for well testing at the Nikaitchuq Unit (NU), Schrader Bluff Oil Pool. The multiphase metering system proposed is the Schlumberger PhaseWatcher Vx. This system has been previously approved by the AOGCC for well testing in the following pools: Put River Oil Pool (CO 559.003), Raven Oil Pool (CO 570.001) All other oil pools within Prudhoe Bay Field (CO 547.001), All Endicot Pools (CO 548.001) All Milne Point Pools (CO 550.001), and Northstar Pools (CO 551.001). The proposed meter installation locations are at an onshore gravel pad (OPP) located at Oliktok Point and at an offshore island pad (SID) constructed in 6 feet water depth. Both locations host drilling facilities and the well testing meters and manifold (see attachments A & B — P &IDs). The onshore location also contains 40 Kbopd multiphase processing facilities and custody transfer metering for all NU production. The multiphase meters will be used for well testing, i.e., individual well rate determination. There is one meter station at Oliktok Point and one meter station at Spy Island. Each meter station consists of two meters in parallel. This arrangement provides full redundancy of measurement. It is expected that only one meter is used at a time. At Oliktok Point there is expected to be 10 producing wells. At Spy Island there is expected to be 16 producing wells. Each well will be routed through the well test multiphase meter periodically to meter the well flow rate. Each well will be tested at least once per month. Well test duration may vary. The well flow rate measurement results have no direct bearing on the custody transfer measurements. The projected schedule for installation and commissioning of the meters calls for installation of the meters in the third quarter of 2010, and pre- commissioning in the fourth quarter of 2010. Final commissioning will occur at facility start up, which is planned for January 1, 2011. 2. Affected fields, pools, and wells The multiphase meters will be installed and used to meter well test rates for the Nikaitchuq Field and Schrader Bluff Oil Pool. There is expected to be approximately 26 producing wells, 10 at Oliktok Point and 16 at Spy Island. All produced fluids are from the same pool. There is no commingling. 3. Working interest, royalty interest, and tax treatment Working interest in the NU is 100% ENI US Operating Co., Inc. The royalty rate is 16.66667% (1 /6th) for all the leases except Tract 18 ADL 391283, which is 12.5% (1 /8th). This lease is also the only Net Profit Share lease in the Unit with a 30% NPS burden. For the first 25 years following the date of first sustained production, when Alaska North Slope West Coast delivered crude prices are below the threshold price per barrel, then production from the Nikaitchuq Scharder bluff OA reservoir on the subject lease will pay a 5 percent royalty. All leases are tax exempt. 4. Notifications Notification of this application is being provided to the following" a) Working interest owner: ENI US Operating Co., Inc. (100 %) b) Royalty owner: Alaska Department of Natural Resources c) State revenue department: Alaska Department of Revenue 5. Multiphase meter description 5.1. Introduction The scope of this section is to give a general description of the PhaseWatcher Vx, its main parts, and the measurement principles. 5.2. General Description The PhaseWatcher Vx is a three phase flow meter in the Vx Meter product range from 3 -Phase Measurements. The Vx Meter uses the Vx Technology, where the main components are a venturi section, a high performance phase hold -up detection system and a 3- phasic flow model. 3 -Phase Measurements is a joint technology center for Schlumberger WCP Testing and Framo Engineering. The PhaseWatcher Vx is a complete and independent inline flow meter, designed to measure a- phasic flow rates (Oil, Water and Gas). No other external inputs than fluid properties are needed. The PhaseWatcher, together with a blind tee placed directly upstream, gives accurate and repeatable measurements independent of the upstream flow regime. The operating envelope is decided by the maximum acceptable pressure loss through the PhaseWatcher and the minimum venturi differential Pressure that can be measured with the required accuracy. A standard PhaseWatcher Vx comprises the following: • A venturi with a measuring section including: o Multi- energy fraction meter system (detector housing w/ detector and source housing w /Barium source) o Differential pressure transmitter o Pressure transmitter • Temperature transmitter • Junction box with DAFC 3.1.1 Venturi 5.3. Hardware Description The venturi is fitted with two pressure barriers (windows) of a low- attenuation material. These are placed 180° opposite each other at the venturi throat (radiation path). The venturi has fixed sized inlet and outlet hubs. 5.3.1. Junction Box • • The junction box has a Data Acquisition Flow Computer (DAFC) installed. All instruments, communications and the power supply are connected to the DAFC though the terminals inside the junction box. 5.3.2. Differential Pressure Transmitters The DP transmitter consists of a transmitter housing and two remote seals. The remote seals are connected to a high pressure and low pressure port at the venturi, using flexible capillary tubing. The transmitter housing is fitted to the venturi body. 5.3.3. Line Pressure Transmitter The PT transmitter housing is installed at the measuring section of the venturi body. The sensor of the transmitter is connected to the process using impulse tubing. 5.3.4. Temperature Transmitter The TT transmitter is normally installed in the blind tee. In some cases, the temperature transmitter may be mounted non - intrusively in the venturi body. 5.3.5. Source Housing w/ Source Assembly The source housing is installed at the venturi throat. The source housing reduces the external radiation from the installed source assembly to well below acceptable limits. The source assembly consists of a Barium 133 isotope encapsulated in a lead filled holder of stainless steel. The source assembly has a collimating opening for the radiation beam. An identification plate is riveted on the source housing envelope plug to indicate the source serial number, fabrication date and initial activity. 5.3.6. Detector Housing w /Detector The detector housing is installed at the venturi throat, opposite to the source housing. The detector is installed inside the detector housing, which also acts as protection against radiation from the Ba -133 source. The cover on top of the detector housing is part of the penetrator cable, and includes wires with connectors to be plugged into the detector. 5.3.7. Blind Tee A blind tee must be located immediately upstream of the venturi. The blind tee is a flow mixturing device. The blind tee must be produced in accordance with 3 -Phase Measurements specifications. The blind tee is required in order for the PhaseWatcher Vx to be independent of the effects of variable and unpredictable flow regimes, which are encountered in multiphase well streams. The blind tee will also prevent any interaction from upstream devices. (i.e. choke, valves, etc.). The blind tee is customer supply, or may be supplied together with the PhaseWatcher Vx. 5.4. Instrumentation 5.4.1. DAFC 0 The Data Acquisition Flow Computer (DAFC), is the heart of the PhaseWatcher Vx system. The DAFC collects data from all instruments, and interacts with external systems. The input voltage to the PhaseWatcher Vx is connected directly to the DAFC. The DAFC is fitted with DC /DC converters, and acts as a power supply unit for the detector and the transmitters. The DAFC is fitted with two serial links which provide capabilities for concurrent communication with external systems. 5.4.2. Pressure Transmitter The pressure transmitter measures the pressure at the venturi throat. The output of the pressure transmitter is used by the DAFC to correct the PVT model for changes in pressure. 5.4.3. Temperature Transmitter The temperature transmitter measures the temperature at the PhaseWatcher Vx inlet. The output of the temperature transmitter is used by the DAFC to correct the PVT model for changes in temperature. 5.4.4. Differential Transmitter The differential pressure transmitter measures the differential pressure across the measuring section of the venturi. It is used by the DAFC to calculate the velocity of the flow. 5.4.5. Detector The detectors' primary function is to measure activity of 3 energy peaks in the Ba -133 Gamma spectrum (- 32keV, —81 keV and —356 keV), in counts per second. This is the basis for the hold -up calculations. 5.5. Principles of Measurement 5.5.1. Flow calculation The velocity of the fluid /gas is found using a venturi equation. For a mono - phasic flow, we can find the flow rate using raw dynamic output of the DP transmitter together with the density of the fluid /gas. However, for three - phasic flow, the equation is different, due to slippage between the oil and gas. For a three - phasic flow we need to know the total mixture density before we can calculate the flow rates. To find this we use the output of the detector. Data from the detector is used to calculate the fraction of oil, water and gas. Flow regimes are very often impossible to identify because they appear not as a singularly identifiable flow regime, but as a complex combination of several flow patterns. The challenge in handling variations in flow regimes is one of the most important parameters that influence the performance of multiphase flow meters. The PhaseWatcher Vx approach to this challenge is to break the flow regime up into a turbulent mixture and use high- frequent measurements to precisely measure the individual phase fractions. In this manner the PhaseWatcher Vx measurements are unaffected by any flow pattern that appears in the multiphase flow lines upstream the Vx meter. 5.5.2. Instant fraction at the throat of the venturi Known equations for mass attenuation are used in the interpretation model to find the instant fraction of each phase. When the PhaseWatcher Vx is properly configured, the only unknown parameters will be the fraction of each of the three phases at the throat of the venturi. Because of this, the interpretation model uses three equations to find the three unknowns. The three equations are made as follows: • Two of the equations are based on the equation for mass attenuation with the numbers of counts per second for the 32keV and 81 keV levels as inputs. • The third equation is based on the fact that the percentage sum of all three fractions must be 100 %. To set -up the PhaseWatcher Vx so it can perform as described above, the following measurements /calculations must take place: • First, an empty -pipe reference measurement has to be performed to determine the source strength. • Then, we need to find the mass attenuation levels of each of the three phases. This can be done either by calculations or in -situ reference measurements. The attenuation of gamma rays is dependent of the density and the mass attenuation coefficient of the penetrated material. The physical relation is well known: N = N e r° '' ( Where: N = count rate from the gamma detector 1M'o = 'empty pipe reference' cant rate x = gamma path length p = density of the penetrated material u = mass attenuation coefficient of the penetrated maternal In the case where multiple components are penetrated as in a homogenized mixture of oil, water and gas equitation (1) can be expressed as: N = N e H a, a1 (2) Where: ao = al hold-up Qv = water hold-up = gas hold -up Since ao, aw, and ag are the unknown, two more equations are required to solve the system. The dual energy gamma fraction meter utilizes the fact that the radioactive source emits radiation at different energy levels. • Equations similar to (2) are established for each of the two energy levels. The third equation used to solve the system is straight forward since the volume between the source and the detector is fully occupied by the mixture of the three fractions: a +a„ +a =1 (3) As seen from equation (2), the mass attenuation coefficient p and the density p for each phase are used as input parameters (known values) in the fraction calculations. The mass attenuation coefficients are constants given by the chemical composition of a specific material (fluid). The mass attenuation coefficient for oil and gas (hydrocarbons) are not affected by pressure or temperature and are in most applications stabile over the field life. 5.5.3. Density The density for a phase is found using an algorithm based on input from a PVT analysis, together with raw measurement data from pressure and temperature transmitters. Service computer - PC 1 Pcs ( serer Wks DAK RS232 serial rink HART I P Live — I Gamma Detector I'" 1 Gamma Some WART I DPV T Lire Few MART TALE 4-- Figure 1: tnstrumer*atian Diagram 5.6. Application Software The application software of the PhaseWatcher Vx consists of two major parts, the Data Acquisition Flow Computer (DAFC) software and the service computer software. 5.6.1. DAFC Software The DAFC software performs acquisition of data from the gamma detector and transmitters, runs the interpretation model and responds to requests via the Modbus serial link from the supervisory system or service computer. • Processed flow data is updated every 10 seconds (transmitter readings g every 1 second) and made available to the supervisory system on a serial link from the Data Acquisition Flow Computer. Data which is available at the Modbus serial line interface includes: • Volumetric flow rates and phase fractions at standard conditions and at line conditions, • Total mass flow rate, water liquid ratio (WLR), gas volume fraction (GVF), gas oil ratio (GOR), basic sediment and water (BSW) and cumulative mass /volumetric values for oil, water and gas. 5.6.2. Service Computer Software Once the service computer is connected to the DAFC, the DAFC will appear transparent at the service computer. For the operator, the service computer and DAFC will appear as one system. The service computer software features the following main functionalities: • Provides user interface for the PhaseWatcher during set -up, reference measurements and service. • HART communication with transmitters. • Retrieves and displays measured and calculated data from the DAFC. • Performs storage of configuration and reference parameters. • Performs storage of data. • Permits flow monitoring and trending to be displayed. 5.7. Additional Equipment 5.7.1. VFD Display Module A local VFD display at the front of the Data Acquisition Flow Computer is installed. A window section is fitted in the junction box lid if this option is selected. The display automatically toggles between pre- defined screens presenting updated key data (flow rates, fractions, transmitter readings and density data). 5.7.2. Datalogger An optional Compact Flash card (2GB) is installed in the DAFC and used as a Datalogger. The DAFC will store measured and calculated data. Stored data may be extracted from the Compact Flash card via the DAFC using Service Manager Software. 5.7.3. Double Block & Bleed (DBB) valves • DBB valves are installed between the venturi and the remote seals of the DP transmitter, and between the venturi and the PT transmitter. This option makes it possible to perform zero -trim or replacement of the transmitters, without having to de- pressurize the venturi first. 6. Field testing exemption An exemption from meter field- testing is requested because of the substantial historical reference data available documenting the the PhaseWatcher Vx meter performance in general, in similar field environments, as well as nearby fields in the State of Alaska. Reference is made to the previous application for use of PhaseWatcher Vx meters for well testing by BP Alaska for Put River Oil Pool (CO 559.003), Raven Oil Pool (CO 570.001) All other oil pools within Prudhoe Bay Field (CO 547.001), All Endicott Pools (CO 548.001), All Milne Point Pools (CO 550.001), and Northstar Pools (CO 551.001). The manufacturer has demonstrated the meter performance in several independent third party tests. The manufacturer's stated performance is given in the table in the following section. The field tests conducted in Alaska by BP, results also given in a table in the following section, confirm the field performance is in line with the manufacturer's stated performance. 7. Meter performance during flow loop tests and field tests The average performance of the PhaseWatcher Vx meter as tested in the GPB field by BP, is show in the table below. These results are from 13 flow tests covering a range of GVF from 54% to 91 %, liquid rate from 1386 to 3256 blpd, gas from 0.2 to 6.6 MMSCF /d, and watercut from 2% to 70 %. GVF 0 -90% Liquid (relative) -4 % WLR (absolute) -1 Gas (relative) +8 % The performance of the PhaseWatcher Vx meter as published by the manufacturer, 3 -PHASE Measurements AS, is show in the table below. GVF 0 -90% 90 -96% 96 % -98% Liquid (relative) 2.5 % 5 % 10 % WLR (absolute) 2.5 % 2.5% - 5 % 5% - 8 % Gas (relative) > 300 psi 5 <300psi 10% 15% 8. Meter performance expected in proposed application The following is a graph of estimated metering system performance obtained from Monte Carlo simulation over the range of conditions for which the meter is planned for use in the proposed application. The • . uncertainty values are determined at a 95% confidence level for each phase, oil, water, and gas flow rates. V 16% CD — Oil Rate 1.3 14% — - Water Rate —6— Gas Rate V 12% 0 c 10% - O' 8% \ • o O ri c 4% - - • ( 2% -- " = = _ -- c v 0% I I ! I I I I I I I I I D` .$3 kb NC) g Ng' NC") NC!) 19 A A The conditions used to compute the above are: • Operating Pressure = 300 psi • Operating Temperature = 80 deg F • Oil Density = 0.95 g /cc • Water Density = 1.03 g /cc • Gas Specific Gravity = 0.948 • Oil Viscosity = 160 cp at 89 deg F • Phase Inversion at WLR = 58% +1- 2% • High flow rate cases • Oil Density +/- 1% • Water Density +/- 1% • Gas Density +1- 2.5% • Solution Gas -Oil Ratio +/- 3% • Oil Viscosity +/- 5% • Liquid Viscosity +/- 10% • Shrinkage +1- 1.5% • The anticipated uncertainty of the well test data and overall production allocation is difficult to determine for well test allocation, but it can be controlled by performing monthly allocation balances between total custody transfer metered volumes and the sum of the well test determined volumes, as outlined in section 9. 9. Production allocation methodology Production from NU will be allocated to each producing well using a well test -based allocation method. In this method the Lease Automatic Custody Transfer ( "LACT ") meter total production volume is divided by the summation of theoretical production from all wells to determine an allocation factor ( "AF "). The AF is multiplied by the theoretical well production for each well to determine the allocated crude oil, natural gas, and produced water volumes. This method forces the summation of allocated production from all wells to equal the LACT total. The allocation factor will be calculated on a daily basis. The theoretical production for each well is determined by well test using a multiphase meter. Each producing well will be tested at least once per month. More frequent or longer tests may be conducted if the allocation quality deteriorates. As is required for the multiphase measurements, samples will be taken periodically from each well to determine the well fluid composition, API gravity, sulfur content, and water content. The well production rate is determined as the total measured volume during the well test divided by the total well test time for each well, and multiplied by a shrinkage factor, which is the fractional residual volume of oil at LACT conditions that remains after flashing a unit volume of oil from well test meter conditions. The well up -time is determined on a daily basis as the total time the well is producing during the 24 -hour period. The uptime is adjusted to account for any periods in which the well is produced with a choke setting or back pressure level different than that of the well test. The production rates from the most recent well test multiplied by the up -time will determine the theoretical volume at LACT conditions from each well each day. All data used in the allocation calculations will be validated prior to use. Validation will consist of trend analysis of well test results, daily and monthly balance monitoring (theoretical volumes compared to LACT volumes), meter performance indicators, and fluid properties data. A monthly report and file(s) containing daily allocation data and daily test data will be maintained for surveillance and available to the AOGCC for evaluation. An annual well test and allocation review report will also be generated. 10. Contingency plan in the event of meter performance failure Contingency plans are proposed for flow measurement and well testing in the event the meter system performance does not meet the expected levels, either due to mechanical or electrical impairment of metering hardware, software or system error, or well production changes such that conditions are outside the initial operating envelope of the metering system. Redundant meters have been installed at each well test manifold. In the case of failure of a multiphase meter, the second meter will be used. In the case of failure of both multiphase meters, the previously recorded well test rates will continue to be used until a mobile meter can be deployed or one of the NU multiphase meters is returned to service. If a mobile meter cannot be obtained, a mobile test separator will be used. In the event of poor allocation balance that is not due to meter failure, a thorough review of all meter input data will be conducted and new fluid samples will be obtained and analyzed. • • 11. HSE management plan The following is an overview of the primary processes proposed to manage the risks to human health and safety and environment protection. Detailed procedures for HSE are provided in the manufacturer's procedure, 6010 - 0139 -D Health, Safety and Environment Guidelines for Vx Meters. The Vx Meter has been designed to ensure that all personnel are protected from mechanical, hydraulic or electrical hazards, under normal operating conditions. Caution, however, should always be taken when working with the equipment. Only highly qualified and well trained personnel should be permitted to install and operate the meter. Note: It is critical that only the correct components, according to the Manufacturer Record Book, are used. This is not only important to guarantee proper operation of the Vx Meter, it is also essential for maintaining the certification rating of the equipment in hazardous environments. 11.1. Pressure and Hydrocarbons The Vx Meter is designed to measure hydrocarbons under high pressure. Pressure control components like Measurement Piping, Pressure Tapping and Liners are designed to operate at high pressures. After mechanical completion of the Venturi Assembly a Hydrostatic Pressure Test has been performed to ensure that the Pressure control components are functional under normal operational conditions. When dismantling the Vx Meter for inspection or repair, always consider that fault conditions may have caused pressure to be trapped as a result of seal failure. Never perform any maintenance or repair on the system unless the pressure has been completely released. In particular never try to tighten or loosen connections under pressure. After disassembly of any pressure control components a Pressure Test should always be performed according to client's specifications. The working pressure for the Vx Meter can be found in the reference Document "Interface Drawing" 11.2. Radiation Safety The Vx Meter uses a Gamma Radioactive 133 - Barium Source assembly for the fraction meter. The Source assembly is contained within the Vx Meter in such a way that external radiation is well below the requirements set forward in the EC Directive 96/29 /Euratom (1 NSv /hr at 0.1 m distance from accessible parts). The design features of the Source assembly and the safe handling procedures established for their use are safeguards that minimize the chances of a radiation hazard occurring. However, design and good safety practices alone will not protect the careless. It is imperative that operational personnel be thoroughly familiar with radioactive hazards, know and observe safe handling techniques, understand the nature of radioactivity, and have healthy respect for radioactive material. Such knowledge will help in understanding the potential hazards as well as the degree of safety that can be obtained when the radioactive material is properly handled. It will also help personnel to act properly if an emergency should occur. • . There are two potential hazards associated with the use of radioactive sources: • The biological effects of the radiation • The contamination of the environment and persons if radioactive materials are released by a leaking source. Please see ref. document Barium Radioactive Source Data Sheet for technical information regarding the Source. Please see ref. document Gamma Radiation and Source Assembly Handling Procedure for detailed procedures on source assembly handling. 11.3. General Precautions All personnel working at the site must adhere to the applicable Safety Regulations. During Source handling, the wearing of a dose rate meter is required. All disassembly work at the Vx Meter, which may expose the radioactive source, must be performed by authorized personnel only. Be aware that the Windows are "transparent" to the gamma rays, and that any removal of detector /detector housing when the source assembly is installed, will cause a severe and dangerous increase in radiation. • The source must never be dismantled from the Source Holder. • Never place your body or body parts in front of the source beam. • The Source assembly must always be stored inside its transportation box if removed from the meter, and locked with padlock. • After maintenance operations always secure the system with the Hazmat Padlocks. 12. Measurement quality assurance plan The following is provided as a description of the routine daily and monthly control processes that are proposed to maintain measurement quality. The aim of these procedures is to minimize uncertainties and biases in the multiphase flow measurements. These procedures are based on manufacturer's guidelines and API RP 86, where applicable. The preventative maintenance steps outlined in section 13 are an integral part of the quality control plan. A proper functioning meter is a primary requirement. In addition to hardware performance, the other important aspect of measurement quality control is fluid parameter accuracy. These two components of the quality control plan, hardware performance and fluid parameters, are discussed below. The meter makes five raw measurements. These are pressure, temperature, Venturi differential pressure, gamma counts at low energy, and gamma counts at high energy. To ensure the meter hardware is performing well, the pressure, temperature and differential pressure transmitters, and the gamma densitometer need to be checked periodically. The maintenance steps in section 13 are sufficient to • . ensure that all transmitters are performing within specification, or get replaced if out of specification. This includes monthly checks and annual calibrations. To verify performance of the gamma densitometer there are two actions to take. The first is to monitor daily for alarms from the detector. Alarms can indicate malfunction or a need to reset the detector, perform a peak search or other steps. The second is to make routine empty pipe reference measurements. These are prescribed to be quarterly to provide a record of gamma counts at each energy level and total counts to compare against count predictions based on theoretical decay rate. Observed gamma counts should be within 0.5% of theoretical predictions every quarter. Also, the ratio of low energy to high energy should remain constant. A good empty pipe measurement is evaluated by the software during the recording period. If a empty pipe measurement is successful, and matches predictions, then it can be reasonably concluded that the gamma detector is in proper working order. Without accurate fluid properties, the multiphase meter is capable of making useful relative flow rate measurements. In other words, changes in rates are in the right direction and relative magnitude, but the actual values may not be accurate. Accurate flow rates require accurate fluid properties, which begins with sampling. Gas and liquid samples will be taken from dedicated sampling points. Sampling and analysis procedures will follow API recommended practices and ENI company procedures. The primary measurements that are monitored for measurement quality control are: • Density of oil, water and gas at standard conditions • Gas composition • Oil viscosity at standard conditions • Oil -water emulsion viscosity (if obtainable) • Manual Basic Sediment & Water (BSW) When changes in oil or gas properties occur, an updated oil in -situ reference measurement and gas reference calculation are required. There procedures are referenced in section 13. On oil samples taken for in -situ reference measurement, the following are also recorded: • Oil sulfur content • Water in oil content The record keeping and reporting for these procedures is given in section 13. 13. Meter maintenance plan The following table summarizes the proposed systematic maintenance of the metering system. The maintenance methods are described in the referenced documents from the manufacturer as listed in the second column. The maintenance frequency is provided in the third column. This table includes both preventative maintenance and calibration. Activity Description Ref. Document Routine Maintenance Visual Inspection 6527- 0050 -D User Manual Monthly Software updates 6010 -010 -D Service Computer As new releases are available SW User Manual Transmitter check and zero trim 6010 -010 -D Service Computer Monthly SW User Manual • Empty pipe reference 6010 -010 -D Service Computer Quarterly (3 months) measurements SW User Manual, Empty Pipe Reference Measurement Procedure Fraction meter reference 6010 -010 -D Service Computer Semi - annually, and immediately measurements SW User Manual, In -Situ Fluid after any reasonable change in Reference Measurement fluid composition. Procedure Fluid and gas properties update 6010 -010 -D Service Computer Semi - annually, and immediately SW User Manual, 6009 - 1567 -D after any reasonable change in Well Independent Input fluid composition. Parameters Data Sheet, 6010 - 0268-D Vx Fluids ID Procedure, 6010 - 0271 -D Vx Fluids ID Process Overview and Inputs Requirement Source wipe test and radiation Gamma Radiation & Source Semi- annually, and immediately survey Handling, PhaseWatcher, 6010- after any suspicion of loss of 014 -D Radiation Survey pressure integrity. Transmitter calibration Transmitter Calibration Annually (except semi - annually Procedure for first year) Junction box desiccant and 6527 - 0050 -D User Manual Biannually corrosion inhibitor replacement Venturi inspection for corrosion 6527 - 0050 -D User Manual Biannually and erosion Radioactive source replacement 6009 - 1382 -D Gamma Radiation Replace source approx. every 7 & Source Handling, 6039 - 0003 -D to 10 years Multiphase Flow Meter Replacement of a Barium Radioactive Source The following is a summary of the proposed record keeping and reporting. Activity Description Record Reporting Visual inspection and remedial Checklist completed and signed, Local maintenance maintenance events log Software updates Same as visual inspection, Local maintenance events log Transmitter check and zero trim Checklist completed and signed, Local and network accessible maintenance events log database of complete historical record Empty pipe reference Service computer screen Meter DAFC, local service measurements capture, meter configuration file, computer, and network maintenance events log accessible database of complete historical record Fraction meter reference Service computer screen Meter DAFC, local service measurements capture, meter configuration file, computer, and network maintenance events log accessible database of complete historical record Fluid and gas properties update Meter configuration file, PVT lab Meter DAFC, local service report, maintenance events log computer, and network • • accessible database of complete historical record Source wipe test and radiation Wipe test record sent with Local and network accessible survey specimen for analysis, radiation database of complete historical survey, wipe test results lab record report, maintenance events log Transmitter calibration Transmitter Calibration Report, Local and network accessible maintenance events log database of complete historical record Junction box desiccant and Checklist completed and signed, Local corrosion inhibitor replacement maintenance events log Radioactive source replacement Same as empty pipe reference Local and network accessible measurements, maintenance database of complete historical events log record 14. P &IDs for SID and OPP The following table summarizes the proposed systematic maintenance of the metering system. The maintenance methods are • � ,� , • • • TRUCK CONNECTION /� Z -1301 MULTIPHASE TEST METER SKID ATTACHMENT A T a2 ONSHORE (OPP) PRODUCTION ALLOCATION METER OUTSIDE 5 _ - - - - - - - - - - - - - - D1 P01 INSIDE 4'- 10061 -D13.3 (NOTE 2) ' „� q 1 4"- 10053 - 012.3 -1P T 4 "- 10053- 012.3 -1P � IHD1P01�- 0001 -02) - — — — — — — — — — — — — — — - - - - ° TO PRODUCTION HEADER 4) — VENDOR SKID uLars T . (NOTE - (� Tx w` 4' Xt :)4• P. I Th ' (V) x — (NOTE 4) EX ES OIL GAS WATER • w � 1 4 (NOTE 3) = we gm mg NU. �(v) I I+Z' KZ kt• � r il r5 , 1 N' can ■ ®® L_-- FLOW `�'(h i - - - 'ch V o i ° A (v) (NOTE 3) OIL GAS WATER 1 4' I—V - (NOTE 5) ARC m 0 r I (NOTE 3) 1 . 4 (� NUCLE b w , (v) � ' IEM FLOW e � (V) � NM � f COMPUTER I Tr(v) (V) 0 (V) `� 4' 5'x3" I (NOTE 2) �• a$ p (') I TEST HEADER YNANA :I 0)4" (NOTE 3)— (NO 5) RTD _ PI- D1W02- 0001 -02 E I ► 4 "- 10051- D13.3T II �a ` FROM Wes PI l � x ) n 1781 I N2 O () a INJECTION WATER VGDVe$34" I • AIIA I I Z -13010 — 33/4"x1" n PI- D1P01- 0001 -02 f 2 -40015- D3.3 -1P - - - - - VENDOR SKID UNITS FROM INJECTION PUMPS n 0 N I NOTES: V 1 "- 13001 -03.3 CLOSED DRAIN 1. ALL INSTRUMENT AND EQUIPMENT TAG NUMBERS ARE PRECEDED BY "D1P01 ". PI- DiP01- 0001 -03 TO T -13020 2. INSULATION MUST EXTEND A MINIMUM OF 12' INTO THE MODULE. 3. GRAYLOC HUB. 4. GRAYLOC HUB WITH BLIND FLANGE. 5. GRAYLOC HUB WITH BLIND FLANGE & 1/2" TAP. J3327 -101 -1 REV. A 4" DUAL METER SKID P&ID (SPITZER IND.) 0 08/09 ISSUED FOR CONSTRUCTION PER GEG01 RMS AES TMF CSS DKO DKJ EMINEERING C EnI m o�eu a TITLE MKAITCHUQ OUKTOK POINT PAD ((OPP) WINO AND INSTRUMENTATION DIAGRAM ONSHORE DRILLSITE TEST METER IP01 N ) ASPIC DRAWN BY CHECKED BY: DISCIPLINE ENC. PRO.. ENG. Emory �-' J.RUIZ AES T.FRAME S.STARK DSCAELL REV. DWG.No. TITLE No. DATE DESCRIPTION OM. CHICD O. DIG P. END P. INR WENT 000RACIDR Xfif DATE SCALE REFERENCE DRAWINGS - ISSUES / REVISIONS ENQIEERINGAPPROVALS E08023 1211007 NONE PI -D1P01- 0001 -01 0 • • Z -13510 • MULTIPHASE TEST METER SKID ATTACHMENT B r iSP/049 I TRUCK CONNECTION Y V OFFSHORE (SID) > PRODUCTION ALLOCATION METER R PRODUCTION HEADER T 14' - 10501- D13.3 -3H -E PRODUCTION HEADER PI- D2W05- 0001 -03 h P►- D2P03- 0003 -01 FROM WCS TO PIG LAUNCHER _ OUTSIDE _ _ - - - - - - - - - — -- -- -- -- -- - - INSIDE D2P01 j 4 "- 10061 -D13.3 (NOTE 2) ; %,.2•Sv I > 1 4 " - 10053- D12.3 -1P T 4 "- 10053- D12.3 -1P _ _ VENDOR SKID LIMITS _ PI T (NOTE 4) I I 1351 (h In I I I 4 . : h" P" * 1 I Th" -I* — (NOTE 4) I I P I I OIL GAS WATER 1351, (y) In X Es � �O1 © � I . 4 IEii • 13529<8 IFi a I 4 '� (NOTE 3)= © TFI ` NZE I ! � Z .,� � Tr NUCLEAR , - (V) I IEC 135298 YEEM DT I I(h .I .352 � ROW I I r PDT L— ' PUTER O Q o —o o o I .352 (y) t- �� y) a PI I I I I I `, 1•1 IM (y) I I I I i • NOTE 3) 1 1 OIL GAS WATER I 4" 5 "x3' (NOTE T (NOTE 5) © RID - I �� 'Dr I (V 1.35z NM illE9 I j¢" (NOTE 3) 115 \ NM I NUC LEAR DT of) p 3 W (V) i 13521 N I I ei I - 1351 — — - -, ROW I 0 I 13515 (y) �I PDT — o m PUTER o —o0 -00 00—{0 —0 0 1 I 135U. (V 1 ®(y) II M 5 i - -� I I I ��a pp t3s n(� I I I (NOTE 2) Y4" 1 > p k!' (NOTE 3) RID TEST HEADER I VNANA U 4 10051 -D13.3 T 4" 5 "x3" ( ) T (NOTE 5) TE J N PI- D2W85- 0001 -83 II �Q 1351 (V) FROM WCS I j¢ " I i I - I 3/ %1" I J�•$VBCSC - Z-13510 VENDOR SKID LIMITS I Y:1 ="S N 1 ei o ii"O f 1 [ 7 � D Wl.y 1 tl �2 m v" CSO M v/4"4 "1- CLOSED DRAIN NOTES: - - - 1. ALL INSTRUMENT AND EQUIPMENT TAG NUMBERS ARE PRECEDED BY "D2P01 ". ' -1 PI- D2P01- 8801 -02 2. INSULATION MUST EXTEND A MINIMUM OF 12" INTO THE MODULE. • TO • T-13020 3. GRAYLOC HUB. 4. GRAYLOC HUB WITH BUND FLANGE. 5. GRAYLOC HUB WITH BUND FLANGE & 1/2" TAP. J3327- 101 -1 REV. A 4' DUAL METER SKID P&ID (SPIT7ERR IND.) A 10/09 ISSUED FOR REVIEW PER GEG02 RMS AES 1W CSS DKO DKJ ENGINEERING CONTRACTOR )/1)(45 - iii sni - -., --- -, , ,'-r,, , i, Eni Petroleum TITLE NIKAITCHUQ SPY ISLAND DRILLSITE S(ID) PIPING AND INSTRUMENTATION DIAGRAM ASRC OFFSHORE DRILLSITE TEST METER (D2P01) DRAWN BY: CHE BY: DISCIPLINE ENG. PROJ. ENG. PROJ. MGR. Gn.rpy S.rvle.. J.RUIZ AES T.FRAME S.STARK D.O'CONNELL REV. DWG.No. TITLE No. DATE DESCRIPTION DWN. CHK'D D. ENG P. ENG P. MGR CLIENT CONTRACTOR JCO# DATE SCALE DWG. NO REFERENCE DRAWINGS ISSUES / REVISIONS ENGINEERING APPROVALS E09023 10/09 NONE PI- D2P01- 0001 -01 A • • Colombie, Jody J (DOA) From: Davies, Stephen F(DOA) Sent: Wednesday, January 12, 2011 3:00 PM To: Province Robert Cc: Colombie, Jody J (DOA) Subject: RE: Eni-A10 Robert, Yes, the CO will be No. 639. I don't believe getting the order issued will be a problem. Thanks, Steve Davies AOGCC Original Message From: Province Robert [mailto: Robert .Province @enipetroleum.com] Sent: Wednesday, January 12, 2011 2:57 PM To: Davies, Stephen F (DOA) Subject: RE: Eni - AIO And will the Conservation order # be CO 639 since this is our Pool Rule CO number? Also, I think we need it before Jan 21st since this is when Eni plans to bring hydrocarbons into the facilities. Robert A. Province Land Manager - Alaska Eni US Operating Co. Inc (907) 865 -3350- Office (907) 947 -3793 - Cell Original Message From: Davies, Stephen F (DOA) [mailto:steve.davies @alaska.gov] Sent: Wednesday, January 12, 2011 2:31 PM To: Province Robert Cc: Colombie, Jody J (DOA) Subject: RE: Eni - AIO Robert, 1. The order will be AIO NO. 36. 2. No, administrative approval to inject isn't an option, but I don't believe there will be a problem issuing the order by January 21st. Steve Davies AOGCC Original Message From: Province Robert [mailto:Robert .Province @enipetroleum.com] Sent: Wednesday, January 12, 2011 2:20 PM To: Davies, Stephen F (DOA) Subject: RE: Eni - AIO 1 • • Can you provide me what the AIO number will be for the Area Injection Order? We are now giving notice to the AOGCC of our intent to bring a injection well on as first oil is within weeks and we would like to make reference to the AIO number in our format notice. Also, in the event the AIO has not been issued prior to January 21, 2011, is it possible for Eni to obtain an administrative approval to be allowed to inject, pending the official AIO? Robert A. Province Land Manager - Alaska Eni US Operating Co. Inc (907) 865 -3350- Office (907) 947 -3793 - Cell Original Message From: Davies, Stephen F (DOA) [ mailto:steve.davies @alaska.gov] Sent: Wednesday, January 12, 2011 1:41 PM To: Province Robert Cc: Colombie, Jody J (DOA) Subject: RE: Eni - AIO Robert, We have one last question for you. Concerning Exhibit 19: from your email below, it appears as though Eni does not wish Exhibit 19 to be considered by the Commission as we deliberate, yet you also state that Eni does NOT want it to remain confidential. That would mean that we are to disregard Exhibit 19, but are free to release Exhibit 19 to the public record of the hearing. Is this correct? Thanks, Steve Davies AOGCC 793 -1224 Original Message From: Province Robert [mailto: Robert .Province @enipetroleum.com] Sent: Tuesday, January 11, 2011 7:57 PM To: Davies, Stephen F (DOA) Subject: Re: Eni - AIO Steve, I apologize for the confusion. Yes, exhibit 20 is not confidential. And, Exhibit 19 is not to be considered. We were told that it can not be withdrawn, so we do not want it to remain confidential. It is our understanding that the AOGCC can not consider it for our AIO since we have not and will not prove that it should be confidential. And, Exhibit 21 "Advantek..." is not confidential now. Thank you for your assistance in this regard. Sincerely, * Sent from my Blackberry 2 . . Robert Province Land Manager - Alaska Eni US Operating Co. Inc (907) 865 -3350 - Office (907) 947 -3793 - Cell Original Message From: Davies, Stephen F (DOA) [ mailto:steve.davies @alaska.gov] Sent: Tuesday, January 11, 2011 08:53 PM To: Province Robert Cc: Colombie, Jody J (DOA) <jody.colombie @alaska.gov> Subject: RE: Eni - AIO Robert, Per your email (below) and the letter attached to it, the Commission understands that the Ivishak Water Analysis depicted in Exhibit 20 of Eni's Area Injection Order (AIO) application in not considered confidential. Eni's comments concerning Exhibit 19 are not entirely clear. Does Eni wish the Commission to disregard Exhibit 19, which depicts a schematic generic injector with DTS, during our deliberations? Or does Eni wish the Commission to consider Exhibit 19 to be non - confidential? The last bullet point of Eni's January 11, 2011 letter to the Commission states: "Consider all other submitted AIO application material as public information." Does this include Exhibit 21, the "Advanteck Study Excerpt Injector Performance Potential During Water Flood Operations" document, that was also marked as being confidential in Eni's AIO Application? Please provide guidance concerning the Commission's classification of Exhibit 21 (confidential or not), and please confirm our understanding that Eni now considers AIO application Exhibits 19 and 20 to be non - confidential. Thanks for your help, Steve Davies Sr. Petroleum Geologist Alaska Oil and Gas Conservation Commission 793 -1224 Original Message From: Province Robert [mailto: Robert .Province @enipetroleum.com] Sent: Tuesday, January 11, 2011 1:33 PM To: Davies, Stephen F (DOA) Cc: Colombie, Jody J (DOA) Subject: Eni - AIO Steve: Attached, in accordance with the Commissioner's recommendation, please find Eni's letter indicating that the water source information (exhibit 20) presented at yesterday's hearing be considered public information (remove the confidential title) as advised. 3 In addition, please consider all ther AIO application material toe titled public information. When convenient, please advise me when Eni can anticipate the Area Injection Order being issued as it is expected that first oil will be in the very near future and being able to inject water will be crucial in this regard. Regards, Robert A. Province Land Manager - Alaska Eni US Operating Co. Inc (907) 865 -3350- Office (907) 947 -3793 - Cell Original Message From: Eni US Operating Co., Inc. [ mailto :noreply @enipetroleum.com] Sent: Tuesday, January 11, 2011 1:25 PM To: Province Robert Subject: Please note the attached... Please open the attached document. This document was digitally sent to you using an HP Digital Sending device. This message may contain information that is confidential, and is being sent exclusively to the Recipient. If you are not the designated Recipient, you are prohibited from utilizing, copying or divulging the information contained in this message,or taking any action whatsoever on the basis of the information herein. If you have received this message by mistake, we ask you to kindly inform the Sender and to delete the message. It is understood that, with regard to messages sent by its network, the Company is not responsible for any statements made or opinions expressed, that are not strictly related to the Company's operations. This message may contain information that is confidential, and is being sent exclusively to the Recipient. If you are not the designated Recipient, you are prohibited from utilizing, copying or divulging the information contained in this message,or taking any action whatsoever on the basis of the information herein. If you have received this message by mistake, we ask you to kindly inform the Sender and to delete the message. It is understood that, with regard to messages sent by its network, the Company is not responsible for any statements made or opinions expressed, that are not strictly related to the Company's operations. This message may contain information that is confidential, and is being sent exclusively to the Recipient. If you are not the designated Recipient, you are prohibited from utilizing, copying or divulging the information contained in this message,or taking any action whatsoever on the basis of the information herein. If you have received this message by mistake, we ask you to kindly inform the Sender and to delete the message. 4 It understood that, with rega'•8 to messages sent by its networkhe Company is not responsible for any statements made or opinions expressed, that are not strictly related to the Company's operations. This message may contain information that is confidential, and is being sent exclusively to the Recipient. If you are not the designated Recipient, you are prohibited from utilizing, copying or divulging the information contained in this message,or taking any action whatsoever on the basis of the information herein. If you have received this message by mistake, we ask you to kindly inform the Sender and to delete the message. It is understood that, with regard to messages sent by its network, the Company is not responsible for any statements made or opinions expressed, that are not strictly related to the Company's operations. 5 0 Colombie, Jody J (DOA) From: Province Robert [ Robert.Province @enipetroleum.com] Sent: Friday, October 08, 2010 4:21 PM To: Davies, Stephen F (DOA); Colombie, Jody J (DOA) Subject: Eni Pool Rules Application Steve, The following rules are different proposed rules: West Sak Rule 7 Common Production Facilities and Surface Commingling (Restated from CO 406A)c. Each producing well must be tested a minimum of twice per month. Rule 8 Reservoir Pressure Monitoring (Restated from CO 406A)a. A bottom -hole pressure survey shall be taken on each well prior to initial sustained production or injection. This rule is more strict than our proposed rule, but Eni can live with it. This is the same language as Milne Pt Rule 7 (b). We want to amend to amend our proposed rule to align with this language. I admit our proposed rule is awkward as pointed out by Kathy. This is addressed in our Proposed Rule 6 (a). so in our response please propose the language above for Rule 6 (a). Rule 10 Pressure Maintenance Project (Restated from CO 406A)A pressure maintenance waterflood must be initiated within six months after the start of regular production from the West Sak Pool. For our drilling schedule this rule is too restrictive. We have proposed 12 months in our analogous Rule 9, which is half way between West Sak's 6 months and Milne Point's 18 months shown below. We prefer our Rule 9 language. Schrader B1uffRule 2 Well SpacingNominal 10 -acre drilling units are established for the pool within the affected area. Each drilling unit shall conform to a quarter - quarter - quarter The 1 hall not be opened in an governmental section as projected. T e poo s p y well closer than 500 feet to the exterior boundary of the affected area. (CO 255, Rule 2, modified by this order)Rule 3 Horizontal /High Angle Completions A horizontal or high angle wellbore through the pool may be completed in one or more drilling units so long as the wellbore remains 500 feet from exterior boundary of the affected area. (CO 255, Rule 3, modified by this order) These two rules address the same issue as our Rule 3 which very similar to West Sak. We like our language, as the Schrader Bluff Rules 2 & 3 seems complicated. With these rules would we have to define the drilling units for each horizontal well? Eni prefer's our spacing exception rule to these Milne Point Rules 2 & 3. Rule 7 Reservoir Pressure Monitoringa. Prior to regular production a pressure survey shall be taken on each well to determine reservoir pressure. (CO 255, Rule 7a) Eni prefers our rule on West Sak Rule 8 (a)b. A minimum of one bottom -hole pressure survey per producing governmental section shall be run annually. The surveys in part (a) of this rule may be used to fulfill the minimum requirements. (CO 255, Rule 7b)I am not sure what a governemental section is. In re- reading our Rule 9 We propose the following change in our proposed rule: Rule9: Pressure Maintenance ProjectWaterflood is required for purposes of pressure maintenance and enhanced oil recovery in the Nikaitchuq Schrader Bluff Oil Pool. Production and injection must ensure the average reservoir pressure in any isolated reservoir compartment is maintained at or above the bubble point for that respective isolated reservoir compartment. The pressure maintenance waterflood will be initiated within 1 year of the start of regular production from each drill site. Rule 8 Pool -wide Waterflood ProjectA waterflood project to maintain reservoir pressure must be implemented within eighteen months after regular production from the Schrader Bluff Oil Pool has 1 started. Water injection must b0mplemented within the expanded !kd area within eighteen months of initial production. (CO 255, Rule 8a, modified by this order)Same comment as above on West Sak Rule 10. One last issue that needs to be addressed is Rule 8. In this rule Kathy pointed our that the reference to the rule 20 AAC 25.240 (b) (1) or (2). The (2) refers to reinjection of produced gas which we do not plan to do. We plan to burn all of our gas. So please correct the language for proposed Rule 8 to read: Rule 8: Gas -Oil Ratio ExemptionWells producing from the Nikaitchuq Schrader Bluff Pool are exempt from the gas -oil ratio limits of 20 AAC 25.240(a) so long as requirements of 20 AAC 25.240 (b) (1) is met.So Robert, my recommendation is to comment propose changes to the Nikaitchuq Proposed Pool Rules as follows:Rule 6: Reservoir Pressure Monitoring(a) A bottom -hole pressure survey shall be taken on each well prior to initial sustained production or injection.(b) A minimum of one pressure survey will be taken annually in each reservoir compartment.(c) The reservoir pressure datum will be - 3,760' feet true vertical depth subsea.(d) Pressure surveys may consist of stabilized static pressure measurements (bottom -hole or extrapolated from surface), pressure fall -off tests, pressure build -up tests, multirate tests, drill stem tests, and open -hole formation tests.(e) Data and results from pressure surveys shall be submitted with the annual reservoir surveillance report. All data necessary for analysis of each survey need not be submitted with the report but must be available to the Commission upon request.Rule 8: Gas -Oil Ratio ExemptionWells producing from the Nikaitchuq Schrader Bluff Pool are exempt from the gas -oil ratio limits of 20 AAC 25.240(a) so long as requirements of 20 AAC 25.240 (b) (1) is met.Rule 9: Pressure Maintenance ProjectWaterflood is required for purposes of pressure maintenance and enhanced oil recovery in the Nikaitchuq Schrader Bluff Oil Pool. Production and injection must ensure the average reservoir pressure in any isolated reservoir compartment is maintained at or above the bubble point for that respective isolated reservoir compartment. The pressure maintenance waterflood will be initiated within 1 year of the start of regular production from each drill site. I would like to review this with you on Monday if possible. Thank you. * Sent from my Blackberry Robert Province Land Manager - Alaska Eni US Operating Co. Inc (907) 865 -3350 - Office (907) 947 -3793 - Cell This message may contain information that is confidential, and is being sent exclusively to the Recipient. If you are not the designated Recipient, you are prohibited from utilizing, copying or divulging the information contained in this message,or taking any action whatsoever on the basis of the information herein. If you have received this message by mistake, we ask you to kindly inform the Sender and to delete the message. It is understood that, with regard to messages sent by its network, the Company is not responsible for any statements made or opinions expressed, that are not strictly related to the Company's operations. 2 r W 0 1 ALASKA OIL AND GAS CONSERVATION COMMISSION 2 Before Commissioners: Daniel T. Seamount, Chairman John K. Norman 3 Cathy Foerster 4 In the Matter of ENI US OPERATING ) 5 COMPANY, has applied for Pool Rules ) for the Proposed Nikaitchuq Schrader ) CO -10 -14 6 Bluff Oil Pool in the Nikaitchuq Unit ) Beaufort Sea, Alaska in conformance ) 7 with 20 AAC 25.520 ) 8 ALASKA OIL and GAS CONSERVATION COMMISSION 9 Anchorage, Alaska 10 September 29th, 2010 9:00 o'clock a.m. 11 VOLUME I 12 PUBLIC HEARING 13 BEFORE: Daniel T. Seamount, Chairman Cathy Foerster, Commissioner 14 15 16 17 18 19 20 21 22 23 24 25 R& R C 0 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 David Moles 05 David Cook 12 3 Maurizio Grandi 40 Steve Massey 50 4 Mark Cook 84 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 R& R C 0 U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 0 1 P R O C E E D I N G S 2 (On record - 9:02 a.m.) 3 CHAIRMAN SEAMOUNT: I'd like to call this hearing to 4 order. Today is September 29th, 2010. The time is 9:02 a.m. 5 We're located at 333 West 7th Avenue, Suite 100, Anchorage, 6 Alaska. Those are the offices of the Alaska Oil and Gas 7 Conservation Commission. 8 To my left is Commissioner Cathy Foerster. I'm Dan 9 Seamount, the Chair. That's two Commissioners, that's enough 10 -- that's a quorum for making a decision. 11 If anybody has any special needs, please, see our special 12 assistant Jody Colombie way in the back. 13 R & R Court Reporting will be recording the proceeding. 14 You can get a copy of the transcript from R & R Court 15 Reporting. 16 I guess -- well, I'd like to remind anybody who is going 17 to testify, and it looks like there's a lot of them on the 18 sign -up sheet, to speak into both of the microphones so persons 19 in the rear of the room can hear and so the Court Reporter can 20 get a clear recording. 21 This is Docket No. CO -10 -14 and before I'd read it off I'd 22 like to -- this is one of the most important parts of the 23 hearing, the pronunciation is Nikaitchuq. 24 MR. MOLES: Very good. 25 CHAIRMAN SEAMOUNT: Nikaitchuq, okay. Not Nikaitchuq, R& R C 0 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 0 1 Nikaitchuq, okay. That is ENI US Operating Company has applied 2 for Pool Rules for the Proposed Nikaitchuq Schrader Bluff Oil 3 Pool in the Nikaitchuq Unit, Beaufort Sea, Alaska in 4 conformance with 20 AAC 25.520. 5 Notice of this hearing was published on August 27th, 2010 6 in the Anchorage Daily News, as well as the State of Alaska on- 7 line notice and AOGCC website. This hearing will be held in 8 accordance with 20 AAC 25.540 of the Alaska Administrative Code 9 and will be recorded. 10 Take a look at the sign -up sheet, one, two, three, four, 11 five, six, seven, at least seven people wish to testify today, 12 maybe eight and it looks like they're all the applicant, okay. 13 One thing I'll say before we get started is we're a state 14 agency and the presumption is that anything that's filed with 15 us is not confidential unless you can demonstrate that it 16 should be confidential so I'd like you to keep that in mind if 17 you've got some stuff that you want to be kept confidential let 18 us know and we'll make a ruling on it. 19 So we will start with the applicant and the applicant ENI 20 decides who goes first on this, so who is going first? okay. 21 Raise your right hand, please? 22 (Oath Administered) 23 MR. MOLES: I do. 24 CHAIRMAN SEAMOUNT: And do you wish to be considered as an 25 expert witness? R& R C 0 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 0 0 1 MR. MOLES: Yes. 2 COMMISSIONER FOERSTER: Do you want to explain what that 3 means so we don't do the same little..... 4 CHAIRMAN SEAMOUNT: An expert in some technical part of -- 5 I mean, if you're going to be discussing, like, petroleum 6 engineering or the petroleum geology aspect of this, then we 7 give greater weight if you're an expert witness or if you 8 aren't, okay. So then please give us your name, who you 9 represent, what the discipline is that you wish to be 10 considered an expert witness on and your qualifications. 11 DAVID MOLES 12 called as a witness on behalf of ENI US Operating Company, 13 Inc., testified as follows on: 14 DIRECT EXAMINATION 15 MR. MOLES: Okay. My name is David Moles. I work for ENI 16 US Operating Co., Inc. here in the Alaska office which is a 17 remote office to our headquarters in Houston. I have a history 18 in facilities engineering and project development so that would 19 be my area expertise and most of my comments though will tend 20 to be more general. 21 I'm ENI's representative here in Alaska. I'm the 22 development manager for Nikaitchuq. I've worked on the project 23 for a number of years from it's conception to its current 24 status. I have 38 years in the oil industry in every area you 25 can think of from a development viewpoint, refining, R& R C 0 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 0 0 1 petrochemical, transportation. More recently Gulf of Mexico 2 deep water. And for the last four years Alaska and the North 3 Slope. 4 I've worked for a number of different oil companies in the 5 past. And I moved here about two and a half years ago to open 6 the office for ENI here in Anchorage. 7 I have a Bachelor of Science Degree from the University of 8 Nebraska in Civil Engineering and an MBA from the University of 9 Texas. I'm here this morning to make an introduction and 10 overview of the development. 11 CHAIRMAN SEAMOUNT: Okay. Well, you said you had a 12 Master's Degree from UT? 13 MR. MOLES: Yes. 14 CHAIRMAN SEAMOUNT: That will help you. Commissioner 15 Foerster, I apologize, I didn't give you the opportunity to 16 make any statement before we started so, first of all, do you 17 have any statements and second of all do you have any objection 18 to Mr. Moles be considered as an expert witness? 19 COMMISSIONER FOERSTER: First I'd just like to state that 20 I'm happy to see that ENI is moving forward and about to start 21 production at Nikaitchuq. And I hope that you guys have 22 received guidance from our Staff in working through our process 23 so that we haven't been a burden to you. And our job is to 24 regulate and make sure that you follow all the rules, but not 25 to plan got cha or make it difficult for you to be successful, R& R C 0 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 • M 1 so I hope that's been your experience. 2 And, you're right, Mr. Moles saved himself with that MBA. 3 No, I have no objections to accepting him as an expert witness. 4 CHAIRMAN SEAMOUNT: Okay. Mr. Moles, you are designated 5 as an expert witness in the discipline of facilities 6 engineering. Please, proceed. 7 MR. MOLES: Okay. Well, I want to thank you for the 8 cooperation we have received in preparing for this. As you 9 know this is our first full on venture in Alaska and it's quite 10 different than our operations in the Gulf of Mexico from which 11 many of us stem, so we appreciate the cooperation we've 12 received from the AOGCC. And I want to thank you and the 13 committee members for inviting us here today. 14 As you know we've submitted an application for pool rules. 15 We submitted that on August the 19th of this year and we would 16 ask that you look favorably upon our request and our 17 application for those rules. 18 With that said I'd like to give you a little background on 19 the project. So Nikaitchuq is a viscous oil, marginal field 20 and by marginal that means it has a marginal economic incentive 21 to it. It's in the development cycle so it's passed through 22 exploration appraisal and a feed. In this project we're going 23 to produce an oil that's about 19 degree API gravity, very 24 viscous and we're going to do it from an area that's about 25 3,400 acres. R& R C 0 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 • M 1 A unique aspect here for ENI and our learning effort is 2 that this is a 100 percent project. We have no partners and it 3 will be a new venture in Alaska for a producer, processor, 4 transporter, seller of Alaskan production. So in that regard 5 we've moved ahead with the construction of both an offshore 6 drill pad which you can see in the photo (page 3). 7 This is one of the largest ones to date in the Beaufort 8 and we have build an onshore processing center which you can 9 see in the upper photo which is right near with seawater 10 treatment plant for Kuparuk at Oliktok Point. 11 So I'll walk through in a few minutes the schedule and, 12 kind of, the history of the project, but first production is 13 targeted for last this year, early next year from the onshore 14 wells. And you'll hear more about those in the future. We're 15 doing that in a staged event so that we can take the learnings 16 we get from the onshore wells where we're trying a number of 17 different completion styles and apply that to our larger number 18 of wells offshore. 19 The offshore production is scheduled to begin before the 20 end of next year. So the gross peak flow rate of 28,000 21 barrels a day is what we've used to evaluate the project 22 internally. We've designed the facilities for a capacity of 23 40,000 barrels a day. We would like to hope for an upside and 24 if not we have allege (ph) in the facility for other purposes. 25 The productive life that we've used in our evaluations is R& R C 0 U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 8 0 0 1 30 years although as a function of oil price, technology and h performance of the field with our water injection and inj 2 the e J P 3 cycling the field life could extend well beyond that. 4 The total development consists of 52 wells with 19 5 onshore, the majority offshore. 6 Here's a slide that walks you through how this project 7 comes to be where it is. (Page 4) In 2008 we authorized the 8 project for $1.5 billion and proceeded to build a gravel drill 9 site offshore and a gravel production site onshore. 10 CHAIRMAN SEAMOUNT: Mr. Moles, do we have a hard copy of 11 these slides and do you wish to enter them into the record? 12 MR. COOK: Sure. 13 MR. MOLES: Yeah, that will be fine. 14 CHAIRMAN SEAMOUNT: Okay. 15 COURT REPORTER: May I get one of those, please. 16 CHAIRMAN SEAMOUNT: And as you go along could you state 17 which exhibit you're talking from. 18 MR. MOLES: Okay. 19 CHAIRMAN SEAMOUNT: We just got through with exhibit 1 and 20 now we're on exhibit 2? 21 MR. MOLES: Correct. We're on exhibit 2. 22 CHAIRMAN SEAMOUNT: Thank you. 23 MR. MOLES: So the overview here is simply to say that we 24 started in 2008. We've taken a staged approach. We slowed the 25 project down a little bit in 2009. As you'll recall there was R& R C 0 U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 9 • 0 1 quite a change in the oil price and industry activity in that 2 period and we re- authorized the project at the first of 2010, 3 this year raising the level of funding to $2 billion. 4 So in that time we've completed the offshore pipeline 5 which is a bundle of pipe -in -pipe for oil production. We have 6 completed the onshore pipeline. We have built two 4,000 ton 7 modules in Louisiana which you'll see in a minute. And those 8 have been successfully shipped and off loaded and put in place 9 on the North Slope at our production center at Oliktok Point. 10 We've had every shop in Anchorage busy building onshore 11 truckable modules and those for first oil onshore are all now 12 delivered to the Slope. So we're currently in the process of 13 doing mechanical completion in an integrated way between 14 construction, functional check out and commissioning, again, 15 with our objective to deliver first oil by the end of the year 16 or early next year. We all know how those activities can go. 17 So we have a great team on the Slope. We have over 1,200 18 people employed in Alaska working in various phases of the 19 project. 20 At the bottom of exhibit 2 is a slide that shows a number 21 of wells that have been drilled successfully to day by ENI and 22 we acquired the project in 2007. We picked up Kerr- McGee's 23 original interest that had been transferred to Anadarko when 24 Anadarko acquired Kerr - McGee, that came with two wells and 25 since then we've drilled a number of wells at the bottom. R& R C 0 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 a 0 1 We're focused on drilling producers so that we have enough 2 capacity to fill the pipeline to keep our production warm when 3 we start out initial sales. And we have an injector that we're 4 working on now and you can see then the wells in green that are 5 yet to be drilled this year. 6 So turning to exhibit 3 (page 5), this is simply some nice 7 photography of our utility module being towed to Oliktok Point. 8 In the lower right you can see Oliktok Point. In orange is the 9 KRUC water treatment plant as the module approaches the dock 10 there to be off - loaded. Fortunate for us our production area 11 is immediately adjacent to the docks so the transport of the 12 modules was a short event. 13 We will be self- sufficient in every regard except the 14 provision of fuel gas which we are working to acquire now from 15 the KRU, the Kuparuk River Unit. 16 That being said that's a highlight of the project and how 17 it comes to be. You mentioned we have a number of other people 18 to testify. I'll turn it over to David Cook. He's our 19 reservoir project manager and he'll take us through more 20 detail. 21 CHAIRMAN SEAMOUNT: Okay. Before we proceed, Commissioner 22 Foerster, do you have any questions at this point? 23 COMMISSIONER FOERSTER: I have some questions, but I was 24 going to -- I think they're more appropriate for Mr. Cook so I 25 was going to save them for him. R& R C 0 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 1 1 CHAIRMAN SEAMOUNT: Okay. And the other thing is it looks 2 like we've got quite a few people that want to testify. Maybe 3 we should swear them in all at the same time now. So anybody 4 that's going to testify, please, raise your right hand. 5 (Oath Administered) 6 IN UNISON: I do. 7 CHAIRMAN SEAMOUNT: Thank you. Okay. Was that 8 appropriate, Mr. Assistant Attorney General? 9 MR. BALLANTINE: It will be a little tough to tell who's 10 been sworn when you have so many. (Indiscernible - away from 11 microphone) that come forward sort of say your swore. 12 CHAIRMAN SEAMOUNT: Okay, all right. So maybe I was a 13 little bit inappropriate, but we'll get over it. Okay. Next 14 -- the expert here is laughing at me. 15 (Side conversation) 16 CHAIRMAN SEAMOUNT: Okay, next please. 17 DAVE COOK 18 called as a witness on behalf of ENI US Operating Company, 19 Inc., testified as follows on: 20 DIRECT EXAMINATION 21 MR. COOK: My name is Dave Cook. I'm the Alaska reservoir 22 manager for ENI US Operating here in Alaska. I received a 23 Bachelor of Science from the University of Texas at Austin in 24 1991. Since then I've worked mostly in Texas, but the last two 25 years here in Alaska on this project. I've also had some R& R C 0 U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 12 1 international experience. I've been with ENI for five years 2 and like I said before this I was working deep water in Texas 3 and also the shelf in the Gulf of Mexico. 4 I've testified as an expert in the -- in Texas before the 5 Railroad Commission, in Mississippi before the Mississippi Oil 6 and Gas Board and also in Texas State Court. I have 7 represented ENI in a hearing before the MMS in New Orleans 8 prior to moving to Alaska and I'm also a registered 9 professional engineer in Texas. 10 I'd like to be acknowledged as an expert witness in the 11 field of petroleum engineering and with a specific expertise in 12 reservoir engineering. 13 CHAIRMAN SEAMOUNT: Commissioner Foerster. 14 COMMISSIONER FOERSTER: You said you has a BS Degree, but 15 you didn't say which kind of engineering. Is it petroleum 16 engineering or..... 17 MR. COOK: It's petroleum engineering, yes. 18 COMMISSIONER FOERSTER: Thank you. I have no problems. 19 CHAIRMAN SEAMOUNT: Okay. When did you testify in front 20 of the Railroad Commission? 21 MR. COOK: I used to work as a -- with a consulting firm 22 in Austin, Texas and did several field rule hearings, spacing 23 exceptions, things of that nature. 24 CHAIRMAN SEAMOUNT: Within the last few years? 25 MR. COOK: Oh, probably five or six years ago before I cam R& R C 0 U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 13 1 to ENI. 2 COMMISSIONER FOERSTER: Which consulting firm? 3 MR. COOK: Platt, Sparks (ph) and Associates. 4 CHAIRMAN SEAMOUNT: Did you know Victor Coreo (ph)? 5 MR. COOK: I think I might have been either before him or 6 right when he was coming in. 7 CHAIRMAN SEAMOUNT: Okay. He's a good friend of ours. 8 Okay. You are so by -- so by -- here by designated as an 9 expert witness in the field of petroleum engineering. Please, 10 proceed. 11 MR. COOK: Thank you. Exhibit 4 shows an agenda for 12 today's presentation. (Page 7) We do have several people 13 signed up as experts, but we primarily only have three 14 scheduled to give this presentation, with additional experts as 15 needed for question and answer. 16 So as Mr. Moles stated we submitted an application for 17 pool rules in August 19th and most of that is still intact. 18 There's some wording differences for some of the requested 19 rules that we'll show today later on in the presentation. 20 Just to give you an outline of who will be speaking, I 21 will be discussing generally the exploration strategy for the 22 reservoir, also speak more detail about the geology and the 23 reservoir engineering. Followed by Mr. Maurizio Grandi who is 24 our -- he'll talk about drilling and completion. Then Steve 25 Massey our production manager will talk about operations and R& R C 0 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 • 0 1 facilities in a little more detail. And then I will come back 2 to show the text of the requested rules. 3 Then I suspect we'll have some question and answer for 4 this presentation, this main presentation. We also have some 5 confidential exhibits that, if necessary, we can go into that 6 we believe are more interpreted, more specific on the geology 7 and reservoir side so I'll let you decide how we'll handle 8 those. 9 COMMISSIONER FOERSTER: Those confidential exhibits are 10 part of the packet that you handed the Court Reporter..... 11 MR. COOK: Yes, ma'am. 12 COMMISSIONER FOERSTER: .....and if we choose either not 13 to use them for this hearing or to grant them confidentiality 14 then the monkey is on your back to get those back from here. 15 MR. COOK: Okay, thank you. So exhibit 5 (page 8) is a 16 map just showing the location of the Nikaitchuq Unit. It is 17 outlined here in red just to the northeast of the Oooguruk 18 Unit. It's completely within state waters obviously since 19 we're here at the AOGCC. Below us here to the south is the 20 Kuparuk River Unit and the other nearest unit is the Milne 21 Point Unit just to the southeast. 22 Exhibit 6, (page 9) is schematic showing the basic concept 23 for the development of the -- of our reservoir. And Mr. Moles 24 explained this in -- as an overview, but basically what we have 25 is an offshore -- and onshore processing facility and on R& R C 0 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 onshore drilling site connected also to an offshore drill site 2 island. This is called Spy Island drill site or SID. The 3 onshore drill site is called OPP which is Oliktok Point pad. 4 And then there's also an operations camp supporting the 5 processing facility and the drilling. All of this is connected 6 by a 14 mile pipeline to TAPS. 7 All this is being built to support a development of a 8 Schrader Bluff reservoir. The main target is a sand we call 9 the OA sand and we also have some minor accumulations in the 10 Sag River, but that's not part of the development right now. 11 Just up hole from the OA is another Schrader Bluff sand 12 called the N -sand which is a -- for us is a future potential 13 resource. 14 Okay. Exhibit 7 (page 10) is a little bit out of my area, 15 but I thought we would just touch on the evolution of the unit. 16 The Nikaitchuq Unit originally was the pink area -- or the 17 orange area, sorry, over here to the east and this map shows 18 the ownership as of 20- -- January of 2007. Originally ENI got 19 into the unit by purchasing the interest from Armstrong Oil & 20 Gas becoming a 30 percent owner in the unit. 21 We also at the time became a partial owner in the Tuvaaq 22 leases which are here in purple. Followed by a farm (ph) in 23 with -- along with Kerr -McGee to this Kigun lease here. So 24 subsequent to this (indiscernible) we now have jumped forward 25 to our current ownership which is 100 percent ENI and let me R& R C 0 U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 16 9 0 1 tell you a little bit about how we got there. 2 COMMISSIONER FOERSTER: That's exhibit 8? 3 MR. COOK: I'm sorry, exhibit 8, yes. I've moved to 4 exhibit 8. (Page 11) 5 So I'm not sure -- let's see, in July of 2006 the parties 6 agreed to assigned a consistent interest across the entire unit 7 so Kerr -McGee was going to be operator with 70 percent and then 8 ENI would have 30 percent. And then in January 2007 ENI 9 acquired Kerr -McGee or, I think, at that time was Anadarko 10 interest 70 percent. It became the operator and 100 percent 11 working interest owner in the unit. 12 Exhibit 9 (page 12) is a base map showing all of the wells 13 that we could come up with in the public record, off lease 14 along with all of the wells that are -- either have been 15 drilled or are currently active on the unit. The unit outline 16 is shown in a light color. It is -- the Barrier Islands are 17 also shown here, this is Spy Island, Barrier Island and this is 18 Thetis island over here. You can see Oliktok Point, the 19 shoreline just to the south of the map where our drill site is 20 and so all of our drilling is going offshore under the state 21 waters of the Beaufort Sea. 22 Just as an orientation the pad just to the south of us is 23 KRU 3R and to the southeast is Milne Point F pad. There are a 24 few L pad wells coming in here from off the map. 25 I'd also like to use this map to give you a rundown of the R& R C 0 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 s �► 1 drilling history, the appraisal history of the unit. Back in 2 2004 and 5 these Nikaitchuq wells were drilled, number 1 and 3 number 2. Number 1 was here and number 2 was here. Then in 4 the winter of 1 05/06 some additional appraisal was done at this 5 site with the Nikaitchuq 4 well and the Nikaitchuq 3 well. The 6 Nikaitchuq 3 tested the Sap River. The Nikaitchuq 4 was a 7 dedicated test appraisal for the Schrader Bluff in the OA sand. 8 Also that year the Kigun and Tuvaaq wells were drilled. 9 The OA penetration is -- for both of these wells is very near 10 the Kigun. This was a deeper test, the Tuvaaq was a deeper 11 test so the bottom hole location was out to the northwest. 12 When -- this was all done prior to ENI's involvement. 13 Then ENI became involved in the project and along with Kerr - 14 McGee as operator the OPI 2 horizontal well was drilled as an 15 appraisal well and the OPI 1 pilot hole was drilled as an 16 appraisal well in the winter of 2006 and 7. Those wells, the 17 information gathered from those wells included a well test and 18 also some fluid data and was along with the geology and the 19 facilities work was the basis of design and basis of approval 20 for the project, so we sanctioned the project and started 21 working on the execution phase. 22 We drilled in 2008 the first development well which was a 23 disposal well and it is located right here in the southern part 24 of the unit. Followed by a producer which was our first 25 horizontal well, was the OP03 -PO5. I'll tell you about the R& R C 0 U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 18 s 0 1 naming (ph) convention in just a minute. And then subsequent 2 to that we have restarted drilling in April of 2010 and it had 3 some nice success drilling several wells this year. 4 Okay. Exhibit 10, (page 13) is a drilling lateral drain 5 hole map. It shows all of the planned wells, development 6 wells, both injection and producing wells for the project. The 7 green wells are the producing wells and the blue wells are the 8 water injection wells. This is a water injection project. No 9 gas injection or any other FOR techniques. This is strictly a 10 water flood. 11 So the wells along the southern part of the unit will be 12 drilled from Oliktok Point OPP and they include 10 producers, 13 eight injectors and one disposal and then we will also drill up 14 to three water source wells to support both our facilities 15 design and also our water flood. 16 There's one other well, the OPI2 which was an appraisal 17 well shown here in the central -- southern central part of the 18 map was left as a producer and will be converted to an 19 injection well and used in the development. 20 The water source is the Ivishak formation. I won't talk 21 about that today too much. This hearing is about the Schrader 22 Bluff oil pool so -- but we will be using Ivishak for the water 23 source. 24 At Spy Island, like David Moles said, the bulk of the 25 drilling will occur from Spy Island which is shown here as a R& R C 0 U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 19 M 1 gravel pad that has been built and is currently under 2 construction. 3 The total well count for the whole project is 52 wells 4 including 26 horizontal wells, 21 injection wells. At Spy 5 Island we'll have 16 of those producers from Spy Island and 6 then 13 injectors from Spy Island. And the first well we'll 7 drill on Spy Island will be a disposal well which will dispose 8 of all the cuttings from that SID drill site. 9 CHAIRMAN SEAMOUNT: Mr. Cook, what's the lateral length of 10 those wells, is it about 2,500 feet per well? 11 MR. COOK: No, actually the shortest wells we're drilling 12 are approximately 4,000 feet and our technical limit is 13 approximately 8,500 feet, so some of these longer wells are 14 planned to be 8,500 feet or so. 15 CHAIRMAN SEAMOUNT: Thank you. 16 MR. COOK: One other note currently we have designed a 17 spacing of 1,200 feet between wells, so this is essentially a 18 line drive pattern with 1,200 feet spacing between the 19 horizontals. 20 Exhibit 11 (page 14) is a zoom in on the Oliktok Point 21 area showing our current drilling progress. All of the green 22 wells are wells we have drilled since the project has been 23 sanctioned. I mentioned the OP03 -PO5 shown here and then all 24 of the other green wells have been drilled this year. 25 Our naming convention is to indicate which drill pad it's R& R C 0 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 0 • 0 1 drilling from first, with the first letter, so O stands for 2 Oliktok Point. The second letter is whether it's a producer or 3 injector, P for producer, I for injector. Then we put the slot 4 number of the drill pad so -- or the well containment shelters 5 so, for instance, this well is the OPO4 well slot and then -07 6 is a notional reservoir drain hole that we've designed in our 7 reservoir modeling so we kept that for consistency, but that's 8 what the last two numbers refer to, a well name for the 9 reservoir. 10 So for injection well we're currently drilling this red 11 well here in the central part of the field and it's name is OP- 12 -- I'm sorry, 0I11 -01, so it's an injection well from Oliktok 13 Point from the 11 slot and it is the first drain hole as we've 14 defined in our model. 15 Okay. So back to our lease map, this is exhibit 12, (page 16 15) and it shows the proposed pool area. We have reason to 17 believe that the Schrader Bluff pool extends across the entire 18 unit so we are requesting the entire unit as the definition of 19 the Nikaitchuq Schrader Bluff oil pool. 20 Exhibit 12, (page 16) shows the Kigun type log well to 21 give you the interval that we're requesting for the Nikaitchuq 22 Schrader Bluff oil pool. The Kigun well is a public well and 23 the interval is defined as the top of the Schrader Bluff which 24 is also the top of the cretaceous and then the base is 25 approximately 45 feet below the base of the correlative OA R& R C 0 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 • 0 1 sand. If you want me to read in the depths on the Kigun it is 2 measured depth..... 3 COMMISSIONER FOERSTER: That's okay, if this is going to 4 go into the public record. 5 MR. COOK: It will go in the public record. 6 COMMISSIONER FOERSTER: That's fine. 7 MR. COOK: Okay. 8 COMMISSIONER FOERSTER: As long as you refer to which 9 exhibit you're talking about then -- and the exhibit is going 10 to be in the public record..... 11 MR. COOK: Okay, thank you. 12 COMMISSIONER FOERSTER: .....we're good. 13 MR. COOK: So on this type log just to let you know there 14 are two main sand packages that we've discovered across the 15 unit. One is called the N sand which is a little bit -- about 16 100 to 150 feet above the primary target for our development 17 DOA sand. The N sand has some uncertainty attached to it and 18 so we are characterizing it as a resource right now and we will 19 continue to work on appraising it and determine whether it has 20 any development potential in the future. 21 Okay. This slide is not an exhibit, (page 17) it's just a 22 transition slide to -- I'll going to talk a little bit more in 23 detail about the geology and the reservoir itself now. 24 And just to let you know as I've said in my opening that 25 I'm a reservoir -- a petroleum engineer by trade mostly in the R& R C 0 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 • 0 1 reservoir engineering field. I'll be showing some geology and 2 some geophysics so I do have the project geologist and 3 geophysicists here if there are more detailed questions that 4 you have later we can bring them up. 5 COMMISSIONER FOERSTER: We won't recognize you as the 6 geological expert. 7 MR. COOK: Thank you. 8 CHAIRMAN SEAMOUNT: But reservoir engineers should know 9 geology. 10 COMMISSIONER FOERSTER: Or at least a good geologist. 11 CHAIRMAN SEAMOUNT: Or a good geologist. 12 MR. COOK: Okay. So exhibit 14 is just a general North 13 Slope Strategraphic column and it points to the general age of 14 the Schrader Bluff at the late period of the cretaceous. At 15 the time the source of the sediments was from the southwest and 16 towards this direction the Schrader Bluff is interfingering 17 with the marine or marginal marine sediments of the Prince 18 Creek formation. 19 Toward the base and far from the sediment source the 20 Schrader Bluff is interfingering with the deeper marine shales 21 of the Canning formation. 22 Exhibit 15 (page 19) shows outlines of our seismic data 23 that we have. The gray boxes show both the Thetis Island 3D 24 and the Simpson Lagoon 3D. Both of these are legacy 3D data 25 sets that we have acquired and used to help sanction the R& R C 0 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 3 1 project. 2 As a part of the sanction we also agreed to acquire 3 another -- a seismic survey in 2008. We refer to it as the PGS 4 OBC 3D seismic survey and it is shown highlighted in purple. 5 And as you can see it covers -- there was a hole in the 6 development not covered by the original seismic and we covered 7 that hole and a lot of our reservoir work is based on this PGS 8 OBC 3D survey which was specifically designed for the Schrader 9 Bluff as opposed to the Thetis Island and the Simpson Lagoon 10 which are really designed for deeper targets such as the 11 Ivishak and the Sag River. 12 There's one other 3D volume that we know about called the 13 WBA Kalubik, but it was not -- it's in the southern part of the 14 area, but it was not used due to poor signal quality. 15 Okay. Exhibit 16, (page 20) is a seismic based structure 16 map on top of the OA and I've quite a few points to make on 17 this slide so we'll stay on it for a minute. First of all it's 18 a gently dipping monocline from the southwest to the northeast 19 meaning it's going down depth to the northeast. The Schrader 20 Bluff occurs at levels from 3,000 to 5,000 feet subsea on this 21 map. There are some normal faults trending generally northwest 22 to southeast and they're related to the cretaceous extension of 23 the Beaufort Sea. 24 Some up dip wells here off the structure map, Thetis 25 Island, Oooguruk, and East Harrison Bay show either very little R& R C 0 U R T R E P O R T E R S 811 G STREET (907)277 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 24 1 or no sand at the AO level so that we know there's a 2 strategraphic pinch somewhere between our appraisal wells and 3 these off unit wells. Luckily the PGS data set helped us 4 define that boundary and it roughly follows this complex of 5 faults here on the western side edge of the unit. 6 Okay. To the northward we have no reason to believe that 7 the sand doesn't continue at least to the unit boundary and 8 beyond. We don't have any well control or very good seismic up 9 in this area, but our depositional models tells us that we have 10 a prograding deltaic system going to the north and so we fully 11 expect there to be and have planned for there to be OA sand and 12 hopefully also N sand in the northern part of the unit. 13 To the south and east we believe the Schrader Bluff does 14 not stop. It continues on and is very similar to the Milne 15 Point Schrader Bluff oil pool and the KRU West Sak pool. 16 In terms of confining formations the top confining 17 formation is the shale between the lower Ugnu and the N sand. 18 The thickness of this confining shale is 50 to 100 feet thick. 19 The bottom confining zone is the Canning Hue shale and it's 20 very thick, over 2,000 feet. 21 Now, the faulting here, we characterize these are obvious 22 seismic faults that are quite easily seen and mapped on the 23 seismic data with several lines of consistent throw. We know 24 that there are other faults. We have encountered them during 25 the drilling, the sheer, but right now these major faults which R& R C 0 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 0 1 can have throws of -- from 20 feet up to 80 feet and then, of 2 course, they pinch out to zero according to zero according to 3 this map, we know that some of those faults can take the sands 4 so that they're not in communication and could create 5 compartments. 6 We don't have any compartments defined on this map, but as 7 we drill we'll learn more and probably define some compartments 8 in the future. We do know from fluid data that there's a 9 likely at least two compartments and I'll talk about that a 10 little bit more later. 11 Okay. Exhibit 17, (page 21) is just a sedimentological 12 concept of the OA reservoir. Starting from the bottom the base 13 of our reservoir is a distal prodelta system and then the 14 overlaying deposits are a mixture deposition of system shelfal 15 lobe separated by some shales or shalier, silty intervals and 16 this is the OA that we're showing here so we have a main level 17 here at the base called the OA3. It tends to be our best 18 level, our best interlayer. The middle layer is more silty, 19 but certainly is reservoir and the upper layer we refer to as 20 the OA1 is also quite good, although a little thinner than the 21 OA3. 22 One thing to note is even though there is some -- the 23 yellow does not show continuity between the three, we believe 24 all three of these are in perfect communication. If not for a 25 little bit less, lower quality in these more silty 'cause that R& R C 0 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 one's in between. 2 Exhibit 18 (page 22) is another base map. I've cleaned it 3 up, taken off many of the points that you saw on Milne Point F 4 pad and KRU. This represents the data set that we used to 5 develop our geologic model and characterize the reservoir. 6 Below the map we have some general parameters for reservoir 7 properties such as gross thickness, porosity, net -to- gross, 8 water saturation and permeability. 9 Generally the OA reservoir is about 30 to 40 feet thick 10 with porosities ranging from 25 to 35 percent. Water 11 saturation is 23 to 45 percent, but the 45 percent is likely in 12 a transition zone near the oil /water contact. And permeability 13 is in the range of 100 to 600 millidarcies. 14 One thing that I didn't notice -- I didn't show you on the 15 structure map and maybe I'll go back to it on exhibit 16, there 16 was -- the oil /water contact that we know about was discovered 17 in the Nikaitchuq 2 well just off the unit to the east and it 18 is at negative 4177 TBD subsea. If you follow that along in 19 the northern area is to the northeast would be considered water 20 and an aquifer. Most -- all of the development is obviously 21 within the oil column. 22 Up to the north based on compartments we may have oil up 23 there even below the contact that we know about. We're not 24 sure if this area is isolated or not, but for the purposes of 25 the sanction we've assumed a contact across the entire R& R C 0 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 0 0 1 structure at negative 4177. 2 Now back on tract to exhibit 19, (page 23), exhibit 19 is 3 an OA thickness map and this represents our base case so we do 4 have different interpretations or different realizations of our 5 thickness. This is what we consider to be very representative. 6 It has the contour -- the contour shown on the map represents 7 two feet and the color scale is from 20 to 48 feet, so 20 feet 8 is the blue and 48 feet is the red. 9 One thing to note is we can't resolve thickness from the 10 seismic data so all this thickness is generated from well 11 control. 12 Exhibit 20, (page 24), has some bullets on there 13 describing more of the reservoir side of our project. First of 14 all it is a heavy oil waterflood development. We talked about 15 the horizonal wells and how long they are. Measured depth on 16 those are extremely long, up to 20,000 feet, but the laterals 17 are 4,000 to 8,500 feet in a line drive pattern. 18 Our current strategy is to replace voidage 1 to 1. This 19 will probably be done on a -- maybe not a well pair level, but 20 at least by grouping of well (ph) to try to balance the pattern 21 evenly across the field. We'll try to maintain reservoir 22 pressure around initial pressure. Our initial pressure is 23 1,700 pounds at the datum of negative 3760. 24 The fluid properties are a real driver here. The oil is 25 actually on the upper end of the heavy oil spectrum from 16 to R& R C 0 U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 28 0 0 1 19 degree gravity oil. What makes this difficult from a 2 waterflood point of view is the temperature of the reservoir 3 it's 80 degrees making the viscosity I wouldn't say, you know, 4 a heavy oil viscosity, but ranging from 100 to 200 centipoise 5 it certainly does dominate the fluid movement within the 6 reservoir being cold. 7 The oil in place has been estimated to range on the unit 8 somewhere between 800 and 930 million barrels and with all of 9 our work that we've done trying to assess uncertainly we 10 believe the technical recovery would range from 15 to 22 11 percent of the lease, original oil in place. 12 Other depletion strategies have been considered. I know 13 there are lots of things -- exotic techniques going on, on the 14 North Slope in other fields, but because we're a standalone 15 operation we don't have any access to gas other than what we 16 produce. As you can see from the table our GOR is very low so 17 we expect to consume all of our gas as fuel gas so waterflood 18 for us is the best and really only technique. 19 We have investigated some polymer and continue to work on 20 FOR techniques and hopefully will come up with something to 21 even improve recovery, but to date we're sticking with the 22 waterflood concept. 23 Exhibit 21, (page 25) is a -- shows the predicted oil rate 24 from the field, from the full field development in solid green. 25 The scale on the left is in stock tank barrels per day so you R& R C 0 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 • 0 1 can see that the peak rate on this slide is approximately 2 28,000 barrels a day with a short plateau. The cumulative oil 3 production is 180 million barrels from this model through 30 4 years. 5 Now, this is a -- we haven't produced any oil so this is 6 -- there's a lot of uncertainty here and -- but this is what we 7 are -- have planned for and what we're hoping for. 8 COMMISSIONER FOERSTER: So are you going to keep this and 9 30 years from now at your retirement party you're going to do a 10 comparison? 11 MR COOK: Not -- no comment on that. Yeah, it's a long -- 12 it's a long life unit for sure and, you know, we have looked at 13 quite a few analogs across -- not just in Alaska, but also in 14 Canada and California and other places internationally and this 15 type of flood it just takes a long time to get the oil. And we 16 expect water break through fairly early, you know, within the 17 first five years, significant break through and then it's just 18 a matter of cycling lots of water through and that's what our 19 model shows and that's what the analog show and so yes, we've 20 in for the long haul. 21 Oh, other point and it's not in the application and I know 22 the AOGCC is interested, the associated gas rate with that peak 23 rate is 2.2 million a day. And the peak water rate is 24 approximately 50,000 barrels of water a day, that's for this 25 case, but we've done some uncertainty work that shows that our R& R C 0 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 • 0 1 water rates could get up to 100,000 barrels of water per day 2 for the field and all of these are within the facility's 3 limitation so there are no constraints envisioned for the OA 4 Schrader Bluff development. 5 Okay. So that concludes the reservoir side of our main 6 development, the OA reservoir. I want to just show you a few 7 things about the N sand so exhibit 22, (page 26) is -- shows 8 two N sand structure map with two different contacts on them. 9 The one to the -- the structure map to the north -- I 10 mean, to the upper left hand side of the slide -- of the 11 exhibit shows the highest known water and the map on the lower 12 right hand corner shows the lowest known oil. So there is a 13 gap in between the Kigun wells here the Nikaitchuq wells over 14 here that is uncertain. We also know that there is some sort 15 of strategraphic limit, but we're not sure where it is. Thetis 16 Island doesn't have any logs across the N sand unfortunately so 17 we don't know there, but down in East Harrison Bay I think the 18 N sand is non - existent. 19 Okay. I'll also use this slide -- I'm sorry, I'll go into 20 the next slide (page 27). So for future potential the N sand 21 overlies the -- this is exhibit 23. It shows some main bullet 22 points about the N sand. The N sand overlies the OA. It is 23 pretty consistently following the same structure as the OA. It 24 is a little bit more variable in quality. It's quite good in 25 the Kigun area, but not quite as good down south where we're R& R C 0 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 i 0 1 drilling now, so we'll continue to work on it. 2 We're doing some seismic interpretation of the N sand 3 horizon. It's very difficult because it's just below a very 4 bright marker and as we drill wells we're continue to gather 5 data across the N sand and hopefully gather enough data in 6 terms of rock properties and at some point hopefully get a 7 fluid sample so that we can justify an N sand development, but 8 the real uncertainty for N sand is compartmentalization and the 9 northern area where we don't have well control and the fluid 10 properties. I 11 I'll add one more thing in there, we -- you know, it may 12 be also more unconsolidated so sand issues may be something we 13 have to consider, but where it does occur in the wells it's 14 quite good, 23 to 33 percent porosity with low water saturation 15 and in Kigun well it looks very good. Very well developed with 16 oil full to base. 17 One thing that it does show is that as we go north the 18 sand quality tends to improve so we do believe that our 19 northern area that we don't have well control data or really 20 very good seismic could still be, you know, quite perspective 21 (ph) for the N sand. 22 The range of oil in place for the N sand -- or the 23 resource has been estimated to be between 300 and 600 million 24 so it's smaller than the OA, but still sizable. 25 Exhibit 24, (page 28) is a map showing the outlines of R& R C 0 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 0 0 1 both the N sand and the OA sand as we know them. This is to 2 support our requested pool area. The blue outline shows the 3 mapped OA. We have some very high confidence in the solid blue 4 line so the solid blue line, as you can see, covers the -- most 5 of the unit, certainly central down to the southeast to the 6 lease line or to the unit line and up to the north. 7 There is a dashed blue line in the far north eastern part 8 of the unit that we called prospective OA. We don't have any 9 data up there or any really reliable data up there, but our 10 depositional model indicates that there's no reason that there 11 wouldn't be additional lobes deposited going to the north, so 12 depending on the oil /water contact, depending on the sand there 13 could be additional OA up in that corner. 14 Now, for the N sand we're not nearly as well along on our 15 understanding of the N sand extent, but we generally do see it 16 in the new seismic, PGS seismic shoot so the solid red polygon 17 shown in the southern half of the unit is where we believe 18 almost -- you know, very, very confidently that there is N sand 19 supported by the well control and the seismic. 20 Then farther to the north the red dash line which is the 21 balance of the unit shows where we think N sand could be 22 present and there certainly is no evidence to suggest that it's 23 not present up there in the north. 24 That concludes the reservoir side at least from the 25 perspective of what we would consider for the public R& R C 0 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 consumption. And we do have some confidential slides that -- 2 that we can go through later off -- not on the public record. 3 CHAIRMAN SEAMOUNT: Which slides would those be, the 4 confidential ones? 5 MR. COOK: They're on -- they're toward the back of the 6 presentation starting on -- after the pool rule slides and 7 they're referred to by an exhibit with an A numbering -- or a 8 letter numbering system, alpha data. 9 CHAIRMAN SEAMOUNT: Okay. 10 MR. COOK: I think page 51, page 51, yes. 11 COMMISSIONER FOERSTER: Page 51 in mine. 12 COURT REPORTER: So it would be 51 to the end? 13 MR. COOK: From 51 to the end, yes, ma'am. 14 CHAIRMAN SEAMOUNT: So when we get to the point where 15 we're going to consider these slides we'll probably take a 16 recess and discuss whether we even need 'em. And the 17 Department of Law can correct me, but I believe that if we 18 don't need 'em they're considered as voluntary admissions and 19 we can keep them confidential or if they're proprietary, you 20 know, if it's something that's going to hurt your 21 competitiveness in this area. So I guess we'll just listen to 22 the rest and then when we come to that point we'll take a 23 recess. 24 MR. COOK: Generally the confidential slides are just 25 backup to the reservoir work and geology work we've done, some R& R C 0 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 4 • 0 1 of the basis that we've used and our analysis techniques so I 2 think we've presented all the conclusions of the study in the 3 testimony so far, so yeah, I would appreciate if they're not 4 necessary than we can certainly put them in voluntarily as long 5 as they're confidential. 6 COMMISSIONER FOERSTER: And make sure that the one that 7 goes with the Court Reporter doesn't have 'em. 8 MR. COOK: Yes, ma'am. 9 COMMISSIONER FOERSTER: Okay. 10 MR. COOK: Okay. What I'd like to do now is pass the 11 hearing over to our well operations project manager Maurizio 12 Grandi who will tell you about our drilling and completion 13 strategy 14 CHAIRMAN SEAMOUNT: Before we do that Commissioner 15 Foerster has some questions. 16 MR. COOK: Yes, ma'am, sure. 17 COMMISSIONER FOERSTER: First I wanted to applaud ENI on 18 sticking with that long standing North Slope tradition of 19 throwing as many confusing acronyms to name things which 20 possibly could -- I don't know what we'd do without that, but 21 seriously I have several questions for you. 22 Is there any Kuparuk potential, Kuparuk sand potential? 23 MR. COOK: We have mapped Kuparuk interval based on the 24 seismic data. So far we have drilled a deep water well and we 25 did not find the Kuparuk in that well. We're still hopeful and R& R C 0 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 5 0 0 1 we'll continue to evaluate, but right now we have not found any 2 Kuparuk. 3 COMMISSIONER FOERSTER: Okay. You talked about the 4 possibility of more faulting and some compartmentalization with 5 the faults you see and the faults you don't yet see. Have you 6 modeled a case with more dense faults and more 7 compartmentalization and how does that impact your recovery? 8 MR. COOK: Yes, yes, we have modeled it. We have 9 different scenarios for compartmentalization. We also believe 10 that there may be a stratigraphic element to that. The seismic 11 has shown that there's some internal depositional features 12 across the unit so it could be a combination of strategraphic 13 and faulting. 14 Like I said, we have found some significant faults that 15 were not mapped so we certainly believe that there are 16 compartments. Because we have two fluid regions we have to 17 separate them in the model otherwise we have equilibrium 18 problems so we -- and we do have some different scenarios where 19 different areas are compartmentalized and not connected to the 20 rest. 21 To be honest the differences are not that great. Because 22 you saw our well pattern, we're basically covering every inch 23 of the reservoir so whether we cross a boundary or cross a 24 fault and even in the same well the processes going on 25 underground are going to be relatively near well bore so as R& R C 0 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 6 1 long as you have wells there I think we will -- we'll get 2 production from that area. If we don't have a well there we 3 won't get production from the area no matter whether there's a 4 compartment or not 'cause the oil just doesn't move very well. 5 COMMISSIONER FOERSTER: So you put the monkey on 6 Maurizio's back. To make sure he drills, you give the 7 (indiscernible - voice lowers) ..... 8 MR. COOK: That's right, we're telling him to draw..... 9 COMMISSIONER FOERSTER: Got cha. 10 MR. COOK: .....cross faults and stay in the -- stay in 11 the reservoir so I don't know how that works, but..... 12 COMMISSIONER FOERSTER: Okay. You guys, are you aware 13 that you'll need to apply for an area injection order before 14 you start injecting anything? 15 MR. COOK: Yes, we are -- we are aware and we intended to 16 have a joint hearing, but the schedule got us so we'll be 17 putting that together..... 18 COMMISSIONER FOERSTER: Okay. 19 MR. COOK: .....relatively soon. 20 COMMISSIONER FOERSTER: Yeah, we typically do see those 21 jointly. 22 MR. COOK: Yeah. 23 COMMISSIONER FOERSTER: So this is, kind of, a rhetorical 24 question, but why put the edges of the lease as the pool unit? 25 MR. COOK: well, first of all that's the only information R& R C 0 U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 37 • 0 1 that we really feel confident with. The other issues are that 2 the Milne Point pool, Schrader Bluff pool and the KRU pool come 3 very close to the unit so I'm not sure how to resolve that 4 really. 5 COMMISSIONER FOERSTER: Okay. Do the N and the OA sand 6 correlate and carry through to existing production at Milne 7 Point and Kuparuk? 8 MR. COOK: I don't think existing production -- I know -- 9 I know we believe it's -- the OA continues off lease to the 10 south and to the east. I'm not sure if -- I don't think 11 there's any Schrader Bluff at F pad. I think it's mostly 12 Kuparuk so I think the Milne Point /Schrader Bluff development 13 is further -- further to the south and to the -- and to the 14 east. 15 COMMISSIONER FOERSTER: So you don't think that's the same 16 pool? 17 MR. COOK: Well, it may or may not be. It may be the same 18 correlative interval, but -- but, you know, whether -- there's 19 no telling whether it's in communication with all the faulting 20 and this -- with this type of oil you get -- you get a few 21 thousand feet away from a drainage point and you may not even 22 see it. You may not -- you know -- you know..... 23 COMMISSIONER FOERSTER: So you talked about, you know, not 24 having the same resources everybody else did so would -- would 25 recovery be positively impacted by pooling everything and R& R C 0 U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 38 1 making use of other -- the other operators resources? 2 MR. COOK: No, like I said I don't believe there will be 3 much cross lease communication at all because -- because the 4 oil just -- it requires energy in terms of water in order to 5 get the oil to move. I mean, it will move -- a little bit of 6 it will move, but -- but if you look at -- if you look at the 7 pressure gradients away from the well they go very quickly back 8 up to original pressure. You just -- it's difficult to get 9 this cold, heavy oil to move. 10 COMMISSIONER FOERSTER: Okay, I'll leave that one. What 11 data do you have to tell you that the different layers are in 12 communication as you referred to in exhibit 17? 13 MR. COOK: Well, we have some MDT (ph) data and that was 14 one of the confidential slides. 15 COMMISSIONER FOERSTER: And how do you plan to appraise 16 the OA in the perspective (ph) OA area? 17 MR. COOK: The perspective OA area, we can't reach it 18 right now from our current drill sites and I guess -- I guess 19 we don't really have plans to appraise it at this point, but we 20 do have an interest in the leases north of the unit and that is 21 an ongoing evaluation of what's going on north of our unit in 22 federal waters and so I'm not saying -- I mean, I think the 23 best idea would be some sort of seismic, but we don't have any 24 plans right now for that area. 25 MR. MOLES: Do you accept interjections by others or -- on R& R C 0 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 the questions or no? 2 COMMISSIONER FOERSTER: He could..... 3 COURT REPORTER: He needs to come to the mic. 4 COMMISSIONER FOERSTER: Come to the mic and you can be a 5 lifeline if that's okay. Call a friend..... 6 MR. MOLES: No, it's really quite simple. This is a 7 challenging project economically so we see how the onshore 8 wells go and then how the offshore wells so and then you see 9 what kind of economic energy you have as you move out, so 10 recognizing the resource area that Dave's described and then it 11 becomes an economic matter and then followed by a data 12 gathering plan. 13 COMMISSIONER FOERSTER: Okay, thank you. 14 CHAIRMAN SEAMOUNT: Thank you, Mr. Moles. 15 COMMISSIONER FOERSTER: I'm done. 16 CHAIRMAN SEAMOUNT: Okay, thank you, Mr. Cook. And we'll 17 go to the next testifier and I know that you were sworn in, is 18 that correct? 19 MR. GRANDI: Yes, I do -- I did. 20 CHAIRMAN SEAMOUNT: Okay. Please state your name and..... 21 MAURIZIO GRANDI 22 called as a witness on behalf of ENI US Operating Company, 23 Inc., testified as follows on: 24 DIRECT EXAMINATION 25 MR. GRANDI: My name is Maurizio Grandi. I'm the Alaska R& R C 0 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 well operation project manager. And I received my -- my 2 history is I received a MS Degree in Engineering in a 3 university in Italy, (indiscernible) University in 1994. Then 4 I joined the industry in 1986 (ph) and I grew up -- well, I 5 worked either in (indiscernible) and internationally and after 6 a period of, you know, (indiscernible) Italian district I moved 7 overseas. 8 And just to be detailed (ph) over the last 11 years I was 9 -- I covering the position of well operation manager in Egypt 10 for five years essentially dealing with exploration of wells 11 onshore /offshore (indiscernible) deep water (indiscernible) 12 activity. 13 And then a couple of years as well operation manager in 14 Ecuador in this case development heavy oil artificially in, you 15 know, helicopter operation in the Rain Forest difficult 16 logistics again. 17 And now from (indiscernible) -- from two and a half years 18 since, you know, as the team was forming here in Anchorage in 19 early 2008 I'm the well operation manager and so for that I 20 would like today to be acknowledged as an expert witness in the 21 drilling completion. I mentioned well operation and we 22 essentially means -- maybe it's more comfortable for everybody 23 drilling completion, yes. 24 CHAIRMAN SEAMOUNT: Thank you, Mr. Grandi. Commissioner 25 Foerster, questions,..... R& R C 0 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 I 0 6 1 COMMISSIONER FOERSTER: No. 2 CHAIRMAN SEAMOUNT: .....objections? Okay. Mr. Grandi, 3 you are designated as an expert witness in, I guess, well 4 operations engineering. Thank you. 5 COMMISSIONER FOERSTER: It's Grandi not (indiscernible - 6 away from microphone) ..... 7 CHAIRMAN SEAMOUNT: Oh, is it Grandi? 8 MR. GRANDI: Grandi, yes. 9 CHAIRMAN SEAMOUNT: Okay, Grandi not -- okay, sorry. 10 MR. GRANDI: So exhibit 25, (page 30) you have already 11 seen it, but I come back just to make some other comments. So 12 in here we see all the pattern of the horizontal wells. In 13 effect we have -- Dave explained we have shown the horizonal 14 laterals outlining this picture, injectors and producers. As 15 he said we have two -- two pads. We are drilling from two 16 different pads, the onshore in Oliktok Point and the offshore 17 in the manmade island, the Spy Island, so close Spy Island. 18 We're going to have two separators separating in the two 19 pads. In the onshore we have already the (indiscernible) rig 20 (ph) 245E (ph) that is working, has been working also for the 21 original first campaign in late 2008. 22 We have already started operation in April 2010 and we are 23 drilling now the sixth well,since April, the injector as was 24 mentioned, so we are drilling this year 2010 campaign one water 25 well for producer and this is the sixth well the injector. We R& R C 0 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 2 1 have already drilled as we -- I just remind other couple of 2 wells in 2008/2009, the disposal well and one producer. So the 3 plans calls for the activity keep going with this rig and 4 expected end of operation by the second quarter of 2012. 5 In the island we have the plan for having a second rig as 6 I said in this case it's the Doyon rig 15 (ph). The plan is 7 for barging the rig in the barging season 20- -- activity 2011 8 so in essentially in August for spudding (ph) around September 9 2011, so one month later. 10 Again, the count of the wells for the island is 30 wells 11 so we're going to have one disposal as we have in the drilling 12 pad onshore for getting rid of the waste of the drilling, 13 drilling waste and cuttings. And then the most of -- you know, 14 of our water (ph) injector /producer 15 and 16 so a total of 40 15 wells (ph). Starting next year (indiscernible) again is 16 considered to be around the end of year 2014. 17 So all the -- as you can see all the project is based on 18 hdrizonal wells, long lateral and I can say just for the sake 19 of clarity, you know, standard (ph) reach drilling. We are 20 talking about displacement is a number that in effect is always 21 asked is the ratio, the ratio is activity versus displacement 22 we are talking about the number that goes exceeded five -- the 23 most long reach will be 5.3 for your (indiscernible) and we are 24 talking in effect of a range of activity we have already said 25 3,300 (ph) to 3,800 feet activity and (indiscernible) measured R& R C 0 U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 43 i 1 depth that can be from 14 -- 16,000 (ph) to the most -- the 2 longest one will be 21,400. 3 And the only other point is that, of course, the pattern 4 has already been shown and discussed and we'll fully cover and 5 explore the possible production and -- of all the reservoir and 6 as you can see all the laterialized -- most of the laterialized 7 essentially parallel oriented, parallel to the main 8 (indiscernible) action. It is not west -- southeast. 9 We can go to exhibit 26, (page 31) that looks pretty busy 10 as a picture. As a matter -of -fact it is just for a reference. 11 This is a typical configuration our casing design and most of 12 the other details relative to, you know, mud, the cementing and 13 (indiscernible). 14 And another comment regarding all the Schrader Bluff 15 wells, the injector and the producer, the one shown is a 16 producer. There's a schematic of an ESPN (ph) and -- and 17 tubing will be the same, exactly the same casing design. We 18 start with a conductor 20 inches pre - installed during the pad 19 construction -- or following the pad construction. The surface 20 casing is a 16 inches over 14 and 3/8 (ph) casing. The 21 original section is to cover the permafrost area that is the 22 permafrost (ph) zone that is in this area considered to be at a 23 TD of 1,800, 1,900 feet and so will pass the permafrost area 24 and to provide a proper, you know, (indiscernible) base for the 25 -- the casing will be cemented to surface. R& R C 0 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 In this section we will also have the start of the 2 deviation (ph), as a matter -of -fact, we are talking about 3 (indiscernible) -- the kickoff point, the start of - -, it 4 pretty surface -- close to surface. We are talking about -- I 5 mean, they are set apart because of (indiscernible) issue, but 6 is around 300 feet and we are going to navigate with an angle 7 of, you know, 30, 60 (ph) degrees to the end of the phase. 8 Then the (indiscernible) phase is 12 and a quarter for a nine 9 and 5/8 casing. In this case the casing point is the top of OA 10 sand where we -- that should be reached with an angle of 85 11 degrees for the final build -up and keep the lateral in the 12 horizontal (ph). Again, the angle of this -- this 13 (indiscernible) section will be very demanding, very long reach 14 some how, you know (ph), with angle of pretty -- pretty long 15 arriving at the end of the day to close to the horizontal 16 section at the top of OA. 17 The production, as we said, are a length of in between 18 6,000. I have some statistic of even more than 9,000. I don't 19 (indiscernible) -- if Dave agree (ph). Anyway, these are 20 statistics and it's an (ph) eight and a half (ph) all size for 21 a five and a half slotted liner so simple design according to 22 the experience of (indiscernible) protecting the lateral with a 23 five and a half liner. What can be said also the lateral drain 24 will be through navigation and there is a void (ph) so we'll 25 have geo- steering (ph) capability, place and rotary steerable R& R C 0 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 5 i 9 1 to -- just to maximize exposure in the reservoir and follow the 2 natural depth of the strata. 3 Okay. So moving quick exhibit 27, (page 32) in this 4 exhibit we -- I want to only outline a few rationale that 5 you're going to see in the pool rules themselves that are more 6 detailed later on. We have three points for discussion. 7 All wells will be equipped with a fail -safe automatic 8 surface safety valves meaning in essentially all wells in our 9 two location, injector, producer, water well disposal and this 10 is our commitment. 11 Then other two points is specifically on injection wells, 12 the injection well will be equipped with landing nipple for a 13 possible below permafrost for possible future installation of a 14 flow control device. This is a precaution for future need. We 15 do not anticipate, but we prefer to keep this as a must in our 16 well design. 17 And finally something that can be a little more explained 18 is the need to have a -- the packer of the injection wells not 19 more than 200 feet above the top of perforation or the 20 injection zone. In our case it's the horizontal (ph). 21 Essentially to facilitate wireline access, so keep the packer 22 position in an angle capable to be reached by water line. This 23 200 feet could be extend, could be more than what the rule 24 asked -- called for. 25 So to -- to have -- to -- let's say to grant the same R& R C 0 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 • 9 1 level of confidence we would like to add additional two points 2 for this so the packer should be set anyway above -- not 3 located above the confining zone that for us is the Ugnu (ph) 4 formation. And will be -- we are going to have the cement bond 5 on the (indiscernible) section such as the top of cement will 6 be located minimum 300 feet above the packer (indiscernible) 7 depth again. These are the rationale for, as I said, a few of 8 the comment we're going to have for the pool rules later on. 9 As you see I tried to be short and so when you're ready 10 for additional questions we are going to have other description 11 essentially or element to the completion design later on in the 12 confidential side and for the moment is all I have for the 13 drilling completion. Eventually I would leave the work (ph) to 14 Steve Massey for (indiscernible) operation. 15 CHAIRMAN SEAMOUNT: Thank you, Mr. Grandi. Commissioner 16 Foerster, questions? 17 COMMISSIONER FOERSTER: Two questions. Your ESP wells, 18 are there going to have packers? 19 MR. GRANDI: Pardon. 20 COMMISSIONER FOERSTER: Will your ESP wells have packers? 21 MR. GRANDI: The ESP will not have packers. As far as we 22 can demonstrate they are not -- flow so it will be consistent 23 with the reg -- ACC -- Chapter 25 regulation so this is 24 planned. 25 COMMISSIONER FOERSTER: Okay. And you talk about that R& R C 0 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 S 0 1 you're going to ensure a good cement job so that blab, blah, 2 blab, but what are you going to do if you don't get a good 3 cement job? 4 MR. GRANDI: (Indiscernible) or I mean,..... 5 COMMISSIONER FOERSTER: You know, are we just setting 6 ourselves up for waiver after waiver after waiver or do you 7 have a plan to get a good cement job if..... 8 MR. GRANDI: First of all, I mean, the plan starts from 9 the excess of the degree of confidence you have in that we are 10 going to not have a program and plan for having the bear 11 minimum accessory (ph). In effect we believe that we could -- 12 we are planning for more -- than the simple bare minimum as we 13 state. Then we're going to have, of course, a learning curve 14 through the easiest well to the most demanding. We have, of 15 course, the campaign for any -- for any single injector well to 16 have the proper log to analyze the real behavior so the real 17 effect of the cement job itself and for the final cement, you 18 know, back up we usually have the same as everybody has in a 19 re- -- possibility of re- cementing that we've always pros and 20 cons. 21 COMMISSIONER FOERSTER: Okay. Those are my two questions. 22 CHAIRMAN SEAMOUNT: As you drill these horizonal wells 23 are you planning to bounce from bottom to top, you know, to 24 kind of wiggle through to -- to catch all the zones or are you 25 just going to go at it at an angle to get 'em all? R& R C 0 U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 48 0 9 1 MR. GRANDI: No, as I said and Dave, of course, can makes 2 his comment on the different area of the OA sand, we just -- so 3 we have a full capacity to follow -up any needs -- ask us to 4 achieve. So as a matter -of -fact in the wells we have drilled 5 so far we have -- prove the reservoir and to get all the -- all 6 the different, you know, OA sand and -- okay I don't know if 7 you want to -- that they are different in injection and 8 production? 9 MR. COOK: Yeah, I could just speak to that. We have the 10 different layers like we said, but we consider in the OA from 11 top to bottom to be reservoir, different qualities, but 12 obviously there are some vertical barriers so we are planning 13 on undulating and we have executed that plan. Generally we 14 want to stay around 1,000 feet in one layer and then dive down 15 to the bottom layer 1,000 feet and then back up to the top 16 layer, that's generally our plan, but, of course, the geology 17 will dictate where we drill so some wells have gone very, very 18 much accordin g to plan and other wells we've had to make 19 adjustments based on what we're seeing. 20 We have some very nice tools in the ground that we're..... 21 MR. GRANDI. As a matter-of-fact so far the steering in 22 the reservoir has been pretty smooth and effective. As I said 23 we are using rotary stable (ph) system and -- and so you can 24 have what you need without really -- and has been pretty smooth 25 in effectiveness. And fast reactive any way according to R& R C 0 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 9 • 1 adjust steering to logging wide draining (ph) so you can really 2 take action as soon as you realize you need to make 3 corrections, so..... 4 COMMISSIONER FOERSTER: And you're not anticipating any 5 different water contacts as production occurs..... 6 MR. COOK: We haven't seen any evidence of ....... 7 COMMISSIONER FOERSTER: Okay. 8 MR. COOK: .....of other contacts and everything that 9 we've seen from the appraisal and also in the drilling we've 10 had oil full to base so that's the way it's modeled, that's 11 what we expect. 12 COMMISSIONER FOERSTER: Okay. I'm done. 13 CHAIRMAN SEAMOUNT: Okay. Thank you, Mr. Grandi. 14 MR. GRANDI: Thank you. 15 CHAIRMAN SEAMOUNT: Okay. Who's next? 16 MR. MASSEY: I'm next. 17 CHAIRMAN SEAMOUNT: And I saw you, you were sworn in. 18 MR. MASSEY: I was sworn in, yes. 19 CHAIRMAN SEAMOUNT: Okay, thank you. 20 STEVE MASSEY 21 called as a witness on behalf of ENI US Operating Company, 22 Inc., testified as follows on: 23 DIRECT EXAMINATION 24 MR. MASSEY: My name is Steve Massey. I'm the Alaskan 25 production manager for ENI Petroleum and ENI US Operating R& R C 0 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 0 0 • 1 Incorporated. I received a Bachelor of Science in Chemical 2 Engineering from Texas Tech University. 3 I've worked in the oil industry for 35 years with a 4 variety of engineering and operating experience in the Lower 48 5 and Alaska. I worked 25 years for Atlantic Richfield, 14 of 6 which were in Alaska. I've held numerous jobs at Prudhoe 7 including production supervisor, superintendent of both 8 facilities and remedial well work and operations manager. 9 I'd like to be acknowledged today as an expert witness in 10 facilities and production operations. 11 CHAIRMAN SEAMOUNT: Thank you, Mr. Massey. Commissioner 12 Foerster. 13 COMMISSIONER FOERSTER: I'm very familiar with Mr. 14 Massey's qualifications and have no problem accepting him as an 15 expert witness. 16 CHAIRMAN SEAMOUNT: Thank you. Mr. Massey, you are 17 designated as an expert witness in facilities and operations 18 engineering. 19 MR. MASSEY: Thank you. Basically this morning I'd like 20 to go over the facilities that we're going to have on each one 21 of our pads to get you familiar with what we have. 22 First off, you've seen this in a different form, but it 23 basically show that we have an offshore island. 24 COMMISSIONER FOERSTER: Refer to the exhibit. 25 MR. MASSEY: Exhibit 28, (page 34), sorry, Cathy. Yeah, R& R C 0 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 • i 1 exhibit 28. It's just a development plan map. Furthest north 2 up by Spy Island we do have an offshore island there. It's an 3 artificial gravel pad that we built in about six foot of water. 4 It's 11 acres. That's going to be our drill site number 2 5 there and we'll start drilling on that 2011, you've heard that. 6 We have a three mile flowline bundle. It's made up of 7 four different lines. We have a pipe -in -pipe production line, 8 a water injection line, a pipe -in -pipe diesel line and then a 9 fourth line is -- we label it gas right now, but it's a spare 10 right as we know it. 11 We come on to Oliktok Point here where we're going to have 12 a processing facility and separator oil, gas and water. We'll 13 re- inject the water, burn the gas and put on -spec oil down 14 14 mile export line that leaves Oliktok Point ties into the 15 Kuparuk Pipeline system and goes to TAPS. 16 Okay. Exhibit 29 is a 3D rendering. I use this instead 17 of a plot plan. It's pretty easy to see. The north side of 18 the pad we're calling our drill site 1 area, the south side is 19 our processing facilities. 20 Just to start off we have these well containment shelters. 21 We have slots for 24 wells in these shelters. Interesting 22 point it's not the first of its type, but it's pretty unique. 23 It -- they're fully self - contained. If we have a leak or a 24 drip inside these things it cannot go to the gravel. We have 25 containment inside. R& R C 0 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 2 1 We have test headers, production headers, water injection 2 headers, diesel, all inside here. As we come out of these -- 3 we also have here a tank farm area that's going to be our 4 diesel. It's base oil and it's all our production chemicals, 5 emulsion breaker, corrosion inhibitor, scale inhibitor and 6 anti -foam (ph) and a pumping system for that. 7 We have an electrical module here that is the drive units 8 basically for the ESP pumps that we're going to put in our 9 wells and the switch gear for the motors. 10 And then we have a drill site ESD module. It's also our 11 well testing module and for your information we're going to be 12 using the multi -phase flow meters, a Schlumberger VX meter. I 13 think you guys are familiar with those, so that's in that 14 module. 15 Coming around this pad here we have a grind (ph) and 16 inject facility right here that's primarily being used right 17 now for drill cuttings. It's a permanent facility. It's a 30 18 year facility that goes with the rest of this out there and 19 this will be in the future used for pumping sand that we 20 produce out of our wells into our class 1 injection well here. 21 And just -- we planned on mitigating sand at the surface 22 in these wells. We don't have any down hole packing or 23 anything for that so we're going to go ahead and produce the 24 sand. Inside of all our vessels we have a sand management 25 system and I'll talk about that in a little bit, but anyway we R& R C 0 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 3 • 0 1 are going to use this grind and inject, you know, for the 2 remainder of the life of this field. 3 And then we have our two big modules, our processing 4 modules. One of 'em is the process module itself and we have a 5 utility module. We have two 20,000 barrel a day oil processing 6 trains. They're pretty common and then we have inlet 7 separation and we have intermediate separation and then a 8 treater in each one of these things on both trains. 9 One thing unique when it's -- the first thing that the oil 10 will come into these facilities is go through a set of heat 11 exchangers and get heated up. It's pretty cold so we need to 12 get it pretty hot to separate and oh -oh, sorry...... 13 CHAIRMAN SEAMOUNT: How much energy is that going to take 14 to heat it up? 15 MR. MASSEY: (Indiscernible) You know, I don't know. I 16 don't know the btu's right off the top of my head, but what 17 we're basically doing is taking this from 80 degrees in the 18 reservoir and we're going to heat it up to 180 degrees in the 19 inlet separation and then up to 230 in the treaters. 20 CHAIRMAN SEAMOUNT: Sounds expensive. 21 MR. MASSEY: It is. Hopefully we're going to use the 22 waste heat recovery off of our turbines to do this so hopefully 23 we'll mitigate some of that expense. 24 The water system is very unique in here. Like I say we're 25 going to -- oh, sorry. R& R C 0 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 4 0 • 1 COURT REPORTER: (Indiscernible) I need to change the 2 tape. 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 R& R C 0 U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 55 1 Tape 2 2 MR. MASSEY: Okay. Mr. Seamount, I was going to say also 3 that I should have added that our water source wells, that 4 Ivishak water that we're going to be using coming in to the 5 facility, is -- it's over 200 degrees and we're going to get a 6 lot of heat source from that, also. 7 The water system in our facilities are very unique. Like 8 I said, we're going to be producing sand and it pretty much is 9 going to go with the water system so we have hydro- cyclones, 10 sand hydro- cyclones to clean up our water and oil hydro - 11 cyclones. And hopefully we plan to get our water clean enough 12 to inject into our wells there. 13 Our electricity is coming from four solar turbines. 14 They're T -70 brand turbines and we're going to use the exhaust 15 over there for waste heat. 16 Other than that, right here we're going to have 7,500 17 barrels of off spec (ph) oil capacity that will help us out if 18 the pipeline shut down or we get prorated we can keep our ESPs 19 on line and go to here. We've got stand -by generation. Our 20 flare knock -outs are outside. 21 And then down here on this end, right here, we have a pig 22 launcher for our 14 mile oil cells (ph) pipeline that will have 23 the capability to pig that system. And right here on this end 24 is another set of pig launchers and receivers and those are so 25 that we can pig and receive pigs from the island for our R& R C 0 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 6 0 ! 1 production and water, so we'll have all that capability. 2 CHAIRMAN SEAMOUNT: How far offshore is the island? 3 MR. MASSEY: About 3.1 miles I think we were saying in our 4 last slide. 5 CHAIRMAN SEAMOUNT: And that's in six feet of water? 6 MR. MASSEY: That island was in six feet of water. I think 7 the bathometry (ph) shows anywhere form seven to eight -- six, 8 seven, eight out there. We brought our barge in at seven I 9 believe. 10 CHAIRMAN SEAMOUNT: That doesn't sound like Gulf of Mexico 11 to me. 12 MR. MASSEY: No. So it's inside the barrier islands here, 13 so -- we put a picture in so that you can see where we're at on 14 this. 15 COMMISSIONER FOERSTER: And that would be exhibit 30. 16 MR. MASSEY: Exhibit 30, (page 36) shows -- I believe Mr. 17 Moles indicated that we have all of our facilities up there and 18 you can see that sure enough we do and we're in the process of 19 getting these all hooked up to one another and functionally 20 checking them out. 21 Our next facility is our Spy Island drill site facility. 22 And basically this will be a drill site ultimately, but to 23 start with we're going to house our drilling people out there 24 at 120 man camp. We will have a drilling support complex here, 25 cementing capabilities, grind and inject capabilities. We'll R& R C 0 U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 57 1 have a chemical tank farm out there with the same as onshore 2 diesel base oil and all the production chemicals. And we will 3 have three well containment shelters out there, the same as 4 onshore for a capability of 36 wells there and I think we have 5 planned 30, 31 there. 6 COMMISSIONER FOERSTER: And this is all for exhibit 31? 7 MR. MASSEY: This is all for exhibit 31. Out on this 8 island, like I said, we'll have the well containment shelters. 9 We'll also have a testing facility that's similar to the one 10 onshore. It's going to be the Schlumberger VX multi -phase flow 11 meter. We'll have -- bring that flow into a pig launch module 12 and through the undersea bundle and into the facility at 13 Oliktok Point. 14 Okay. Here's a picture. You can see our gravel island. 15 COMMISSIONER FOERSTER: Exhibit 32, (page 38). 16 MR. MASSEY: Excuse me, exhibit 32. 17 COMMISSIONER FOERSTER: I'm here for you. 18 MR. MASSEY: Thank you, Cathy. Exhibit 32 is our Spy 19 Island drill site. It's armored at this time. You can see our 20 row of wells that we're going to have in place here. The 21 conductors are set. We've also built a large support to 22 support a semi - cantilever rig. And all the other foundations 23 are being put in at this time. The modules are being built in 24 town here as we speak and we look forward to getting that 25 onstream at the -- you know, next year, towards the end of next R& R C 0 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 0 0 1 year on line. 2 Just for your interest here's a cross section of our 3 offshore flowline bundle. 4 COMMISSIONER FOERSTER: In exhibit 33. 5 MR. MASSEY: In exhibit 33, (page 39). This is our 6 production line. It's a pipe -in -pipe. We'll be pulling a 7 vacuum on this for leak detection. 8 This is our water line. It's an insulated and cement 9 coated line. 10 This is our pipe -in -pipe diesel and base oil line. This 11 is how we're going to be transferring diesel and base oil 12 alternatively through that line out to the rig. 13 And this is our spare line which we're calling our gas 14 line right now. 15 Okay. This is a bad picture here, but maybe you can see 16 it better in your handout. Exhibit 34, (page 40). (Tape 17 malfunction) .....center, NOC. And we're going to have -- 18 this is where our camp and offices will be located here. We're 19 going to have a warm storage warehouse and shop, a cool storage 20 warehouse and shop. We're going to have facilities here for 21 distribution of diesel and gasoline and a heliport in the 22 future here. 23 Exhibit 35, (page 41) is a picture, recent picture of 24 where we're at, at this time. You can see our cool storage 25 warehouse is pretty much done. This is our warm storage R& R C 0 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 9 0 1 warehouse. It's pretty much complete at this time. And our 2 camp here is now sitting on that structure and in place. We're 3 putting it together at this time. 4 And last, exhibit 36, (page 42) I'd like to talk just a 5 little bit about our well testing strategy. I know people are 6 interested in that. We plan to test our producing wells at 7 least once per month and submit a monthly well test report to 8 the AOGCC. 9 Our well testing will be completed with a Schlumberger VX, 10 multi -phase flow meter and our oil custody transfer will be 11 through a LACT unit before it goes into the pipeline. And 12 that's all I have about facilities today in case..... 13 CHAIRMAN SEAMOUNT: Thank you, Mr. Massey. 14 MR. MASSEY: .....you have a lot of questions. 15 CHAIRMAN SEAMOUNT: I've got a few that I haven't asked 16 yet. You mentioned a class 1 well,..... 17 MR. MASSEY: Yes. 18 CHAIRMAN SEAMOUNT: .....have you permitted that through 19 EPA yet? Have you gone through the process? How long did that 20 take? 21 MR. MASSEY: I wasn't involved too much in that. I can 22 defer that to David or Robert, do you guys remember..... 23 UNIDENTIFIED VOICE: It was about a half a year, six 24 months. 25 CHAIRMAN SEAMOUNT: Six months, okay, that's about what I R& R C 0 U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 60 1 thought it was. 2 MR. MASSEY: It is permitted, definitely permitted. 3 CHAIRMAN SEAMOUNT: I think Commissioner Foerster has 4 additional an question about the class 1 process. 5 COMMISSIONER FOERSTER: Yeah. You've got two disposal 6 wells, are both of them going to be class 1 wells? 7 MR. MASSEY: Yes, they are. 8 COMMISSIONER FOERSTER: Okay. So you're doing that just 9 so it's easy, so..... 10 MR. MASSEY: Right. 11 COMMISSIONER FOERSTER: Okay. That makes sense. 12 CHAIRMAN SEAMOUNT: So you're not going for a class 2 13 disposal well? 14 MR. MASSEY: No. 15 CHAIRMAN SEAMOUNT: Okay. So class 1 covers it all? 16 MR. MASSEY: Class 1 covers it -- and one of those is 17 onshore and one will be offshore for those cuttings. 18 COMMISSIONER FOERSTER: But you know that anything that 19 you get out of the reservoir you can put into a class 2, 20 so..... 21 MR. MASSEY: Right, yes. 22 COMMISSIONER FOERSTER: .....but -- so -- I can understand 23 the class 1 onshore 'cause, you know, camp waste and all that 24 other stuff, but are you anticipating a lot of class 1 waste in 25 your offshore location? R& R C 0 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 1 1 MR. MASSEY: Not -- not that I know of. It's just..... 2 MR. MOLES: Because of the camp for five years -- four 3 years ....... 4 COMMISSIONER FOERSTER: I beg your pardon? 5 MR. MOLES: .....we'll have a camp for four years. 6 COMMISSIONER FOERSTER: Oh, you have a camp off shore (ph) 7 -- there you go. 8 MR. MOLES: We have a certain number of other liquids 9 and..... 10 COMMISSIONER FOERSTER: Okay, that -- that answers that 11 question. 12 MR. MASSEY: For just in case. 13 COMMISSIONER FOERSTER: Yeah. I had other questions, too, 14 do you? 15 CHAIRMAN SEAMOUNT: Pardon me? 16 COMMISSIONER FOERSTER: Did you have other questions? 17 CHAIRMAN SEAMOUNT: No, I don't have any other..... 18 COMMISSIONER FOERSTER: Okay. I have a couple more. To 19 what extent and how have you benefitted from Pioneer's 20 experience at Oooguruk? 21 MR. MASSEY: Well, we've for sure shared lessons learned 22 with them on how to develop an offshore island, but as far as 23 processing facilities we don't -- they get their's processed 24 over at ConocoPhillips so we haven't dealt with them very much 25 on that so -- but there -- our drilling's completely different R& R C 0 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 9 0 1 than their's is with the Schrader..... 2 COMMISSIONER FOERSTER: I was referring to the is- -- you 3 know, the island operation..... 4 MR. MASSEY: Yeah, the island it is, that's -- we've done 5 a lot of lessons learned with them on that. 6 COMMISSIONER FOERSTER: Okay, okay. And what drivers led 7 you to choose stand alone facilities rather than facility 8 access to Kuparuk or Milne Point? 9 MR. MOLES: Do you want me to answer that? 10 MR. MASSEY: Yes, go ahead. 11 MR. MOLES: This is David Moles. Part of the decision -- 12 the decision was initiated, shall we say, by the original 13 operator Kerr -McGee and their thinking I can't speak to, but 14 when we became the 100 percent owner /operator we reviewed the 15 project and looked at our understanding of the arrangements for 16 processing by our partner at Oooguruk through ConocoPhillips' 17 facilities and the impact of that as opposed to incremental 18 investment and the impact of being to the greatest extent 19 possible stand alone. And to have maximum control over up -time 20 and limited system influences from downstream sectors, all of 21 that discussed the decision was made to go ahead with a full 22 production and processing facility. 23 COMMISSIONER FOERSTER: Thank you. That's all I have. 24 CHAIRMAN SEAMOUNT: Okay. Is there any other testimony? 25 MR. COOK: We were just going to show you the pool rules. R& R C 0 U R T R E P O R T E R S 811 G STREET (907)277 - 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 63 1 I'm not sure how you want to handle it. I don't feel like 2 reading them into the record unless it's necessary, but we 3 could go through them just to highlight some specific points 4 that we'd like you to consider. 5 COMMISSIONER FOERSTER: That's the -- let's take 'em rule 6 by rule and, you know, what you're asking and why you're asking 7 for it keeping in mind that if you're willing to go by the -- 8 just the regulations that are in place statewide that we don't 9 need a recommendation, so don't recommend a pool rule that says 10 we want to do what 25 AAC blab, blah, blah says. 11 MR. COOK: Right. Just as a preview to this reading the 12 other rules for other pools it's a little confusing 'cause 13 there are some restatement of regulations in those rules, 14 so..... 15 COMMISSIONER FOERSTER: And we're trying to stop that. 16 MR. COOK: You're trying to stop that so what we've done 17 is use those other rulings as a guide to try to understand what 18 you wanted to see. And certainly if there's a redundant 19 regulation that you don't think needs to be restated then -- 20 then we're okay. 21 CHAIRMAN SEAMOUNT: Yeah, we're not going to put it 22 in..... 23 COMMISSIONER FOERSTER: We're not going to put it in -- 24 into your specific pool rules. 25 CHAIRMAN SEAMOUNT: Yeah. We have -- we have -- in order R& R C 0 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 0 0 1 to be consistent with old orders in the same field we have 2 just, you know, had to restate those just so -- it did add 3 confusion, but we think it actually adds to confusion if you do 4 restate certain regulations and not the other ones which, you 5 know, somebody could think well -- well, they said we have to 6 do this, but they didn't say they had to do this regulation so 7 we don't have to do that, so -- I mean, we're..... 8 COMMISSIONER FOERSTER: So -- so if you..... 9 CHAIRMAN SEAMOUNT: .....trying to clean things up. 10 COMMISSIONER FOERSTER: So if you're happy with a portion 11 of your operations being regulated under the statewide 12 regulations then you don't need to tell us that, just hit the 13 things that you want different. 14 CHAIRMAN SEAMOUNT: Exceptions. 15 MR. COOK: Okay. And then as far as our proposal rul- -- 16 proposed rules if there are would you require or would you like 17 us to revised the requested rules if there are some redundancy, 18 you could..... 19 CHAIRMAN SEAMOUNT: No (ph). 20 COMMISSIONER FOERSTER: No, no, no, your request is fine 21 the way it is. 22 MR. COOK: Thank you. 23 COMMISSIONER FOERSTER: We'll -- but our order will come 24 out reflecting just the changes, just the things that are 25 different, but when -- but if you are requesting something R& R C 0 U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 65 9 0 1 different we need the justification for why..... 2 MR. COOK: Okay. 3 COMMISSIONER FOERSTER: .....that is -- you know, not why 4 it makes life easier for you, but why it follows the statutory 5 obligations that we have to prevent waste and promote greater 6 ultimate recovery and human safety and all those other things, 7 okay. 8 MR. COOK: Okay, okay. Well, I will try to do that and go 9 through rule by rule that we propose. So I will start with -- 10 well, I apologize 'cause these exhibits are not numbered. I 11 thought that they were, but they are not numbered. 12 COMMISSIONER FOERSTER: Well, in this case you might just 13 refer to the page number at the bottom of the page. 14 MR. COOK: Okay, I will do that. So page 45 of the 15 presentation shows rule 1 and 2. These are fairly straight 16 forward. Rule 1 we would request that the pool be named the 17 Nikaitchuq Schrader Bluff Oil Pool and be classified as an oil 18 pool. 19 Rule 2, we've already gone over the specific definition in 20 terms of the area and the interval, but that's restated here. 21 It'll be the entire Nikaitchuq Unit as the area and the 22 correlative internal shown there in the Kigun No. 1 well. In 23 the rule itself we've identified all the leases that are 24 included within the unit. 25 On page 46 we have rule 3 requesting spacing exceptions. R& R C 0 U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274-8982 ANCHORAGE, ALASKA 99501 66 1 Since we are drilling horizontal wells we would like to have 2 the freedom to design those wells as we see fit. You know, 3 currently we are planning on 1,200 foot spacing, but, you know, 4 we are continuing to investigate that and we'll decide, you 5 know, if that is the best spacing and we may go higher or lower 6 depending on what we see in the well performance. 7 We don't plan to drill any wells closer than 500 feet to 8 the lease line which I understand is the regulation, but if 9 such a need arises I guess we will handle that on a well by 10 well basis. 11 Okay. Then the drilling and completion practices, this is 12 a rule, I think, Maurizio discussed in general terms of why 13 we're requesting the differences in the packer depth. I don't 14 want to go through that here again, but this is the statement 15 of the rule that Maurizio discussed. 16 Then rule (b) the -- what we propose -- although we're 17 gathering lots of petrophysical data with our well logging we 18 would request that only one official log suite is required at 19 each drill site to satisfy the requirement. 20 Rule -- on page 47 of the presentation we have rule 5 and 21 6 shown. Again, the automatic shut -in equipment. This may be 22 a case where we might have some restatement of some of the 23 regulations, but I know that the inject- -- the rule 5(b) was 24 described by Maurizio and does specify what we're planning to 25 do in the injection wells which I believe is different than the R& R C 0 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 7 1 regulation. 2 MR. GRANDI: Yes, it's more than the regulation..... 3 MR. COOK: More than the regulation. 4 MR. GRANDI: Is not (indiscernible) ..... 5 MR. COOK: Right. 6 MR. GRANDI: And also is stating all wells because is our 7 intention should be -- should be the Schrader Bluff only 8 (ph) ..... 9 MR. MASSEY: Yeah, he said -- he said that on (a) we put 10 all wells will have the automated surface safety valve system, 11 where in the regulations it doesn't necessarily state all types 12 of wells, so every one of our wells, disposal, water source, 13 injector or producer will have that, so..... 14 MR. COOK: Okay. So continuing on, rule 6 is about 15 reservoir pressure monitoring and we do plan to gather quite a 16 bit of pressure data. We will have bottom hole gauges in most 17 of the wells and we will take pressures initially. 18 I think (a) is probably a restatement of an existing 19 regulation, but we will take a minimum of one pressure survey 20 in each reservoir compartment. So as we better understand the 21 compartmentalization of the reservoir we will be sure to take 22 at least one initial pressure survey when we -- when we 23 discover what we consider to be a new compartment. 24 The reservoir datum has been defined as negative 3,760 25 feet TVD subsea. That is very, very much in the middle of the R& R C 0 U R T R E P O R T E R S 811 G STREET (907)277 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 68 0 1 OA reservoir. 2 I think (d) is a restatement of existing regulations, but 3 certainly would consider a pressure could be anything from a 4 static pressure to a pressure build -up or fall -off test, 5 multirate tests, drill stem test and any of those stated there 6 in the rule. 7 And then we will, of course, report these surveys with the 8 annual reservoir surveillance report that I will discuss in a 9 rule, I think, on the next slide. 10 I think rule 7 is concerning well testing and Mr. Massey 11 already discussed our strategy. You clearly understand what 12 our plans are for well testing and allocating production to the 13 different wells. 14 Rule 8 is a request for a GOR or a gas -oil ratio 15 exemption. First of all we don't expect there to be a gas 16 problem here. We have very low GOR and we are committed to a 17 pressure maintenance program so we are going to do everything 18 we can to keep the pressure -- the average pressure maintained 19 around initial pressure, so we -- we request if we have an 20 exemption for any gas -oil ratio restrictions (ph). 21 Rule 9 is just a statement of our project. To improve 22 recovery we have decided waterflood is required for the 23 pressure maintenance and the enhanced oil recovery of the 24 Schrader Bluff -- Nikaitchuq Schrader Bluff oil pool. 25 Production and injection must ensure that the average reservoir R& R C 0 U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 69 1 pressure in each sand lobe or reservoir compartment is 2 maintained at or above the bubble point for that respective 3 sand lobe or reservoir compartment. 4 I think one thing we didn't talk about was the bubble 5 point. The bubble point is approximately 1,000 pounds, so 6 reservoir pressure is 1,700 pounds, bubble point is 1,000. We 7 do have some -- some freedom there for local pressure 8 differences. As long as we maintain above the bubble point 9 we'll be in good shape. 10 And then we would also ask that we don't have this 11 restriction implemented until one year after the start of 12 regular production from each drill site. We need some amount 13 of time to develop the well patterns and get the injection 14 support up and running. Right now we are front loading the 15 production wells because we need a certain critical flow rate 16 for start up of the facilities. We will then follow -up with in 17 fill drilling to get their injection support on line within a 18 year. 19 Then rule 10 is just a statement of our commitment to 20 report to the AOGCC. It does appear that April 1st seems to be 21 a magic date where other companies have committed to April 1st 22 so we have decided to also commit to April 1st to provide you a 23 report. We'll report on the progress of the enhanced recovery 24 project, give you a summary of the voidage replacement in the 25 previous year and also give you a pressure map showing from the R& R C 0 U R T R E P O R T E R S 811 G STREET (907)277 - 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 70 0 0 1 known data and any simulated data what -- you know, what we 2 think the pressure profile looks like across the reservoir. 3 And then finally if there are other things that we're 4 doing on the reservoir side that are interesting that can give 5 some insight as to what our recovery can be and how we're 6 progressing along our plans we'll also-show you those. 7 And then by June of that year we'll be prepared to show 8 you a technical review of the report if you so require. 9 And I think rule 11 is just a rule that we've adopted that 10 we've seen in other orders, so those are the rules we've 11 requested and that concludes our presentation for the pool 12 rules application. 13 CHAIRMAN SEAMOUNT: Thank you, Mr. Cook. Commissioner 14 Forester, do you have any questions? 15 COMMISSIONER FOERSTER: Yes, I do. Let me start with the 16 easy one what does Nikaitchuq mean? 17 MR. MOLES: It means -- in Inupiat it means perseverance. 18 COMMISSIONER FOERSTER: Perseverance, okay. 19 MR. MOLES: The ability to stand against the forces of 20 nature. 21 COMMISSIONER FOERSTER: Okay, thanks. One of your first 22 rules is the designation of the unit pool, does DNR, DOG (ph) 23 have any problem with designating that all as the unit in the 24 pool? 25 MR. COOK: I don't believe they have a problem. We -- you R& R C 0 U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 71 1 know, we'll be requesting a participating area and that 2 participating area will be within the pool and will be tied 3 somewhat to our, let's say, plans -- development plans in the 4 relatively near future so right now it will be centered around 5 the Oliktok Point drilling. 6 COMMISSIONER FOERSTER: Okay. Why only one log per drill 7 site? 8 MR. COOK: Like I said, we're gathering lots of data and 9 we were just hoping that to satisfy the requirement we could 10 just supply one well (ph), but I mean, we certainly have the 11 data. It's just a matter of procedurally whether -- how many 12 wells you want. 13 COMMISSIONER FOERSTER: Okay. So there's not a physical 14 problem with..... 15 MR. COOK: There's not a physical problem. 16 COMMISSIONER FOERSTER: Okay. 17 MR. COOK: Like I said we'll be gathering lots of data. 18 And we won't be drilling through the reservoir. You know, most 19 of our wells will be horizontal wells so -- I mean, we only 20 have a few, let's say, vertical profiles of the geology with 21 the disposal well, with the water well. 22 All the other wells we may drill a pilot hole from here to 23 the- -- you know, now and then, but most of them will be 24 horizonal so it's quite difficult to interpret where you are in 25 the strata, you know, without the geologic model and all the R& R C 0 U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 72 0 1 know, we'll be requesting a participating area and that 2 participating area will be within the pool and will be tied 3 somewhat to our, let's say, plans -- development plans in the 4 relatively near future so right now it will be centered around 5 the Oliktok Point drilling. 6 COMMISSIONER FOERSTER: Okay. Why only one log per drill 7 site? 8 MR. COOK: Like I said, we're gathering lots of data and 9 we were just hoping that to satisfy the requirement we could 10 just supply one well (ph), but I mean, we certainly have the 11 data. It's just a matter of procedurally whether -- how many 12 wells you want. 13 COMMISSIONER FOERSTER: Okay. So there's not a physical 14 problem with..... 15 MR. COOK: There's not a physical problem. 16 COMMISSIONER FOERSTER: Okay. 17 MR. COOK: Like I said we'll be gathering lots of data. 18 And we won't be drilling through the reservoir. You know, most 19 of our wells will be horizontal wells so -- I mean, we only 20 have a few, let's say, vertical profiles of the geology with 21 the disposal well, with the water well. 22 All the other wells we may drill a pilot hole from here to 23 the- -- you know, now and then, but most of them will be 24 horizonal so it's quite difficult to interpret where you are in 25 the strata, you know, without the geologic model and all the R& R C 0 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 2 0 0 1 surfaces and everything that we've done, so I don't think -- 2 for the public record I don't think there are more than a 3 couple of wells per drill site that will be of much value. 4 COMMISSIONER FOERSTER: Okay. Why no packer in your -- in 5 ur producers? Y 6 MR. GRANDI: Again, according to the regulations, the 7 Chapter 25 we're going to follow it according to the flow test 8 we'll -- we'll define in need of assist- -- I mean, of the 9 packering (ph) in unassisted flow wells, so there's no..... 10 COMMISSIONER FOERSTER: So that leads to my next question. 11 So how and when will you do your no flow tests? 12 MR. GRANDI: No flow test? 13 MR. MOLES: Steve, do you want (ph) ..... 14 MR. MASSEY: Yeah, after -- we've been instructed after 15 production is on line for I'd say a week to 14 days then we 16 could call out an inspector and do a no flow test at that time. 17 COMMISSIONER FOERSTER: Okay. Then what do you do if 18 you've got your well all pumped up with no packer and it 19 doesn't pass the no flow test? 20 MR. GRANDI: We have a plan for -- plan b for a campaign 21 of workover (ph) to really have the minimum amount of wells re- 22 -- replanned in order to have the parker in (indiscernible) in 23 order to maintain as quick as possible the early -- early 24 production -- I mean, the (indiscernible) ..... 25 COMMISSIONER FOERSTER: So you'll -- you'll plumb 'em R& R C 0 U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 73 • 0 1 (ph) up with a packer if they..... 2 MR. GRANDI: Yeah. 3 COMMISSIONER FOERSTER: .....don't pass? And how often -- 4 you know, since you're going to be injecting and you're going 5 to have all these compartments that you don't know where they 6 are, how are you going to monitor to maintain that once a well 7 passes a no flow test it will continue to pass a no flow test? 8 MR. COOK: Well, let me say that we don't have any 9 expectation that the Schrader Bluff will be able to flow 10 naturally. From the well test data that we do have from the 11 appraisal well it is clear that because of the heavy oil 12 quality that transients -- pressure transients in the reservoir 13 are such that we will be low a pressure that would -- that 14 would flow naturally so it is definitely -- I mean, obviously 15 we have to prove that and -- but under normal operating 16 conditions around the production well none of our modeling 17 suggests that we'll have pressures that would promote a natural 18 flow. 19 MR. MOLES: And as we get water break through the gradient 20 (ph) will change to become..... 21 COMMISSIONER FOERSTER: I'm sorry, you need to come up to 22 the mic if you're going to say something. 23 MR. MOLES: I'm sorry, just reminding him (ph) ..... 24 MR. COOK: Yeah, what he was suggesting is that once -- 25 once we get water break through we might have better R& R C 0 U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 74 0 1 communication between the producers and the injectors and 2 that's true. We don't see that in the modeling so obviously we 3 have to be prepared and we have to monitor it, but right now we 4 don't believe that, that is a problem. 5 COMMISSIONER FOERSTER: Okay. So that -- that's not what 6 my question is. If you find yourself with a small compartment 7 that you charge..... 8 MR. COOK: Um -hum. (Affirmative) 9 COMMISSIONER FOERSTER: .....how are you going to monitor 10 it to ensure that you can quickly identify a well that does 11 have the capability of flowing? 12 MR. COOK: Well, we'll be monitoring pressure continually 13 'cause, like I said, we will have many bottom hole pressure 14 gauges in both the injectors and the producers and with the 15 ESPs will have the bottom hole gauges so yeah, I think if we -- 16 if we saw a highly charged area that would be quite concerning 17 and we might have to take action and I'm sure Steve would make 18 me take action. 19 COMMISSIONER FOERSTER: So, perhaps, that a rule that we 20 should make you report periodically the results of your 21 continuous bio- pressure monitoring so that we -- you know, we 22 -- we found that ....... 23 MR. COOK: And what -- what (ph) ..... 24 COMMISSIONER FOERSTER: .....we found that, you know, just 25 trusting the operator to self - regulate isn't good enough so, I R& R C 0 U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 75 0 0 1 think -- how would you guys feel about that sort of a rule or 2 do you have something else to suggest in its place? 3 MR. COOK: What kind of frequency would it be because, you 4 know, that would be reported annually in our pressure surveys 5 report and, you know, a pressure map across the field using all 6 of that data. Are you talking about a more -- a more 7 frequent..... 8 COMMISSIONER FOERSTER: It might be -- a more frequent 9 might be necessary. 10 MR. COOK: And is this -- I'm just asking, are you 11 thinking about implementing this on all Schrader Bluff type of 12 developments? I mean, I'm just curious. 13 COMMISSIONER FOERSTER: Yeah. Having given it any 14 thought. 15 MR. COOK: Okay. 16 COMMISSIONER FOERSTER: Just fishing. And why should you 17 not report BHPs, bottom hole pressures in ESP wells? One of 18 the rules says that we -- you wouldn't have to report bottom 19 hole pressures in ESP wells. 20 MR. COOK: No, I think it says on wells that -- except 21 those -- oh, which one was that. I think that may be an 22 instance where a rule we've seen in other Schrader Bluff field 23 rules or pool rules and maybe we've adopted that, but I don't 24 have a problem reporting..... 25 COMMISSIONER FOERSTER: 'Cause you're going to be getting R& R C 0 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 6 1 that data. 2 MR. COOK: .....bottom hole pressures on subsurface pumps 3 -- wells. 4 COMMISSIONER FOERSTER: Okay, okay. 5 MR. COOK: I think -- I think I was reading it the 6 opposite way that -- that, you know, if you don't have an ESP 7 you have to tak- -- deliberately go get an initial pressure 8 survey, whereas an ESP it comes with the equipment so -- so it 9 was a statement of -- on those -- on some wells that you 10 wouldn't have that capability that -- that we would take those 11 pressures so more of active rule than a passive rule. 12 COMMISSIONER FOERSTER: Okay. 13 MR. COOK: I didn't mean to exclude the ESP wells 14 specifically. 15 COMMISSIONER FOERSTER: Okay, okay. And, kind of, going 16 back to the earlier discussion, should we -- you talked about 17 having a bottom hole pressure (indiscernible) drill site 18 requirement, but should we have a bottom hole pressure 19 compartment as you identify reservoir compartments? 20 MR. COOK: I think that was -- what we suggested is as 21 compartments are identified we would -- we would report the 22 initial reservoir pressure for those compartments. Right now 23 we believe we only have two. We're not sure where they are or 24 what it really looks like in terms of hard boundaries, but we 25 know we have -- we think we -- because of the fluid differences R& R C 0 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 7 0 • 1 we have two. 2 COMMISSIONER FOERSTER: Well, I'm not talking about an 3 initial pressure. I'm talking about a monitoring plan. 4 MR. COOK: Oh, monitor. Well, we'll -- like I said, we'll 5 be gathering lots of data and it's just a matter of what..... 6 COMMISSIONER FOERSTER: Okay. So that's not -- asking you 7 to provide information is not going to be an issue? 8 MR. COOK: No. 9 MR. MASSEY: No. 10 COMMISSIONER FOERSTER: Okay, all right. I don't want to 11 beat a dead horse. 12 MR. COOK: No, and we plan on providing all of that 13 information in the annual report. 14 COMMISSIONER FOERSTER: Okay. So how can you meet (b)(2) 15 on the reservoir -- the gas -oil ratio exception, how can you 16 meet (b)(2) if you -- of .240 if you aren't injecting gas 17 'cause (b)(2) says that all produced gas will be re- injected? 18 So -- and, you know, maybe -- your request may be reasonable, 19 but that may not be the way to state it. 20 MR. COOK: Yeah, I think you're probably right on that 21 point. 22 COMMISSIONER FOERSTER: So help me out, tell me it's a 23 reasonable -- tell me why it's a reasonable request? 24 MR. MASSEY: Can I ask..... 25 MR. COOK: I'm not familiar with..... R& R C 0 U R T R E P O R T E R S 811 G STREET (907)277- 0572 /fax 274 -8982 ANCHORAGE, ALASKA 99501 78 i 0 1 MR. MASSEY: Can I ask a question? I mean, what if -- 2 what do these other regulations say if you burn all the gas, 3 that's -- that's what happens to ours. 4 COMMISSIONER FOERSTER: Right, but..... 5 MR. MASSEY: We completely burn it off so we don't have 6 any to re- inject. 7 COMMISSIONER FOERSTER: Right. And that makes you a 8 little unique 'cause as you know in other places what isn't 9 used as fuel is re- injected and it's a sizable amount. 10 MR. MASSEY: Would that be a better way to state that or 11 whatever is not used as fuel will be..... 12 COMMISSIONER FOERSTER: No, because -- because you have no 13 intention of re- injecting any gas. 14 MR. MASSEY: See I..... 15 COMMISSIONER FOERSTER: I think really what I'm looking 16 for is a demonstration from you guys that there's not a better 17 way to produce this reservoir, that by allowing you an 18 exception form the gas -oil ratio we're not allowing you to 19 cause waste, that's what I'm looking for. 20 MR. COOK: Well, I think in terms of -- I mean, the 21 problem I think that you have is that we produce too much gas 22 from the reservoir and -- and we don't intend to and our 23 waterflood project is set up so that we maintain pressure so 24 we're going to do everything we can is all. 25 COMMISSIONER FOERSTER: Just want it on the record. R& R C 0 U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 79 0 0 1 MR. COOK: Okay. 2 COMMISSIONER FOERSTER: There's nothing magic about April 3 1st, is there? 4 CHAIRMAN SEAMOUNT: No, except I try to take that day off. 5 That's an inside joke by the way and don't ask her to explain 6 it 'cause she'll go on for an hour. 7 COMMISSIONER FOERSTER: And you'll be laughing for an 8 hour. 9 CHAIRMAN SEAMOUNT: At me. 10 COMMISSIONER FOERSTER: But there's nothing magical about 11 -- magic about April 1st. I think that may have started out 12 based on some budgeting cycle or something, so if there's a 13 time better than April 1st and June 1st for you guys you need 14 to communicate that to Staff. 15 MR. COOK: Actually it works out very well for us. 16 COMMISSIONER FOERSTER: Okay. 17 MR. COOK: I mean, if you get later then we could get into 18 budgeting and -- and it's enough time so that we can accumulate 19 and vet all of the data from the previous year. I think that's 20 a good time for us. 21 COMMISSIONER FOERSTER: Okay, all right. I'm done with 22 him. 23 CHAIRMAN SEAMOUNT: Okay. Well, thank you all. Is there 24 anybody else that would like to testify? Is there anybody that 25 has any questions of the applicant? R& R C 0 U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 80 1 MR. COOK: Okay. 2 COMMISSIONER FOERSTER: There's nothing magic about April 3 1st, is there? 4 CHAIRMAN SEAMOUNT: No, except I try to take that day off. 5 That's an inside joke by the way and don't ask her to explain 6 it 'cause she'll go on for an hour. 7 COMMISSIONER FOERSTER: And you'll be laughing for an 8 hour. 9 CHAIRMAN SEAMOUNT: At me. 10 COMMISSIONER FOERSTER: But there's nothing magical about 11 -- magic about April 1st. I think that may have started out 12 based on some budgeting cycle or something, so if there's a 13 time better than April 1st and June 1st for you guys you need 14 to communicate that to Staff. 15 MR. COOK: Actually it works out very well for us. 16 COMMISSIONER FOERSTER: Okay. 17 MR. COOK: I mean, if you get later then we could get into 18 budgeting and -- and it's enough time so that we can accumulate 19 and vet all of the data from the previous year. I think that's 20 a good time for us. 21 COMMISSIONER FOERSTER: Okay, all right. I'm done with 22 him. 23 CHAIRMAN SEAMOUNT: Okay. Well, thank you all. Is there 24 anybody else that would like to testify? Is there anybody that 25 has any questions of the applicant? R& R C 0 U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 80 1 Okay. Hearing none, I'd like to take at most a 15 minute 2 recess, at most and we'll come back in and see -- we may have 3 more questions. We will make a decision on the confidential 4 material, too. Okay. Thank you. We're off the record at 5 11:12 -- no, 11:13 and we'll be back by 11:27 -- 28. 6 (Off record - 11:13 a.m.) 7 (On record - 11:27 a.m.) 8 CHAIRMAN SEAMOUNT: It is 11:27 and a half. Okay. 9 Commissioner Foerster has some questions as she always does. 10 COMMISSIONER FOERSTER: And whoever -- you guys can just 11 punt it to which ever one of you is best -- is most comfortable 12 answering the question. If you do end up having surplus gas 13 what are you going to do with it? 14 MR. MASSEY: Do you want me to answer that? 15 MR. COOK: That would be a nice problem to have I think. 16 MR. MASSEY: That would be a nice problem for us to have, 17 but what we would do probably in the interim before we actually 18 -- we would have to cut back our wells or we would -- you know, 19 we would have these wells listed in GOR -- high GOR and do just 20 like everybody else would to where you run out of gas capacity 21 and shut in that well. I mean, that's what we'd have to do 22 until we -- until it healed up near well bore and..... 23 COMMISSIONER FOERSTER: What would you do with the gas? 24 MR. MASSEY: We can't -- we couldn't do anything with it. 25 We're -- we'd have to burn it. If we went too much that we R& R C 0 U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 81 • 0 1 couldn't burn..... 2 COMMISSIONER FOERSTER: And we don't let you burn. 3 MR. MASSEY: No, no, no. No, no. We -- in our turbines 4 if we go past that point which we think we're always going to 5 be gas short, but if we went too much then we would have to 6 shut in one of those wells, that's what we would do. 7 MR. MOLES: I'm David Moles. If I could interject a 8 couple of points. One is we haven't presented a gas production 9 profile versus a consumption profile, but our production is 10 approximately, shall we say, half of our need and so there is i 11 some contingency here in our plan and we're currently working 12 to try and buy gas from a unit we understand is going to go gas 13 short, also, is purported to go gas short in the future. So if 14 we had access gas I'm sure that an arrangement could be made, a 15 business arrangement to reverse the flow of gas out of the 16 Kuparuk supply system where we could sell them whatever modest 17 amount of gas we might have as access. 18 COMMISSIONER FOERSTER: Okay. I want you to be patient 19 with my questions 'cause I suspect all of you have been working 20 long enough that you've been surprised at least once by 21 something. Would you ESPs be tubing conveyed or through 22 tubing? 23 MR. GRANDI: Yeah, essentially through tubing conveyed. 24 We left some (indiscernible) -- through tubing convey, the 25 plan..... R& R C 0 U R T R E P O R T E R S 811 G STREET (907)277 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 8 2 0 • 1 COMMISSIONER FOERSTER: Through tubing. 2 MR. GRANDI: .....for now, yes. 3 COMMISSIONER FOERSTER: Okay. You referred to several of 4 your wells having bottom hole pressure gauges. Which wells or 5 which types of wells won't? 6 MR. COOK: Right now we're planning for -- I think for 7 every well to have one, but you never know if -- if they'll be 8 working or the -- the only well -- I think Maurizio if you can 9 confer it, I think the only well that we don't have definitive 10 plans on are some of the injection wells that are not heavily 11 monitored, but I'm -- I'll be asking for them to put those in 12 so that -- our goal -- my goal at least is to try to have one 13 on every well. If you'd like to comment. 14 MR. MARK COOK: Would you like me to address that? 15 MR. GRANDI: I don't -- you are the -- can Mark Cook our 16 completion engineer maybe detail something? 17 MR. MARK COOK: I can answer some of that. Right now..... 18 COMMISSIONER FOERSTER: Come up and introduce yourself and 19 get your name on the record and..... 20 MR. MOLES: I don't believe he's one of the people sworn 21 in. Did you raise your hand? 22 MR. MARK COOK: No, I did not swear in. 23 CHAIRMAN SEAMOUNT: Okay. Is that necessary Mr. Attorney 24 General? I guess it wouldn't hurt. 25 MR. BALLANTINE: It's up to you (ph). R& R C 0 U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274-8982 ANCHORAGE, ALASKA 99501 8 3 0 • 1 CHAIRMAN SEAMOUNT: Please raise your right hand. 2 (Oath Administered) 3 MR. MARK COOK: I do. 4 MARK COOK 5 called as a witness on behalf of ENI US Operating Company, 6 Inc., testified as follows on: 7 DIRECT EXAMINATION 8 CHAIRMAN SEAMOUNT: Please state your name, whether you 9 want to be considered an expert witness and your 10 qualifications? 11 MR. MARK COOK: Okay. My name is Mark Cook. I have a 12 B.S. Degree in Mechanical Engineering from Colorado School of 13 Mines. I've been working in the industry for approximately 15 14 years, the last approximately 10 of those years have been in 15 Alaska working viscous oil, heavy oil development and spent the 16 last two and a half years with ENI working this project so I 17 think I would probably be considered as a completion, downhole 18 technical expert in that area. 19 COMMISSIONER FOERSTER: Mechanical Engineering Degree? 20 MR. MARK COOK: Yes, um -hum. 21 COMMISSIONER FOERSTER: Okay. That's pretty unusual for 22 Colorado School of Mines. 23 MR. MARK COOK: Um -hum. (Affirmative) 24 CHAIRMAN SEAMOUNT: School of Mines. Okay. Any 25 objection? R& R C 0 U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 84 0 ! 1 COMMISSIONER FOERSTER: No. 2 CHAIRMAN SEAMOUNT: Okay. Mr. Cook, you're designated as 3 an expert witness in completion and downhole engineer. 4 MR. MARK COOK: Thank you. 5 CHAIRMAN SEAMOUNT: Please proceed. 6 MR. MARK COOK: Okay. In addressing the question of 7 monitoring for our wells as David stated earlier all of our ESP 8 wells are planned to be fully monitored with intake pressure, 9 discharge -- or discharge pressure temperature, intake pressure 10 temperature. We'll have some vibration standard ESP monitoring 11 packages. 12 As far as our injection wells go right now we have two -- 13 two designs. One being heavily monitored which is part of our 14 commitment to try to understand our waterflood hopefully to 15 improve efficiency which would maximize production for us, but 16 in the heavily monitored injectors we do have some slides in 17 our confidential section that show injectors. Hopefully with 18 our desired monitoring package if we can make this feasible for 19 installation would include distributed temperature sensing 20 through fiber optics plus pressure temperature gauges that heel 21 to toe (ph) of these laterals, so with this injection design we 22 would be fully monitored and be able to report that. 23 COMMISSIONER FOERSTER: As long as it worked? 24 MR. MARK COOK: Yeah, as long as we get that data as David 25 mentioned, if everything is working. Also on our more standard R& R C 0 U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 8 5 1 injectors without quite the monitoring we would also have a 2 pressure temperature gauge at the heel of the well which would 3 be indicative of our reservoir TVD so our plans are at this 4 point we would have most gauges working in producers and 5 injectors monitored. 6 COMMISSIONER FOERSTER: Okay. I have one more question. 7 MR. MARK COOK: Um -hum. (Affirmative) 8 COMMISSIONER FOERSTER: We like to show some rhyme and 9 reason in what we do and some continuity of thought from pool 10 to pool where they're similar and since you've stated that you 11 think that this is possibly continuous with and definitely 12 correlated to the West Sak and the Schrader Bluff, I'd like for 13 you to take some time and look at the pool rules for those two 14 pools and see if there's anything in those pool rules that you 15 can't live with because as we formulate our final determination 16 of what your pool rules will be that will -- those two will be 17 our go by to look for similarities. 18 So I'd like to suggest that we keep the record open for 10 19 days to give you guys a week and a half to look through those 20 two sets of pool rules and get back to our Staff with oh, gosh, 21 if you make us do this that you make 'em do at Milne Point 22 then, you know, these bad things will happen or we don't care. 23 You know, we -- so -- do you understand what I'm saying to you? 24 MR. COOK: I think so. We've looked at those rules and 25 there are some differences, but I don't think there's anything, R& R C 0 U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 86 1 but let us -- let us..... 2 COMMISSIONER FOERSTER: Well, take the time to look at 3 them..... 4 MR. COOK: .....review and then what you're asking for is 5 a letter..... 6 COMMISSIONER FOERSTER: An e -mail. 7 MR. COOK: Or an e -mail describing..... 8 COMMISSIONER FOERSTER: An e -mail is fine to whoever in 9 Staff you've been working with. 10 MR. COOK: Okay. 11 COMMISSIONER FOERSTER: And so we're going to leave the 12 record open for 10 days. 13 CHAIRMAN SEAMOUNT: We'll leave the record opened until 14 October 9th and if we don't hear back from you we'll assume you 15 don't have any problems or..... 16 UNIDENTIFIED VOICE: I think that's a Saturday. 17 COMMISSIONER FOERSTER: Okay, October 8th. 18 CHAIRMAN SEAMOUNT: Okay, October 8th. I didn't know it 19 was a Saturday, but okay. My I -phone is not working well, I 20 guess. Okay. 21 COMMISSIONER FOERSTER: I don't have any more questions. 22 CHAIRMAN SEAMOUNT: Okay. One last opportunity for 23 questions of the applicant. Hearing none, we resolved the 24 confidentiality issue. We have enough to make a decision 25 without using what you would like to be kept confidential so R& R C 0 U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 87 i • 1 we're going to consider it as being voluntarily submitted. You 2 can take it back or trust it that we'll keep it confidential. 3 We'll take it out of what goes into the official public -- no, 4 I can't do that? 5 MR. BALLANTINE: They can't take it back. 6 MS. COLOMBIE: You can't take it back. I will pull it 7 from the public record and it will be permanently in the 8 confidential room under the CO number. 9 CHAIRMAN SEAMOUNT: Okay. 10 MS. COLOMBIE: We can't give it back. 11 CHAIRMAN SEAMOUNT: Okay. But we will keep it 12 confidential. 13 COMMISSIONER FOERSTER: But it goes out of what..... 14 MS. COLOMBIE: Correct. 15 COMMISSIONER FOERSTER: Okay. So it needs to get pulled 16 out of that copy. 17 MR. COOK: These same exhibits are also -- were included 18 in the application as confidential as well, so there isn't 19 anything new. 20 CHAIRMAN SEAMOUNT: Okay. Sounds good. Any final 21 comments? 22 COMMISSIONER FOERSTER: Yes. 23 CHAIRMAN SEAMOUNT: Of course. 24 COMMISSIONER FOERSTER: Of course. I wish ENI the best of and I invite you guys to call u 25 success in this operation on us y g y P R& R C 0 U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 8 8 1 to clarify any ambiguity you see in our regulations or our 2 regulatory process because we want you to comply with our 3 regulations. There are there for a purpose and once you comply 4 with them we're not about got cha games. And we're very -- 5 part of our statute is to encourage greater ultimately 6 hydrocarbon recovery and we can't do that by stopping you from 7 doing your jobs So we wish you the very best of luck and 8 success and please call on us if we ever can be of assistance 9 appropriately. 10 CHAIRMAN SEAMOUNT: And I would like to thank Mr. Massey, 11 Mr. Cook, Mr. Cook, Mr. Grandi and Mr. Moles for a very 12 professional, complete and very interesting presentations and 13 prove that you guys are experts in your disciplines. I'd like 14 to congratulate you guys on your success. 15 And with that we are adjourned at, what is it, 11:38. 16 Okay, 11:38, thank you. 17 (Recessed - 11:38 a.m.) 18 19 20 21 22 23 24 25 R& R C 0 U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 8 9 1 C E R T I F I C A T E 2 UNITED STATES OF AMERICA ) ) ss . 3 STATE OF ALASKA ) 4 I, Rebecca Nelms, Notary Public in and for the State of Alaska, residing at Anchorage, Alaska, and Reporter for R & R 5 Court Reporters, Inc., do hereby certify: 6 THAT the annexed and foregoing Public Hearing In the Matter of ENI US OPERATING COMPANY, application for Pool Rules 7 for the Proposed Nikaitchuq Schrader Bluff Oil Pool in the Nikaitchuq Unit Beaufort Sea, Alaska in conformance with 20 AAC 8 25.520, Docket No. CO- 10 -14, was taken by Suzan Olson on the 29th day of September, 2010, commencing at the hour of 9:00 9 a.m., at the Alaska Oil and Gas Conservation Commission, 333 West Seventh Avenue, Anchorage, Alaska; 10 THAT this Hearing Transcript, as heretofore annexed, is a 11 true and correct transcription of the proceedings taken and transcribed by Suzan Olson to the best of her ability; 12 IN WITNESS WHEREOF, I have hereunto set my hand and 13 affixed my seal this 8th day of October, 2010. 14 15 Notary Public in and for Alaska My Commission Expires: 10/10/10 16 17 18 19 20 21 22 23 24 25 R& R C 0 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 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION ENI Nikaitchuq Pool Rules Hearing September 29, 2010 at 9:30 am NAME AFFILIATION PHONE # TESTIFY (Yes or No) 1yPy99P1 A,=-h/, -.3 318 �S sSar. olvo 8, 6 -3 3 o I 1c s - 3 3 cfv Yp s All 8bs'� 33aa # RE 1336 Y65 e�7 n `�P 5 - - 33[L( y1\0 � L GA -c � Nikaitchuq Field Pool Rules Hearing September 29, 2010 • 2n� Nikaitchuq Field Pool Rules Hearing Nikaitchuq Project Introduction David Moles - Alaska Eni Representative and Development Manager e nni us operating Exhibit l: Nikaitchuq Project Summary NIKAITCHUQ Future Operating statistics Field Life Cycle Development Project Type Oil, FOR - '3 E i Gross Acres 34 Working Interest 100 First Production 2010,2011 Gross Peak Flow 28,000 MBOPD Rates Productive Life 30 Years Development Wells 52 r cni uss operafing • 3 2no Exhibit 2: Schedule to First Oil NIKAITCHUQ 2008 2009 2010 2011 PROJECT PR03ECT AUTHORIZATION: RE- AUTHORIZATION • .. .............. ............................... .. ............................... - Project Execution ' Gravel Offshore P/L Onshore P/L Drillsites Installed Installed Installed Sea Lift Modules \ \Sea Lift Modules Shipping \ Arrival in OPP All 1St oil Modules in OPP OPP Mechanical Completion (Oct, 23th ) OPP FCO Completed (Nov, 30th) ONSHORE 1ST OIL Start D &C A Re -Start Operation D &C OP26 O eration OP03 ; p OP23 OPO4 OP08 OP12 OP05;; 0I -11 OP -17 0I -07 ............... OILWELL ... ..... CISROSJO L ...................................... ............................... WASTE -...... OIL........ ... WATER. ....... ...O1L ....... ...... WATER - INJECT......................... WELL WATER WELL WELL WELLWELL', INJECT WELL eni us operating 2 n 11 4 i rr �r r� rr rr �r rr r i■r r r rr r� rr r� rr rr rr �r j Exhibit 3: Sealift of Processing Modules NIKAITCHUQ a E. C i -- cno us operraHng 2no 5 Nikaitchuq Field Pool Rules Hearing Nikaitchuq Unit, Proposed Pool and Well Development Plan and Drilling Progress Dave Cook - Reservoir Project Manager cni us operating Exhibit 4: Nikaitchuq Field Pool Rules Hearing NIKAITCHUQ Submitted - August 20, 2010 Hearing - September 29, 2010 Agenda Project Introduction Nikaitchuq Unit and Definition of the Requested Pool Geology and Reservoir Drilling and Completion Operations and Facilities Requested Pool Rules Question & Answer (Public) Confidential Slides Confidential Question & Answer Follow Question & Answer (Public) eni us operrarin a ; Exhibit 5: Nikaitchuq Unit Vicinity Map NIKAITCHUQ BEAUFORT SEA Nika' chuq I I I _ _ NatlosN htroNms L8QBf1d j Rsservs lUSSks -_- I � I Nlkaltchud Unip I Unl% EN L...h ld j Pipelines • Tovms -- cni us operrafing 2no 8 I Exhibit 6: Development Scenario Schematic NIKAITCHUQ inshore island drillsite ♦ �.� Onshore ♦ drillsite ♦ � c .X ..... ♦ Process facility IM Co astlin e IM Key: W -♦ sales oil 7 6perations .�� 3 -phase produced fluids L camp p -P_ Water injection 3 -0 Fuel gas -♦ Diesel _ _ Power & Fibre -optic cable To Kuparuk Pipeline & TAPS eno us operria ring 2ni 9 Exhibit 7: Historic Lease and Ownership Map (prior to January 1, 2007) NIKAITCHUQ AD1389719 ADL390433 ENI (30) ENI (30) ADL389720 KMC (70) ENI (30) KMC (70) KMC (70) ADL388579 . ENI (30) ADL388573 ADL388571 KMC (70) ENI (18) ENI (18) ADL388581 ADL388580 ENI (30) ENI (30) KMC (82) ENI 1572 KMC (82) KMC (70) KMC (70) KMC (82) 'r j ADL388574 ADL388583 ENI ENI (30) ENI (18) ENI (30) ADL388575 KMC (82) KMC (70) ADL388582 KMC (70) ENI (18) .-_ __._. __. -' ENI ( KMC (82)'. KMC (70) T-- I ADL355024 ENI (45) KMC (55) ADL388578 ADL388577 ADL390616 ADL390615 ENI (18) ENI (18) ENI (30) ENI (30) KMC (82) KMC (82) j KMC (70) j KMC (70) I Eni WI% 18 - U 30 ` 45 cni us operating Ce na 10 Exhibit 8: Nikaitchuq Unit Ownership Map NIKAITCHUQ petroleum ADL389719 Tract 003 ADL390433 AD 89720 Eni (100 Tract 001 Tract 002 - - -- - - - --- Eni (100 1/6) Eni (100% - ADL388579 __ Tract 006 ___. - - - - +- Eni (100 1 /6) ADL388580 ADL388571 ADLJ188581 Tract 005 - Tract 011 ADL _ Tract 4 388573 _ - En t(100 %) - Eni Tra ct 0 004 Eni (1!00 %) Tract 013 _. ADL388572 - Eni ( {00"/0) Tract 012 Eni (100%) ADL38858 Tract 007 ADL388574 Eni(100%) Tract 014 - ADL388582 ADL388575 Eni (100 %) TraetM5 Tract -0l5 Eni (100 %j - - - Eni (1100 %) _ ADL355024 Eni WI% Tract 018 Eni (100 %) ADL390616 ADL390515 ADL388578 ADL388577 _ _ . Tract 0113 _ . E ract -Tract 01-7- _Tract -016 Eni (100 %) • Eni (100 %) Eni (100 1 h) -- cno us ©perraCing CA ni �� Exhibit 9: Base Map as of July 2010 NIKAITCHUQ 0 a s e • Nik -01 s Nik -04 Twaaq Nik -02 KR sland 1 _. .. K, _ NW -Milne 1 KR— e ig KRF KR Fb K IT KR 30 KR F-00 e F60 Pal F Fa0 B OPO4 -07 KRF- RF RF -A 8 K -10 KR OP03 -P05 KRF -ro F� K �]O PBt KRF -18 R OP -12 OP0 &04 - 3 3 OP2 WW0 KR F- F- KR F OGRK -1 m KR 1 KR S 026 -DS 2 __ .. O PB -01 OP -1 KRF -z a • Glkid .� ,� c Ft. S a F KR P 4 R— KR KRU 3R10 KR F13 Y Eni Oliktok Point �, -, g KRU -15 FU5 I Iii o oint 2 A�. KR KRF Kq�i R �dRRU 38.18 -12 A KR 9 EHB St 1 K Nlk.hu I.- Sehnd�r 9lua D�wb m�nl 0 2000 4000 8000 8000 10000k ie <OOOO � [ EE3R Milne Point F -- eno us operating eni 12 Exhibit 10: Well Drilling Field Spider Diagram NIKAITCHUQ ol m0000 494000 aee5o5 401000 4ee00D eo5em ao400e a5eom erm06 e,eoao em5m el 4000 emw e1a0m gg SNGk ,I. I 490000 4&MO !8000 401000 s05000 X0000 509W0 50e000 5,1000 e,e000 6]0000 914000 378000 .. 535m Wkaitchuti 2090 hoposed Optimized Well Pattem unto OPP SID Totals 0) Injector 8 13 21 CL Producer 10 16 26 = Disposal 1 1 2 a� Water source 3 0 3 Totals 1 22 1 30 52 cn� us operrafing �3 2n n Exhibit 11 OPP 2010 Drilling Progress Map NIKAITCHUQ Oil 1 -01 Reference wells OA top location 502000 504000 508000 508000 510000 512000 514000 518000 518000 520000 522000 524000 • 0953 [P7] I N • OP10 -00 [P1] \ \ OIX % -06 $ 0113-03\ \ \ \`' • \ 7, 0106-05 [P3] \ I os OP17 -02 [P3] \ \ \ \ \ \ \ \ \ I I I OP15 -08 [P2QI 11 \ \ \ \ oP12.01 \ \ \ \ \ \ \ \ \ op I I \ \\ \\ oP Prod LIm 0111 -01 [P6] I I I \\ \ \\ \\ ON -WW02 I OP76- 21 \ \ \ \ I I I 118-07 IP221 \ \ \ \ \ \ \ 6-DSP02 � I I I \ \ I Oda1 s \ \ 0 2PB -01 \ \_ - - -- \ I OPO 05P9Y -WWO Remaining Well for 2010: OP17 -02 P 8 m 502000 50/000 500000 508000 510000 512000 514000 518000 518000 520000 522000 511000 Schrader Bluff OA development] 0 500 1 �Yy— °0° 1 1 Dafe 1:20000 Drilled Development Wells in Solid Green / OP -12 in Solid Blue / Current Well in Red �- eni us operaring PAIN 2n 14 Exhibit 12: Proposed Pool Area (shown in Green Dashed outline) NIKAITCHUQ petroleum — ,-- A.DL389719 Trail 003 Nikaitchuq Unit ADL390433 AD 9720 Eni (1p0 %) act Tract 001 Eni01002 Eni (1,00 %) ADL38857 9 �T Tract 006 V- - - --- Eni (100%) ADL388580 ADL388571 ADL388581 _Tract 005 - ADL388573 Tract 011 _ - _ Trail 004 ------ Eni (100 %) Trad 013 _ADL388572 _ Ent (100%) Eni (100%) Eni(jOft) Tract 012 Eni (100%) ADL38858 Tract 007 ADL388574 Eni (100%) Tract 014 ADL388582 ADL388575 Eni (100%) Tract-008 Eni (100°/,) Tract 015 _ - - -. Eni (100%) ADL3$5024 TragV 8 Eni (1W16) ADL390616 ADL390515 - ADL388577 Tract 010- Tract 009 ADL388578 Tract Tract{ 316 -- Eni (100%) Eni (100 %) T 017 - Eni (100 %) Eni (100%) eno us operating e: n 11 15 Exhibit 13: _i ype Log with Proposed Pool Correlative Interval NIKAITCHUQ N - 9ZAtlE14�SN.R - MO 'i 1:500 0.2 ABF30 200.0 3500 ' Bluif 3400 chradar BIO z 3550 r W 3450 W ( Pt 3600 W CO N ToP —... __ Top V 1 Z/ 3500 N -2 Z 3650 O O N Bottom Bottom _' _ 3550 f"f � O Inter Marker — — - - -- — — — —"'- -- X744 Inter Marker / �\ , ^ 3600 3750 \ OA Top 3650 OA - 1 OA Top V �' O _ OA -4 OA Bottom A Bottom rn T 3700 a v /1 \ v a 385011 O 1 V SB POOI Base — - -- - -- -- — — -" SB Pool Base U 3750 i 3774 _ _ 3906 .... - - -- - -- cno us ope 2n o 16 w� wi iw iw �w w w w iw �w ww ww rw �w w �w w� w■� w Nikaitchuq Pool Rules Hearing Geology and Reservoir Dave Cook - Reservoir Project Manager i -- a nni us ® erratinn Exhibit 14: Strategraphic Column NIKAITCHUQ 9T�RMRD Bq9 T—y .—T = CRRJROSIMIICRAPNY Ee 8 MORTR SLM., ALASKA LS H tS C� a� ;� OEMERALO'ED GRWF9. FOAM <TIOM9E YEMBER3 F ssnY -aAaY E W 29 w O 5 um NS 0 5 v ssm aKr . U Lu t x910 . • ��., yi a � i x M . Targeted Schrader Bluff F + ' Formation fF — w W a ■.. -- cni us operaring en no �$ Exhibit 15: Seismic Survey Outlines shown with Well Pattern and Fault Map NIKAITCHUQ 47219 476000 48701 481000 488000 492000 49601 50100 56401 508000 512000 518000 520000 52410 52801 532000 536000 54001 544000 548000 552000 Thetis Island 3D �f m __ Simpson Sp. Lagoon 3D C - t I SP 777666 �. �\ m \ l l S " l Mt ft ft � - " _ o Po _ — Nikaitchuq $ 3D PGS 2008 472000 476000 490000 480000 488000 49210 496000 500000 504000 508000 51201 516000 570000 52401 52801 532000 536000 510000 544000 SC8000 552000 Nikaitchuq Development 6 2500 shoo Iwo 16606 ,zsooa �- cni us operal6ng enn 19 oZ uuaU) Bugeja a sn wa 0000v1 _ 180001 0008 0009 0006 000E O ApYMi.MNwm, arl • � l 1S BFC� tlEl BI 141m� � eaN e si rup r o�:xn sPa Ap _ _ .....,. qg a, d ere l 90d�' dx i 4pijsdai.��dn Z IN `\ gg � I bnH:)lIVHIN pupS VO 4o dol - a.an4DnagS paseq :)iwsi@S :9T q!q!gx�j r �r r r �r r■r r r rr rr rr rr r r r r r r r Exhibit 17: Sedimentological Environment Concept & Core Description NIKAITCHUQ NIKAITCHUQ 4 4.3 [rw KIGUN 1 4125 F , 3778 - - . _..- r - - .. - - -� -_. 4130 -, - 4 ` i - .fit Outer shelf y � _ - -- . 4135 , - _ 3780 _�� 4140 Shelfal Lobe .,3785 _� '-'- -. ___-- ..- __.`. .. .. : 47..75 3790 — -r- .- -• Shelfal Lobe .. 3306 .._ ,.a -. - 41.80 — Shelfat Lobe , 3305 — .... .. r - 4185 iM arts i r _ r - - Distal Prodelta .nn 4176 M.S.: 1 :20000• v S. • Mudstone (massive & /or laminated) ❑ Sandstone F & VF grained (massive & /or laminated) ® Siltstone & Mudstone (high hioturbation) F-1 Sandstone M & F grained with clast trains cn� us operrafing 2 n 11 21 Exhibit 18: Map of Well Data Set & Petrophysics NIKAITCHUQ — 0.100 . , ul- a' •R 3 o OP03 -P05 PB1 • OP03 -P05 • OP26 -DSP02 005000 n0000 00lOfD 000000 [85000 .OKOO ONWO ROWA 3000,0 ,IW]OC 5.3,00 3At0C0 R]30[O 531000 3500 500[00 SOSO]0 SSOOA 555000 Nlkattchuq 200 We0 Dataset Gross Thickness: 35 -47 feet Net -to- Gross: 65% - 93% (high side is from a lateral well) Porosity: 24% - 35% Water Saturation: 23% - 45% (high side is likely in a transition zone) Permeability: 92 - 627 and �-- cni us operrafing e n 11 22 m m m m m m IM ! m m m i IM m i Exhibit 19: OA Net Thickness Base Case NIKAITCHUQ 470000 480DOD 49DOW QOOWO 610000 520000 63°°00 590000 44 qw 35 ) \ 32 l w 04 , } 1 O ( � t 3 �- OP -12 1\ E a S 1 I OI } 47000D 48000D 470000 700000 5,0000 520000 530000 54000 Nlkaltehuq 2009 OA Thickness BC ° 200° e6000 (�� cni us operating 23 ^n o Exhibit 20: Nikaitchuq OA Sand waterflood Project NIKAITCHUQ The OA sand development is a heavy oil waterflood. 4'000- 8,500' Horizontal wells in a line drive pattern. Voidage replacement strategy 1 to 1 The OA oil is on the upper end of the heavy oil classification. Wall ON . Bub�le� �lut�c►n F6rm tl©h V.61ume " Gas Lvlseoslty I Mint l:actor, ( �►)" Gravity , c - *Apt l 4-0,1 b ir1� .fib OP -I1 16 1150 140 1.050 0.59 188 OP -I2 19 750 80 1.045 0.67 100 The initial reservoir pressure is 1700 psi at datum of -3760' TVDSS. Schrader Bluff OA OOIP: 800 -930 million STB. Range of potential 30 year technical recovery: 15% to 22% of the lease OOIP. — eni us operrat'�c Exhibit 21: Deterministic Approach Recovery of Oil and Oil Rate Profile NIKAITCHUQ Nikaitchuq 2009 Reservoir Model Field Oil Rate and Cum Oil @ 30 Years 40,000 Cumulative Oil: 180 million STB 200 Recovery Factor: 21% 180 35,000 160 30,000 140 o p m v U) 25,000 V w r . 120 P , 20,000 100 �+ > o / 80 15,000 > 60 V Q 10,000 / 40 • 5,000 20 0 0 2010 2015 2020 2025 2030 2035 2040 2045 Year —�DailyOil Rate — Cum Oil cno u s operating 25 ^ ^ o Exhibit 22: N Sand Structure Map with Possible Oil Water Contacts NIKAITCHUQ Top N Sand - WUT @ -3949 � SODD I 4200 dm0 QE00 ET 1 \ >� • OOOOURUN , O IwnlmRw rwe S � l '- (—' � 1 �� `� �. \ � ~'�, �•. �w. \� 7 J � moo TI _ ��77 T � TCiU�fi'Z\ C \ Q I \ 1� ilele „® Top N Sand - ODT @ -3643 ;- cn� us operafing • ° c n o z6 Exhibit 23: N Sand Future Potential NiKAiTCHUQ The N sand is considered a future potential development for the Nikaitchuq Unit. A data acquisition plan for the N sand is in place. N Sand uncertainty: Compartmentalization - updip well EHB St #1 Northern potential beyond well control - difficult to map N sand from seismic. Fluid properties Petrophysics Porosity: 23 % -33% Water Saturation: 13 % -22% Sand well developed and full to base in the Kigun #1 Range of potential resource within the Nikaitchuq Unit 300 to 600 million STB. eni us operating Exhibit 24: OA and N Sand Mapped and Prospective Sand Outlines NIKAITCHUQ 8 8 . .... ............................... . Prospective OA c 8 . ............................... .. g c Prospective N Nk - 01 Nik -04 Tl aq Nik -02 ' a 8 KR stand 1 Klgun NW -Mine 1 KRFaz F s KR KRF - KR 38 KR R OPO4 -07 �Fao FB+ RF F Fao s OR) P05 KR ` �A RB1 KR OP -12 OPO &04 K OP2 WWO 's OGRK -1 F- Mapped OA 026-DS 2 Mapped N O PB -01 °P R ` KR g • OIik1U %. 5t Fg� a K P RFOe il " K -to II'\ S ill RU 3R -10 A KRU 3R 11 8 Ii o oird 2 A KR F KR g U ]! RO 12 A R K0. K EFB St 1 KR 8 NIkaachu F.M- SChraA.faWR U1V.b Ilwnt .eamo .exwo .va000 B4400° 0 2000 4000 8000 8000�1000OR sww azowo ax.wo azww aawo ma000 avow F 1:40000 -- cno us operating e n i 28 I I • Nikaitchuq Field Pool Rules Hearing Drilling and Completion Maurizio Grandi - Well Operations Project Manager i .� eni us operating Exhibit 25: Well Drilling Field Spider Diagram NIKAITCHUQ aoom smm eee000 mzo mm aaoom aoaoo aoe000 s�moo e.e .. ma000 eacm eanao r i� pQ$, .e \ MLMIM E. Ow? \ w aeomo nen000 +ea000 mmm mmrm eaoaoo eoaoao maoos ,.'w..» eie000 ealmo samm s:eoao aamao Nikaltchuq 2009 Proposed Optknized Well Pattem y moon OPP SID Totals m Injector 8 13 21 Producer 10 16 26 Disposal 1 1 2 Water source 3 0 3 Totals 22 30 en0 us operafing e II II o 30 Exhibit 26: Example Well Bore Schematic NIKAITCHUQ 1 % Eni Pe Schrader Bluff Nikaitchuq Field w- CSG Profile North Slope - Alaska DIR LWD FORM DEPTH HOLE CASING MLIDINFO MWD MD TVD SIZE SPECS INFO Cement to Surface 20" n 20 Conductor Shoo 120' IF20 ` Nry WA t Waded Drive 1,11A Surface Cog 13-3/8" 68 lbs/ft Wellbore Stability Top of Pernnafrost a 0 L-60. BTC +/-10,0 ppg Lost Circulation Hole Cleaning KOP'.180-450 M DLS: 2 deg/100 M Sail Angles: iiiiiii 30-70 Base Per-1-1 +/-1950 ./-IWO Top of Tail Cement 13-318"Casina Point +/-29001+/-2100 le" So- F wam MND/GPJ RES/A FWD Into r. Casino Wellbore Stability Rotary Steerables 0-5/8" Lost CPCUlation IlFRfCas 47 lbs/ft -/-Q.O ppg Hole Cleaning L-80, BTC-M Torque & Drag Sol A rgis: 50-80 degrees Top of Cement +1-8500 WBM 43,825" 90° 12-1/4" 85 °F NWD/GPJ 9-5/8" Casing Point 2 9000, RESAPWD Wellbore Stability Los Circulation Schrader Bluff Hole Cleaning Lateral 90. 5- 1/2' "c -1/2" Torque & Drag 17 lbs/ft -/-9.0 ppg Horizontal L -80, OWC/ drain I I ho,il g0° Rotary Steerable (Geo-Steering) 8-1/2" Proposed TO 17,000 3,825- 85- F sum eno us erating Exhibit 27: well Drilling & Completion Criteria NIKAITCHUQ All wells will be equipped with a fail -safe automatic surface safety valve system capable of preventing an uncontrolled flow All injection wells will be equipped with landing nipple at a depth below permafrost, which is suitable for the future installation of a down hole flow control device To facilitate wireline access, packers may be located more than 200' above the top of the injection zone; however 1) packers will not be located above the confining zone 2) the production casing cement volume shall be sufficient to ensure cement placement is a minimum of 300' measured depth above the planned packer depth -- eni us operraCin, ° +.t aN t ``' .2.;+ e ' a„ x r t,t.c ✓ u a as rpzz i Nikaitchuq Field Pool Rules Hearing Facilities and Operations Steve Massey - Production Manager -- cni us operating Exhibit 28: Development Plan Map NIKAITCHUQ Development Plan Offshore Island Gravel r t- -k Island j • One gravel pad initially f • Water depth –6 feet • Accommodate barge access - -- — Ook Poin r .. Flowline Bundle DS =3R ' I 1 .. i • 3.1 -mile buried flowline �+ bundle G -,«.�- ; � i fi , ,• ;. - I i . • Pipe -in -Pipe Production WI /Pipe -in -Pipe Diesel Gash • Power & comms cable Oliktok Point Production Pad • Process 3 phase flow Export Line • 14 -mile export line to Kuparuk Pipeline on new VSMs (10" line pipe - CF F4, - already purchased) ! ,.. ,.; . + .o. ... Y - - cno us operraCing e II 11 II 34 Exhibit 29: Nikaitchuq Onshore Drillsite /Processing Facility Overview NIKAITCHUQ Q1�p� Tank Farm Fa Comms Tower D1E04 oo � Q o'� GsO ��p2 �a aG�Oe�p ` e` Q Q �pe� s tl`N X O�� bi Disposal y ? Well Shelter F er s PFW01 A � FJ ��p� Qp5 0 8 a k pPR o • s ,0 �;��O- 03 Pipe Rac Flare PFUO3 PFR03 Pipe Rack PFR04 cni us operraHng • n no 35 m m m m m m m m m m m m m mm m m m � Exhibit 30: Oliktok Point Pad (OPP) NIKAITCHUQ i � � f r . A 4 � , :may F i _r �m eno us operating 2 n o 36 Exhibit 31: Spy Island Drill Site (SID) NIKAITCHUQ so =H v"Mos it ----------------- I --------------------------------- ------------------ vm-m 1AW 1C3-M V.LL M Ala. Mt. PL_ A—%L 2ftt. PL— ME WA 62. M.. 4 UM WI I& Z— 4 ave- TNWN S SLM _ fill! z�tz 112M 70 COO coo 004) c2uw W-M5 C=13M umm goo (DOOR 132CIF RE ----------- CH 1i016W-1fE-M-10-9e" + 31k.w ru- 9-6115EUM C TES! 1 3S 1116901 U 1. CODIMMIATES SHIM AM ALASKA ALASKA SATE E w HEM sm 2. OPIK S = 4 HAD 83 AK L M VA DA WED ON A FIRSH PAD ELOWTIDN OF 10W. ISLAND SITE PLAN J. ELE.WrMM LISTED N THE 0 �� TABLE ARE AT THE TOP UNLE55 NVIM WTHEMME ,rs aek>• RIOp - &:dc 1 80 Fact T MU eno US rating . . . . ........ . . . . _ t � _ � QQ '� �. �� ,. .. ,. �� `� + rya Sla� ?'t •�'� _.' '�`.�'�f+'�sa� � �r a. A`:r� - �; F t. Y,� z .. �, ., a __._ -- .> �.= .,. � _ a..- _ F _rew� - . —_�- ., �... �— ..�.. ..w— _ . �- -.:.� a .: "; ..., ,,.r.. � _ _,. .....m, .,.. ��... ,.. � Ili h �� r= • � � � � � � � Exhibit 33: Nikaitchuq Offshore Flowline Bundle Cross - Section NIKAITCHUQ Key: -� 3 -Phase Produced Fluids 2JEATINGDELLIN STCroIJT --R PIPS ARCT`C HEATING °UEL LINE STEEL C"JTER PEE Water Injection MUN'CA SPACER COM NIUN*CAON It osro• w- Diesel CABLE 12 OF 2) SPARE LINE -� BUNDLE STRAP 0 1D O.C. -� Spare 18.01V OD It 0.586' WT STEEL OUTER PIPE WA7E 1 z CTO L WA- ERIN3ECTON LINE Wy H 1.8' POLYURE - NAVE FOAM S.2' POLYETHYLENE. AND " CONCRETE COATING ' :O c' OO WT PRODUCED FLUIDS LINE POWER AND FIBER OPTIC l I COMMUNICATION CABLE :1 OF 2) ii y it BUNDLE OR LOOSE IN SEPARA- EC -RENCH 1t i P- I -0 SPACER 2L O.C. BOTTOM OF TRENCt' NOTE: SLOT T-iROUG9 SPACER FOR 1. CORROSION PROTECTION COATINGS AND RAOIA7M BARRIER &%PACER ATTACHMENT STRAP BETWEEN 13 UWAND ANODES NOT SHOLYN FOR CLARRY. BUNDLE SPACER ENI NIKAITCHUQ FLOWLINE BUNDLE PRELIMINARY CONFIGURATION SCALE 3 IM L Ci. ememeaairra 9 ens us operrafing eni 39 Exhibit 34: Nikaitchuq operations Center (NOC) NIKAITCHUQ EOD.OP ITOPK6RAVEt PAU) E1118TOM�Et PAD lEABE BOVNMM' TRI�IST AtWUW= 38V31 FUIURE COMt 500. TOWEP6BL00 �� FUTU 00 0. Q€ 9UMI110 t 640W FUTUgE FUBTNMIE A �, aPAP«fxu STA umws�EF M BPACEBd TION .. Bldl RM. TNEATEO q TREATMENT 4 CONTAINENE .. 5PANNM0 —E. wOMEMTON FUTUNE OPEN AVM - DIH`Jla SM7 FunMEwENM _ 9LS 38y NfU sec"Oh'ME _ M 3p� STORUiE auinw sTdiraENE.A LL$ I I .__ A VM Tm �EOTbNtdlE §§ BECnuN�pE Nf' , �w SITE PLAN �- ernno us ®cr�a in y � �- .!k TV 0u®R) 5ougeja Jo sn oua _r . r . an H:)llt/)IIN (DON) a a4ua:) suopejado bnuD4i2 >iiN :Se 4pgx�] Exhibit 36 Well Testing Strategy NIKAITCHUQ Test Producing Wells at least once per month. Submit monthly Well Test report to AOGCC Well testing - Schlumberger VX, Multi -Phase Flow Meter. Oil Custody Transfer - LACT eno us operating Exhibits Table of Contents NIKAITCHUQ Exhibit 1: Nikaitchuq Project Summary Exhibit 21: Deterministic Approach Recovery of Exhibit 2: Schedule to First Oil Oil and Oil Rate Profile Exhibit 3: Sealift of Processing Modules Exhibit 22: N Sand Structure Map with Possible Exhibit 4: Nikaitchuq Field Pool Rules Hearing Oil Water Contacts Exhibit 5: Nikaitchua Unit Vicinity Map Exhibit 23: N Sand Future Potential Exhibit 6: Development Scenario Schematic Exhibit 24: OA and N Sand Mapped and Exhibit 7: Historic Lease and Ownership Map Prospective Sand Outlines (prior to January 1, 2007) T Exhibit 25: Well Drilling Field Spider Diagram Exhibit 8: Nikaitchuq Unit Ownership Map Exhibit 26: Example Well Bore Schematic Exhibit 9: Base Map as of July 2010 Exhibit 27: Well Drilling & Completion Criteria Exhibit 10: Well Drilling Field Spider Diagram Exhibit 28: Development Plan Map Exhibit 11: OPP 2010 Drilling Progress Map Exhibit 29: Nikaitchuq Onshore Exhibit 12: Proposed Pool Area Drillsite /Processing Facility Overview Exhibit 1.3: Type Log with Proposed Pool Exhibit 30: Oliktok Point Pad (OPP) Correlative Interval Exhibit 31: Spy Island Drill Site (SID) Exhibit 14: Strategraphic Column Exhibit 32: Spy Island Drill Site (SID) Exhibit 15: Seismic Survey Outlines shown with Exhibit 33: Nikaitchuq Offshore Flowline Bundle Well Pattern and Fault Map Cross - Section Exhibit 16: Seismic Based Structure - Top of OA Exhibit 34: Nikaitchuq Operations Center (NOCC) Sand Exhibit 35: Nikaitchuq Operations Center (NOCC) Exhibit 1.7: Sedimentological Environment - Exhibit 36: Well Testing Strategy • Concept & Core Description Exhibit 18: Map of Well Data Set & Petrophysics Exhibit 19: OA Net Thickness Base Case Exhibit 20: Nikaitchuq OA Sand Waterflood Project #- eni us operating I IC I Nikaitchuq Field Pool Rules Hearing Proposed Nikaichuq Schrader Bluff oil Pool Rules Dave Cook - Reservoir Project Manager e nni us operating on/ = M M M M M III = M M M M = M M M PROPOSED NIKAITCHUQ SCHRADER BLUFF POOL RULES CONTINUED NIKAITCHUQ Rule 1: Field and Pool Name The field is the Nikaitchuq Field and the pool is the Nikaitchuq Schrader Bluff Pool. The Nikaitchuq Schrader Bluff Oil Pool is classified as an Oil Pool. Rule 2: Pool Definition The Nikaitchuq Schrader Bluff Oil Pool is defined as the accumulation of hydrocarbons common to and correlating with the interval between log measured depths 3,530 feet MD and 3,867 feet MD in the Kigun No.1 well ( -3,398 and -3,735 feet TVDSS, respectively), within the area described below. Lease Lease Serial Unit Pool Description Serial Unit Pool Description No. No. ADL 390433 T. 15 N., R. 9 E., UMIAT MERIDIAN ADL 390616 T14N., R.9 E., UMIAT MERIDIAN ADL 389720 T. 15 N., R. 9 E., UMIAT MERIDIAN ADL 388571 T14N., R.8 E., UMIAT MERIDIAN ADL 389719 T. 15 N., R. 9 E., UMIAT MERIDIAN T15N., R.8 E., UMIAT MERIDIAN ADL 388581 T14N., R.9 E., UMIAT MERIDIAN ADL 388572 T14N., R.8 E., UMIAT MERIDIAN ADL 388580 T14N., R.9 E., UMIAT MERIDIAN ADL 388573 T14N., R.8 E., UMIAT MERIDIAN ADL 388579 T14N., R.9 E., UMIAT MERIDIAN T15N., R.8 E., UMIAT MERIDIAN ADL 388583 T14N., R.9 E., UMIAT MERIDIAN ADL 388574 T14N., R.8 E., UMIAT MERIDIAN T14N., R.9 E., UMIAT MERIDIAN ADL 388575 T14N., R.8 E., UMIAT MERIDIAN ADL 388582 T14N., R.9 E., UMIAT MERIDIAN ADL 388577 T14N., R.8 E., UMIAT MERIDIAN T14N., R.9 E., UMIAT MERIDIAN TRACTA ADL 388578 T14N., R.8 E., UMIAT MERIDIAN ADL 390615 T14N., R.9 E., UMIAT MERIDIAN ADL 391283 T14N., R.8 E., UMIAT MERIDIAN Segment 2 T14N., R.9 E., UMIAT MERIDIAN Segment 2 e nni us operating PROPOSED NIKAITCHUQ SCHRADER BLUFF POOL RULES CONTINUED NIKAITCHUQ Rule 3: Well Spacing The requirements of 20 AAC 25.055 are waived for development wells in the Nikaitchuq Schrader Bluff Oil Pool. Without prior notification, development wells, either injection wells or production wells, may not be completed closer than 500 feet to an external' boundary where working interest ownership changes. Rule 4: Drilling and Completion Practices (a) Injection Well Completion: To facilitate wireline access, packers may be located more than 200' 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' above the injection zone, the production casing cement volume shall be sufficient to ensure cement placement is a minimum of 300' measured depth above the planned packer depth. (b) A complete petrophysical log suite acceptable to the AOGCC is required from below • the conductor to TD for at least one well per drill site in lieu of the requirements of 20 AAC 25.071(a). -� ernni us operating ,'- PROPOSED NIKAITCHUQ SCHRADER BLUFF POOL RULES CONTINUED NIKAITCHUQ Rule 5: Automatic Shut -in Equipment (a) All wells must be equipped with a fail -safe automatic surface safety valve system capable of preventing an uncontrolled flow. (b) All injection wells must be equipped with landing nipple at a depth below permafrost, which is suitable for the future installation of a down hole flow control device. The Commission may require such installation by administrative action. (c) Operation and performance tests must be conducted at intervals and times as prescribed by the Commission to confirm that the safety valve systems are in proper working condition. i Rule 6: Reservoir Pressure Monitoring (a) Prior to regular production or injection an initial pressure survey shall be taken on each well except those equipped with a subsurface pump. (b) A minimum of one pressure survey will be taken annually in each reservoir compartment. (c) The reservoir pressure datum will be - 3,760' feet true vertical depth subsea. (d) Pressure surveys may consist of stabilized static pressure measurements (bottom - hole or extrapolated from surface), pressure fall -off tests, pressure build -up tests, multirate tests, drill stem tests, and open -hole formation tests. (e) Data and results from pressure surveys shall be submitted with the annual reservoir surveillance report. All data necessary for analysis of each survey need not be submitted with the report but must be available to the Commission upon request. -- eni us operating Mme PROPOSED NIKAITCHUQ SCHRADER BLUFF POOL RULES CONTINUED NIKAITCHUQ Rule 7: Well Testing (a) All producing wells must be tested at least once per month. (d) The operator shall submit a monthly report (in printed and electronic form) including well tests and daily allocated production and allocation factors for the Pool. (c) Schlumberger VX multi -phase meters will be used to measure produced oil, gas and water volumes during periodic well testing operations and will be used. Rule 8: Gas -Oil Ratio Exemption Wells producing from the Nikaitchuq Schrader Bluff Pool are exempt from the gas -oil ratio limits of 20 AAC 25.240(a) so long as requirements of 20 AAC 25.240 (b) (1) or (2) are met. Rule 9: Pressure Maintenance Project Waterflood is required for purposes of pressure maintenance and enhanced oil recovery in the Nikaitchuq Schrader Bluff Oil Pool. Production and injection must ensure the average reservoir pressure in each sand lobe or reservoir compartment is maintained at or above the bubble point for that respective sand lobe or reservoir compartment. The pressure maintenance waterflood will be initiated within 1 year of the start of regular production from each drill site. �- eni rating rr r err rr rt rr �r �r r err �r rr rt rr rr rr rr rr rr PROPOSED NIKAITCHUQ SCHRADER BLUFF POOL RULES CONTINUED NIKAITCHUQ Rule 10: Reservoir Surveillance An annual report must be filed on or before April 1st of each year. The report must include future development plans, reservoir depletion plans, and surveillance information for the prior calendar year, including: (a) Progress of enhanced recovery project implementation and reservoir management summary including results of reservoir studies: (b) Voidage balance by month of produced fluids and injected fluids and cumulative status. (c) Reservoir pressure map at datum, summary and analysis of reservoir pressure surveys within the pool. (d) Results and, where appropriate, analysis of production and injection log surveys, tracer surveys, observation well surveys, and any other special monitoring. By June 1 of each year, the Operator shall schedule and conduct a technical review meeting with the Commission to discuss the report contents and to review items that may require action within the coming year by the Commission. Rule 11: Administrative Action Upon proper application, 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 on sound engineering and geosciences principles, and will not result in an increased risk of fluid movement into fresh water. -- cni us operating 43 Colombie, Jody J (DOA) From: Ed Marker [Ed.Marker @ihs.com] Sent: Wednesday, September 15, 2010 1:29 PM To: Colombie, Jody J (DOA) Subject: ENI Schrader Bluff pool rules request Hi again Jody, Pursuant to our conversation of just moments ago, I would like to request a copy of the non - proprietary sections of ENI US Operating's application for pool rules for the Nikaitchuk Schrader Bluff Oil Pool. If there are any related documents regarding proposed well locations, spacing, etc, those would be of great interest as well. Thanks very much for your time and help. Sincerely, Ed Marker Geologist IHS Incorporated (907) 335 -1968 ed.marker(5ihs.com Confidentiality Notice: The information in this e-mail may be confidential and / or privileged. This e -mail is intended to be reviewed by only the individual or organization named in the e-mail address. If you are not the intended recipient, you are hereby notified that any review, dissemination or copying of this e-mail and attachments, if any, or the information contained herein, is strictly prohibited. Colombie, Jody J (DOA) From: Goltz, Jon K (LDZX) [Jon.Goltz @conocophillips.com] Sent: Friday, August 27, 2010 1:00 PM To: Colombie, Jody J (DOA) Subject: RE: C0634 Nikaitchuq Unit OP12 -01 Spacing Exception �66 Jody - af As discussed, please send the materials on the pending Eni spacing exception. V ,e Thanks. Jon From: Colombie, Jody J (DOA) [mailto:jody.colombie @alaska.gov] Sent: Thursday, August 26, 2010 2:55 PM To: foms2 @mtaonline.net; Nelson, Michael J; Hutchins, Von L; Alan Dennis; alaska @petrocalc.com; Anna Raff; Fullmer, Barbara F (LDZX); bbritch; Becky Bohrer; Bill Penrose; Bill Walker; Roberts, Bowen E; Brad McKim; Brady, Jerry L; Brandon Gagnon; Brandow, Cande (ASRC Energy Services); Brian Gillespie; Brian Havelock; Bruce Webb; carol smyth; caunderwood; Charles O'Donnell; Chris Gay; Cliff Posey; Crandall, Krissell; dapa; Daryl J. Kleppin; David Boelens; David House; David Steingreaber; ddonkel @cfl.rr.com; Deborah J. Jones; Delbridge, Rena E (LAA); Dennis Steffy; doug_schultze; Elowe, Kristin; Evan Harness; eyancy; Francis S. Sommer; Fred Steece; Garland Robinson; Gary Laughlin; Gary Rogers; Gary Schultz; ghammons; Gordon Pospisil; Gorney, David L.; Gregg Nady; gspfoff; Harry Engel; jarlington @gmail.com; Jeff Jones; jeff.jones @alaska.gov; Jerry McCutcheon; Jim White; Jim Winegarner; Joe Nicks; John Garing; john.katz @alaska.gov; John S. Haworth; John Spain; John Tower; Goltz, Jon K (LDZX); Judy Stanek; Julie Houle; Kari Moriarty; Kaynell Zeman; Keith Wiles; Kim Cunningham; Larry Ostrovsky; Laura Silliphant; Marilyn Crockett; Mark Dalton; mark.hanley @anadarko.com; Mark Kovac; Worcester, Mark P (LDZX); Marquerite kremer; Michael Dammeyer; Jacobs, Michael; Mike Bill; Mike Mason; Mikel Schultz; Mindy Lewis; NSK Well Integrity Proj; mjnelson; mkm7200; nelson; Nick W. Glover; NSK Problem Well Supv; Patty Alfaro; paul.decker @alaska.gov; PORHOLA, STAN T; Rader, Matthew W (DNR); Kanady, Randall B; Randy L. Skillern; rob.g.dragnich @exxonmobil.com; raprovince @marathonoil.com; Robert Brelsford; Robert Campbell; Roberts, Susan M.; Rudy Brueggeman; Scott Cranswick; Scott, David (LAA); Donnelly, Shannon; 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; trmjri; Vicki Irwin; Walter Featherly; Will Chinn; Williamson, Mary J (DNR); Winslow, Paul M; Yereth Rosen; Aaron Gluzman; Bettis, Patricia K (DNR); Dale Hoffman; David Spann; Frederic Grenier; Gary Orr; Jason Bergerson; Eggemeyer, Jerome C.; Joe Longo; Marc Kuck; Aschoff, Mary Mae; Maurizio Grandi; Ostrovsky, Larry Z (DNR); Richard Garrard; Lemke, Sandra D; Scott Nash; Talib Syed; Tiffany Stebbins; Wayne Wooster; Willem Vollenbrock; William Van Dyke; Woolf, Wendy C (DNR); Aubert, Winton G (DOA); Ballantine, Tab A (LAW); Brooks, Phoebe; Davies, Stephen F (DOA); Fisher, Samantha J (DOA); Foerster, Catherine P (DOA); Johnson, Elaine M (DOA); Laasch, Linda K (DOA); Maunder, Thomas E (DOA); McIver, Bren (DOA); McMains, Stephen E (DOA); Norman, John K (DOA); Okland, Howard D (DOA); Paladijczuk, Trade L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Saltmarsh, Arthur C (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Shartzer, Christine R (DOA) Subject: C0634 Nikaitchuq Unit OP12 -01 Spacing Exception Jody J. Colombie Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 (907)793 -1221 (phone) (907)276 -7542 (fax) 1 2 STATE OF ALASKA 0 NOTICE TO PUBLISHER • ADVERTISING ORDER NO. ADVERTISING INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED A O _02114015 AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF A ORDER ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE sI=E BOrroM Fg li fi t : 'irlH ESS F AOGCC AGENCY CONTACT DATE OF A.O. August 26, 2010 R 333 W 7th Ave, Ste 100 Jody Colombie ° Anchorage, AK 99501 PHONE PCN M (907) 793 —1221 DATES ADVERTISEMENT REQUIRED: T Anchorage Daily News August 27, 2010 PO Box 149001 An c h orage , AK 99514 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN g ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Type of Advertisement Legal® ❑ Display Classified ❑Other (Specify) SEE ATTACHED SEND N\/ ,IGE 1N T LI'" Vii. AOGCC, 333 W. 7th Ave., Suite 100 PAGE 1 OF TOTAL OF 'il =IH'��I,`iaz +u I' „h Anchors e AK 99501 2 PAGES ALL PAGES$ REF TYPE NUMBER AMOUNT DATE COMMENTS 1 VEN 2 ARD 02910 FIN AMOUNT SY CC PGM LC ACCT FY NMR DIST LIQ 1 10 02140100 73451 2 REQUISITIONE Y: DIVISION APPROVAL: 02 - 902 (Rev. 3/ 4) Publisher /Original Copies: Department Fiscal, Department, Receiving AOTRM Re- Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re. Docket No. CO- 10 -14. Eni US Operating Company (Eni) has applied for Pool Rules for the ro osed Nikaitchu Schrader Bluff Oil Pool Nikaitchu Unit Beaufort p p q , q Sea, Alaska in conformance with 20 AAC 25.520. The non - confidential portions of Eni's application may be reviewed at the offices of the Commission, 333 West 7th Avenue, Suite 100, Anchorage, Alaska, or a copy of the non - confidential portions may be obtained by phoning the Commission at (907) 793 -1221. The Commission has tentatively scheduled a public hearing on this application for September 29, 2010 at 9:00 a.m. at the Alaska Oil and Gas Conservation Commission, at 333 West 7 th Avenue, Suite 100, Anchorage, Alaska 99501. To request that the tentatively scheduled hearing be held, a written request must be filed with the Commission no later than 4:30 p.m. on September 13, 2010. 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 hearing, call 793- 1221 after September 15, 2010. In addition, written comments regarding this application may be submitted to the Alaska Oil and Gas Conservation Commission, at 333 West 7 th Avenue, Suite 100, Anchorage, Alaska 99501. Comments must be received no later than 4:30 p.m. on September 28, 2010, except that, if a hearing is held, comments must be received no later than the conclusion of the September 29, 2010 hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact the Commission's Special Assistant, Jody Colombie, at 793 -1221, no later than September 16, 2010. Daniel T. S ount, Jr. Chair, Commissioner RFO FNED . �x,lissiQn Anchorage Daily News wla, cf Affidavit of Publication 1001 Northway Drive, Anchorage, AK 99508 �D DATE Pte( ACCOUNT P � O THER HER OTHER GRAND DAY CHARGES CHARGES #2 CHARGES #3 TOTAL 810876 08/27/2010 AO -02114 STOF0330 $172.64 $172.64 $0.00 $0.00 $0.00 $172.64 RC Ilfotic@ of 0(tI lc Heawlg STATE OF ALASKA Alaska oil and Gas Conservation Commission Re: Docket No. Co- 10 -14. Eni US operating STATE OF ALASKA Company (Eni) has applied for Pool Rules for the pproposed Nlkaitchuq Schrader Bluff -Oil Pool, THIRD JUDICIAL DISTRICT Nlk.I ,huq Unit,'Beaufort Sea, Alaska in conformance with 20 AAC 25.520. The non - confidential portions of Eni's apptication may be hane Drew, being first duly sworn on oath deposes and says hat reviewed at the offices of the Commission, 333 west Y 7th Avenue, Suite 100, Anchorage, Alaska, or a cop he is an advertising representative of the Anchorage Daily News, of the non confidential portions m obtained b a daily newspaper. phoning the commission at (907) 793.1221. has been ap b the Third j udicial The Commission has tentativel scheduled a public That said newspaper PP Y J hearing on this application for September 29, 2010 Court, Anchorage, Alaska, and it now and has been published in at 9:00 a.ft gt the Alaska oil and G89 Conservation the English language continually as a daily newspaper in Commission, at 333 West 7th Avenue, Suite 100, Anchors e, Alaska 99501. To request that the Anchorage, Alaska, and it is now and during all said time was tentatively scheduled hearin be held, a written request must be filed with the ommission no later printed in an office maintained at the aforesaid place of than 4 :30 P.M. on Sep tember 13, 2010, publication of said newspaper. That the annexed is a copy of an if request for a hearing is not timely filed, the advertisement as it was published in regular issues (and not in Commission may consider the issuance of an order without a hearing. To learn if the Commission will supplemental form) of said newspaper on the above dates and hold the Hearing, call 793 -1221 after September 15, that such newspaper was regularly distributed to its subscribers 2010. during all of said period. That the full amount of the fee charged In addition, written comments re this ed application may be submitted to the Alaska ©il and for the foregoing publication is not in excess of the rate charged Gas Conservation Commission, at 333 West 7th private individuals. Avenue, Suite 100, Anchorage, Alaska 99501. Comments must be received no later than 4 :30 p.m. on September 28, 2010, except that, if a hearing is held, comments must be received no later than the conclusion of the September 29, 2010 hearing. Signed r If, because of a disability, special accommodations may be needed to comment or attend the hearin , contact the Commission's Special Assistant, Jot y Colombia, at 793 -1221, no later than September 16, Subscribed and sworn to me before this date: 2010. urit, Jr. SEP 0 2014 D W W X Seamo ssi uublig 27,2010 Notary Public in and for the State of Alaska. Third Division. Anchorage, Alaska MY COMMISSION EXPIRES: APR 2 `` kt J, 1. � r ice,. 0 • STATE OF ALASKA NOTICE TO PUBLISHER ADVERTISING ORDER NO. ADVERTISING INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED /� AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF A 0_02114015 ORDER ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE SEE BOTTOM',FQI INUQIE ApDR6 „ 6�I, F AOGCC AGENCY CONTACT DATE OF A.O. R 333 West 7 Avenue. Suite 100 ° Anchorage_ AK 99501 PHONE PCN M (907) 793 -1221 DATES ADVERTISEMENT REQUIRED: T Anchorage Daily News August 27, 2010 PO Box 149001 Anchorage 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 PUBLICATION United states of America 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 2010, and thereafter for consecutive days, the last publication appearing on the day of . 2010, 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 2010, Notary public for state of My commission expires Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Thursday, August 26, 2010 4:08 PM To: 'Aaron Gluzman'; Bettis, Patricia K (DNR); caunderwood @marathonoil.com; 'Dale Hoffman'; 'David Spann'; Frederic Grenier; 'Gary Orr'; 'Jason Bergerson'; Jerome Eggemeyer; 'Joe Longo% Marc Kuck; 'Mary Aschoff; Maurizio Grandi; Ostrovsky, Larry Z (DNR); Richard Garrard; 'Sandra Lemke'; 'Scott Nash'; Talib Syed; 'Tiffany Stebbins'; 'Wayne Wooster'; 'Willem Vollenbrock'; 'William Van Dyke'; Woolf, Wendy C (DNR); (foms2 @mtaonline.net); ( michael .j.nelson @conocophillips.com); (Von. L. Hutchins@conocophillips.com); 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 Gillespie; Brian Havelock; Bruce Webb; carol smyth; Charles O'Donnell; Chris Gay; Cliff Posey; Crandall, Krissell; dapa; Daryl J. Kleppin; David Boelens; David House; 'David Spann'; David Steingreaber; 'ddonkel @cfl.rr.com'; Deborah J. Jones; Delbridge, Rena E (LAA); 'Dennis Steffy'; doug_schultze; Elowe, Kristin; Evan Harness; eyancy; Francis S. Sommer; Fred Steece; Garland Robinson; Gary Laughlin; Gary Rogers; Gary Schultz; ghammons; Gordon Pospisil; Gorney, David L.; Gregg Nady; gspfoff; Harry Engel; Jdarlington Qarlington @gmail.com); Jeff Jones; Jeffery B. Jones Qeff.jones @alaska.gov); Jerry McCutcheon; Jim White; Jim Winegarner; Joe Nicks; John Garing; John Katz Qohn.katz @alaska.gov); John S. Haworth; John Spain; John Tower; Jon Goltz; Judy Stanek; Julie Houle; Kari Moriarty; Kaynell Zeman; Keith Wiles; 'Kim Cunningham'; Larry Ostrovsky; Laura Silliphant; Marilyn Crockett; Mark Dalton; Mark Hanley (mark.hanley @anadarko.com); Mark Kovac; Mark P. Worcester; Marquerite kremer; 'Michael Dammeyer'; Michael Jacobs; Mike Bill; Mike Mason; Mikel Schultz; Mindy Lewis; MJ Loveland; mjnelson; mkm7200; nelson; Nick W. Glover; NSK Problem Well Supv; Patty Alfaro; Paul Decker (paul.decker @alaska.gov); PORHOLA, STAN T; Rader, Matthew W (DNR); Randall Kanady; Randy L. Skillern; rob.g.dragnich @exxonmobil.com; Robert A. Province (raprovince @marathonoil.com); 'Robert Brelsford'; Robert Campbell; Roberts, Susan M.; Rudy Brueggeman; Scott Cranswick; 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 O (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); Winslow, Paul M; Yereth Rosen; Aubert, Winton G (DOA); Ballantine, Tab A (LAW); Brooks, Phoebe; Davies, Stephen F (DOA); Fisher, Samantha J (DOA); Foerster, Catherine P (DOA); Johnson, Elaine M (DOA); Laasch, Linda K (DOA); Maunder, Thomas E (DOA); McIver, Bren (DOA); McMains, Stephen E (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); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Shartzer, Christine R (DOA) Subject: Public Notice ENI Pool Rules Nikaitchuq Attachments: Re- Notice Pool Rules Nikaitchuq.pdf The date of the hearing has been changed. Jody J. Colombie Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 (907)793 -1221 (phone) (907)276 -7542 (fax) 1 STATE OF ALASKA 0 NOTICE TO PUBLISHER 0 ADVERTISING ORDER NO. ADVERTISING INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED A O _02114015 AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF M ORDER ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE s iili!' E� ,; 11 o r MF�R`1 1 G'I S 114 iir Ii ;7c G$u, I ,i ii M' F AOGCC AGENCY CONTACT DATE OF A.O. August 26, 2010 R 333 W 7th Ave, Ste 100 Jody Colombie ° Anchorage, AK 99501 PHONE PCN M DATES ADVERTISEMENT REQUIRED: T Alaska Journal of Commerce ASAP 301 Arctic Slope Avenue, Suite 350 Anchorage AK 99518 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Type of Advertisement SEE ATTACHED SEND WVOIFI; � AOGCC, 333 W. 7th Ave., Suite 100 PAGE 1 OF TOTAL OF �;jt y it j Anchorage, AK 99501 2"( ALL PAGE S$ REF TYPE NUMBER AMOUNT DATE COMMENTS 1 VEN 2 ARDI 02910 FIN AMOUNT SY CC PGM LC ACCT FY NMR DIST I LIQ 1 10 02140100 73451 2 REQUISITIONED BY: DIVISION APPROVAL: 02 -902 (Rev. 3/94) Publisher /Original Copies: Department Fiscal, Department, Receiving AOTRM Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Monday, August 30, 2010 8:27 AM To: 'Belinda Cummings' Subject: RE: Public Notice Belinda I called and cancel this ad order. Please delete and confirm. Jody From: Belinda Cummings [mailto:belinda.cummings @anchoragemediagroup.com] Sent: Monday, August 30, 2010 8:20 AM To: Colombie, Jody J (DOA) Subject: Re: Public Notice Good morning Jody, Here is confirmation for Nikaitchuq Pool. Pub: 9/5/2010. Ad #10140227 & cost will be $105.60 Thank you! Belinda On 8/26/10 1:13 PM, "Colombie, Jody J (DOA)" < jody.colombie(a)alaska.gov > wrote: Please publish once. Jody J. Colombie Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 (907)793 -1221 (phone) (907)276 -7542 (fax) 1 a � Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Docket No. CO- 10 -14. Eni US Operating Company (Eni) has plied for Pool Rules for the proposed Nikaitchuq Schrader Bluff Oil Pool, Nikaitc q Unit, Beaufort Sea, Alaska in conformance with 20 AAC 25.520. The non - confide ial portions of Eni's application may be reviewed at the offices of the Commission, 33 West 7th Avenue, Suite 100, Anchorage, Alaska, or a copy of the non - confidenti portions maybe obtained by phoning the Commission at (907) 793 -1221. The Commission has tentatively scheduled ubli earing on this application for October 21, 2010 at 9:00 a.m. at the Ala a it Gas Conservation Commission, at 333 West 7 Avenue, Suite 100, n Alaska 99501. To request that the tentatively scheduled hearing be e a itten request must be filed with the Commission no later than 4:30 p.m. p ber 27, 2010. If a request for a hearing is n ti e ed, the Commission may consider the issuance of an order without a hear T 1 if the Commission will hold the hearing, call 793- 1221 after October 1, 2010. In addition, written commen regarding this application may be submitted to the Alaska Oil and Gas Conservatio ommission, at 333 West 7 Avenue, Suite 100, Anchorage, Alaska 99501. Comm is must be received no later than 4:30 p.m. on October 15, 2010, except that, if a he ' g is held, comments must be received no later than the conclusion of the October 21 010 hearing. If, because a disability, special accommodations may be needed to comment or attend the heari , contact the Commission's Special Assistant, Jody Colombie, at 793 -1221, no later th October 19, 2010. r Daniel T. Seamount, Jr. Chair, Commissioner • 0 STATE OF ALASKA NOTICE TO PUBLISHER ADVERTISING ORDER NO. ADVERTISING INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED /� 0_02114015 AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF A ORDER ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE SEE BOTTOM FOR INV E' QQI1 =$ k ti' F AOGCC AGENCY CONTACT DATE OF A.O. R th 333 West 7 Avenue. Suite 100 Jody Colombie August26- 2010 o Anchorage_ AK 99501 PHONE PCN M (907) 793 -1221 DATES ADVERTISEMENT REQUIRED: T 0 Alaska Journal of Commerce ASAP 301 Arctic Slope Avenue, Suite 350 Anchorage AK 99518 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: AFFIDAVIT OF PUBLICATION United states of America 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 2010, and thereafter for consecutive days, the last publication appearing on the day of . 2010, 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 2010, Notary public for state of My commission expires Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Thursday, August 26, 2010 1:20 PM To: Aaron Gluzman; Bettis, Patricia K (DNR); caunderwood @marathonoil.com; Dale Hoffman; David Spann; Fr6deric Grenier; Gary Orr; Jason Bergerson; Jerome Eggemeyer; Joe Longo; Marc Kuck; Mary Aschoff; Maurizio Grandi; Ostrovsky, Larry Z (DNR); Richard Garrard; Sandra Lemke; Scott Nash; Talib Syed; Tiffany Stebbins; Wayne Wooster; Willem Vollenbrock; William Van Dyke; Woolf, Wendy C (DNR); (foms2 @mtaonline.net); (michael.j.nelson @conocophillips.com); (Von. L. Hutchins@conocophillips.com); 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 Gillespie; Brian Havelock; Bruce Webb; carol smyth; Charles O'Donnell; Chris Gay; Cliff Posey; Crandall, Krissell; dapa; Daryl J. Kleppin; David Boelens; David House; David Spann; David Steingreaber; ddonkel @cfl.rr.com; Deborah J. Jones; Delbridge, Rena E (LAA); Dennis Steffy; doug_schultze; Elowe, Kristin; Evan Harness; eyancy; Francis S. Sommer; Fred Steece; Garland Robinson; Gary Laughlin; Gary Rogers; Gary Schultz; ghammons; Gordon Pospisil; Gorney, David L.; Gregg Nady; gspfoff; Harry Engel; Jdarlington Qarlington @gmail.com); Jeff Jones; Jeffery B. Jones QeffJones @alaska.gov); Jerry McCutcheon; Jim White; Jim Winegarner; Joe Nicks; John Garing; John Katz Qohn.katz @alaska.gov); John S. Haworth; John Spain; John Tower; Jon Goltz; Judy Stanek; Julie Houle; Kari Moriarty; Kaynell Zeman; Keith Wiles; Kim Cunningham; Larry Ostrovsky; Laura Silliphant; Marilyn Crockett; Mark Dalton; Mark Hanley (mark.hanley @anadarko.com); Mark Kovac; Mark P. Worcester; Marquerite kremer; Michael Dammeyer; Michael Jacobs; Mike Bill; Mike Mason; Mikel Schultz; Mindy Lewis; MJ Loveland; mjnelson; mkm7200; nelson; Nick W. Glover; NSK Problem Well Supv; Patty Alfaro; Paul Decker (paul.decker @alaska.gov); PORHOLA, STAN T; Rader, Matthew W (DNR); Randall Kanady; Randy L. Skillern; rob.g.dragnich @exxonmobil.com; Robert A. Province (raprovince @marathonoil.com); Robert Brelsford; Robert Campbell; Roberts, Susan M.; Rudy Brueggeman; Scott Cranswick; 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 O (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); Winslow, Paul M; Yereth Rosen; Aubert, Winton G (DOA); Ballantine, Tab A (LAW); Brooks, Phoebe; Davies, Stephen F (DOA); Fisher, Samantha J (DOA); Foerster, Catherine P (DOA); Johnson, Elaine M (DOA); Laasch, Linda K (DOA); Maunder, Thomas E (DOA); McIver, Bren (DOA); McMains, Stephen E (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); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Shartzer, Christine R (DOA) Subject: Public Notice Pool Rules Nikaitchiq Unit (ENI) Attachments: Public Notice Pool Rules Nikaitchuq.pdf Jody J. Colombie Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 (907)793 -1221 (phone) (907)276 -7542 (fax) 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 40818 th Street President 6900 Arctic Blvd. Golden, CO 80401 -2433 P.O. Box 1655 Anchorage, AK 99502 Colorado Springs, CO 80901 Schlumberger CIRI Drilling and Measurements Land Department Baker Oil ho o fs 2525 Gambell St, #400 P.O. Box 93330 795 E. 94 Ct. Anchorage, AK 99515 -4295 Anchorage, AK 99503 Anchorage, AK 99503 Jill Schneider Ivan Gillian US Geological Survey Gordon Severson 9649 Musket Bell Cr. #5 3201 Westmar Circle Anchorage, AK 99507 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 Bernie Karl North Slope Borough P.O. Box 60868 K &K Recycling Inc. P.O. Box 69 Fairbanks, AK 99706 P.O. Box 58055 Barrow, AK 99723 Fairbanks, AK 99711 1"` �1 6. eni us operating eni us operating co. inc. 3800 Centerpoint Dr., Suite 300 Anchorage, AK 99503 - U.S.A. Tel. 907- 865 -3300 Fax 907 - 865 -3380 ent RFO ID �'UG 1 8 2.010 August 18, 2010 Atoka C"046 Mr. Stephen Davies Alaska Oil & Gas Conservation Commission 333 West 7 Avenue, Suite 100 Anchorage, AK 99501 Re: Nikaitchuq Pool Rules Application Nikaitchuq Unit, North Slope Alaska Dear Mr. Davies: Eni US Operating Co. ( "eni ") hereby submits its Pool Rules Application for the Nikaitchuq Unit Development project. Eni requests that the hearing date for said Pool Rules Application be scheduled at the first opportunity immediately after the 30 -day notice period as concluded. At your earliest convenience, please provide eni with the date of when the public hearing can be held for eni's testimony regarding our Pool Rules Application. Your consideration of this request is greatly appreciated. Sincerely, Robert A. Province Land Manager - Alaska Encl: Pool Rules Application i at petrokum Nikaitchuq Development Pool Rules Application 9 i Table of Contents 1 ACRONYMS AND DEFINITIONS ....................................................................................... ..............................4 2 DOCUMENT SCOPE .................................................................................................................. ..............................4 3 INTRODUCTION ...................................................................................................................... ............................... 5 3 .1 GEOGRAPHICAL AREA .................................................................. ............................... 5 3 .2 PROJECT BACKGROUND ................................................................ ............................... 5 3.3 EXPLORATION AND APPRAISAL HISTORY ............................................ ............................... 6 3.4 PROJECT SCOPE & OBJECTIVES ....................................................... ............................... 7 3.5 PROJECT OVERVIEW ............................................................... ............................... 7 4 GEOSCIENCE .............................................................................................................................. ..............................9 4.1 FIELD LOCATION AND FIELD DATA ............................................ ............................... 9 4 .1.1 Field Data .................................................................................................................... .............................10 4.2 GEOPHYSICAL ANALYSYS ...................................................... ............................... 10 4.3 GEOLOGY AND GEOLOGICAL MODELING .................................. ............................... 11 4.3.1 Sedimentology ........................................................................................................... .............................11 4.3.2 Petrophysics ............................................................................................................... .............................11 4.3.3 OA Geological Model ................................................................................................ .............................12 4.3.4 N Geological Model ................................................................................................... .............................14 4.3.5 OA and N Mapped and Prospective Limits within the Nikaitchuq Unit . .............................16 4.4 RESERVOIR MODELLING ........................................................ ............................... 16 4.4.1 Dynamic Model Introduction ................................................................................ .............................16 4.5 RESERVES FORECAST AND PRODUCTION PROFILES .................. ............................... 19 4.5.1 Reserves Forecast and Production Profiles ..................................................... .............................19 S DRILLING AND COMPLETION ......................................................................................... .............................20 5 .1 GENERAL PLAN ........................................................................ ............................... 20 5.1.1 Oliktok Point Dril ling .............................................................................................. ............................... 20 5.1.2 Spy Island Drill ing .................................................................................................. ............................... 20 5 .2 WELL PATTERN ........................................................................ ............................... 20 5 .3 WELLS DESIGN ....................................................................... ............................... 21 5.3.1 Casing design ............................................................................................................. .............................21 5 .4 DIRECTIONAL PLANS .................................................................. ............................... 21 5.5 DRILLING SCHEDULE ................................................................. ............................... 21 5 .6 RIG TYPE ............................................................................... ............................... 22 5.6.1 Oliktok Point ............................................................................................................. ............................... 22 5.6.2 Spy Island ................................................................................................................. ............................... 22 5.7 WELL COMPLETION STRATEGY ...................................................... ............................... 22 5.8 COMPLETION REQUIREMENTS ....................................................... ............................... 22 PRODUCTION WELLS CONFIDENTIAL - COMPLETION DETAIL AND SCHEMATIC .... ............................... 22 SEEANNEX 9.4 ................................................................................ ............................... 22 INJECTION WELLS CONFIDENTIAL - COMPLETION DETAIL AND SCHEMATIC ........ ............................... 22 SEEANNEX 9.5 ................................................................................ ............................... 22 5.9 COMPLETION AND RESERVOIR MONITORING STRATEGY ......................... ............................... 23 5.10 FACILITIES CONCEPT ............................................................ ............................... 23 5.11 DESIGN CAPACITY ................................................................ ............................... 23 5.12 TRANSPORTATION TO MARKET ............................................... ............................... 24 5.13 PRODUCTION AND OPERATIONS ............................................. ............................... 24 5.13.1 General ..................................................................................................................... .............................24 5.13.2 Sales Metering and Well Testing .................................................................... .............................24 6 DEVELOPMENT SCHEDULE ................................................................................................ .............................25 Page 2 of 35 8/17/2010 • 0 7 PROPOSED NIKAITCHUQ SCHRADER BLUFF POOL RULES ............................. .............................25 8 ANNEX OF CONFIDENTIAL MATERIAL ....................................................................... .............................30 8.1 TABLE 1 - TABLE OF WELL OA PROPERTIES (THICKNESS, NTG, ❑, SW & K) .............................. 30 8.2 OA GEOLOGICAL MODEL .............................................................. ............................... 30 8.2.1 Description of geophysical interpretation of depositional features and impact on structural interpretation and possible compartmentalization ................................. ............................... 30 8.2.2 Petrophysical model - Discussion of internal petrophysical analysis techniques.......... 31 8.2.3 Permeability - Discussion of internal petrophysical analysis techniques ......................... 31 8.2.4 Water saturation - Discussion of internal petrophysical analysis techniques ................. 31 8.2.5 Description of geophysical interpretation of depositional features and impact on structural interpretation and possible compartmentalization ................................. ............................... 31 8.2.6 Porosity - Discussion of internal petrophysical analysis techniques ... ............................... 32 8.2.7 Table 2 - Volumetric Results: Bulk Volume, Net Volume, Pore Volume, HCPV & OOIP 32 8.3 DYNAMIC MODEL ...................................................................... ............................... 32 8.3.1 Description of Dynamic Reservoir Model (Eclipse) .................................... ............................... 32 8.3.2 Fluid Regions- Description of the dynamic modeling of the potential compartmentalization within the OA sand ..................................................................... ............................... 33 8.3.3 Calibration of Geologic Models- Description of the well tests and the calibration of the reservoir model to the well test results ........................................................................... ............................... 33 8.4 PRODUCTION WELLS - COMPLETION DETAIL AND SCHEMATIC ................. ............................... 33 8.5 INJECTION WELLS- COMPLETION DETAIL AND SCHEMATIC ...................... ............................... 34 Page 3 of 35 8/17/2010 0 0 1 ACRONYMS AND DEFINITIONS x AOGCC Alaska Oil and Gas Conservation Commission CPI Computer Processed Image (Computed Lo Eni Eni Petroleum US LLC Eni US Eni US Operating Co. Inc. ESP Electric Submersible Pum E &P Exploration & Production MD Measured Depth TAPS Trans Alaskan Pipeline System TVD Total Vertical Depth 2 DOCUMENT SCOPE This document is an application for Pool Rules to be submitted to the Alaska Oil and Gas Conservation Commission ( AOGCC). The purpose of this document is to define the proposed Nikaitchuq Schrader Bluff Pool, establish Pool Rules for the development of said oil pool pursuant to 20 AAC 25.520. Eni US Operating Co. Inc. ( "Eni US "), as operator of the Nikaitchuq Unit, submits this document to o the AOGCC on behalf of Eni Petroleum US LLC ("Eni"), the 100% working interest owner. The scope of this application includes a discussion of geological and reservoir properties, as they are currently understood, and Eni's plans for reservoir development and surveillance, well planning, facilities installation and project scheduling for the resource development as they are currently envisioned. This application and supporting testimony will enable the AOGCC to establish rules which will allow economical development of resources, promote greater ultimate recovery and prevent waste within the Nikaitchuq Schrader Bluff Pool. Confidential data and interpretation concerning the Nikaitchuq Schrader Bluff formation may be furnished to the Commission as additional support for this application in accordance with the provisions of AS 31.05.035 and 20 AAC 25.537. The proposed area to be covered by the Nikaitchuq Schrader Bluff Oil Pool Rules is shown in Exhibit 1. The type log for the Nikaitchuq Schrader Bluff Oil Pool is the Kigun No.1 as shown in Exhibit 2. Eni requests that the entire Schrader Bluff formation as shown in the correlative section on the type log from -3398' to -3715' TVD subsea (3530' to 3867' MD) be included in the Pool. The type log shows both the Schrader Bluff OA Sand and the Schrader Bluff N Sand within this interval. The top of the Nikaitchuq Schrader Bluff Pool is defined as the top of the cretaceous shale below the Ugnu and the base is approximately 45' below the base of the Schrader Bluff OA sand. Eni recognizes a need for a consistent development strategy for the Nikaitchuq Schrader Bluff oil accumulation that occurs in this area within the Nikaitchuq Unit Area and Pool rules are necessary to maintain that consistency. Eni plans to form a participating area for the Nikaitchuq Schrader Bluff oil pool within the Nikaitchuq Unit. Eni US as operator plans to apply to the State of Alaska for the formation of a Nikaitchuq Schrader Bluff Participating Area contemporaneously with the submission of this information to the AOGCC. Page 4 of 35 8/17/2010 s 0 Exhibit 1: Proposed Pool Area - shown in Green Dashed Outline Highlighted in Yellow Exhibit 2: Type Log with Proposed Pool Correlative Interval 3 INTRODUCTION 3.1 GEOGRAPHICAL AREA The North Slope of Alaska has been explored and produced for over forty years. It is a world - class oil petroleum system which has already produced over 16 billion barrels of oil. Containing multiple rich source rocks and pay zones, it represents approximately 20% of US reserves. 3.2 PROJECT BACKGROUND The extended Nikaitchuq Unit area is located on the North Slope of Alaska, near the northern terminus of the Trans - Alaska Pipeline System, abbreviated as TAPS. The unit is offshore, 12 miles north -east of the mouth of the Colville River Delta, in water depth less than 20 ft. In August 2005, Eni acquired the Alaskan assets of Armstrong Oil & Gas Alaska Inc., thereby becoming a 30% WI (Working Interest) owner in the offshore Nikaitchuq Unit development project covering seven (7) State of Alaska Oil & Gas Leases located in east Harrison Bay, Colville River Delta, on the North Slope of Alaska. See Exhibit 3. I Exhibit 3: North Slope Location Map Kerr -McGee Oil & Gas Corporation was the Operator of the Nikaitchuq Unit and owned the remaining 70% WI in this unit (beige - colored blocks on the east half of the full unit map below - see Exhibit 4). The Armstrong acquisition also included an 18% WI in the adjacent Kerr -McGee (82% WI) operated Tuvaaq Unit (purple blocks) covering eight (8) State of Alaska Oil & Gas Leases including State of Alaska Lease ADL 355024 (Kigun #1 well) which was acquired by Kerr - McGee (55% WI) and Eni (45% WI) via a Farmout Agreement with the Kuparuk River Unit owners (ConocoPhillips, ExxonMobil, BP & Chevron - green block). Exhibit 4: Historic Lease and Ownership Map (prior to January 1, 2007) Kerr McGee and Eni entered into the Agreement For Nikaitchuq Unit Expansion ( "Expansion Agreement ") dated effective July 1, 2006, wherein the parties agreed to cross assign interests in all of the leases reflected on the above map so that the interests of the parties would be Eni 30% WI and Kerr -McGee 70 %WI in each of the leases The Expansion Agreement further provided that in order to encompass the Schrader Bluff and Sag River formation reservoirs and include enough reserves in the Nikaitchuq Unit to justify development, the parties would seek approval from the State of Alaska Department of Natural Resources to expand the Nikaitchuq Unit to also include all of State of Alaska Leases ADL 390615 and ADL 390616; and all of the seven leases previously in the Tuvaaq Unit ADL 388571, ADL 388572, ADL 388573, ADL 388574, ADL 388575, ADL 388577 and ADL 388578; and ADL 355024 only insofar as it covers the following lands: T14N, R8E, Umiat Meridian T14N, R9E, Umiat Meridian Sections: 24, 25 and 36 Sections 19, 30 and 31 Effective January 1, 2007 Eni acquired Kerr- McGee's 70% WI in all of the leases reflected on the above map and is now Operator and 100% working interest owner in all of the leases. Eni has been notified of State of Alaska approval of the expansion of the Nikaitchuq Unit to include all the lands described in the preceding paragraph. The main formation target in these offshore leases is called the Schrader Bluff. Page 5 of 35 8/17/2010 0 0 3.3 EXPLORATION AND APPRAISAL HISTORY A total of six wells were drilled in the Nikaitchuq area in the 2004 and 2005 winter drilling seasons. Subsequently two additional appraisal wells were drilled in 2006 -07 winter drilling season. Two development wells were drilled from the Oliktok Point Pad (OPP) drill site in the winter of 2008 -09 and development drilling has restarted as of April 2010 with 3 wells completed in the spring and early summer 2010. Exhibit 5: Base Map as of July 2010 The first well drilled in 2004 was the Nikaitchuq #1. The Schrader Bluff OA sand was penetrated at 4,140' TVDSS with a gross interval of 41' and net pay thickness of 23'. No tests were conducted on the Schrader Bluff. The second well drilled in the 2004 program was the Nikaitchuq #2. The Schrader Bluff OA sand was penetrated in the wellbore at 4,154' TVDSS and has an estimated 7' of net pay and also aids in determining the eastern areal extent of the field along with confirming the oil -water contact of 4,177'. The following are the results of the wells drilled in the 2005 drilling program: Nikaitchuq #3 was drilled as a +/- 3,000' horizontal well in Sag River. The Nikaitchuq #4 was a +/- 3,000' horizontal well drilled to test the Schrader Bluff OA sand. The Schrader Bluff OA was penetrated at 4,097' TVDSS with an estimated 2,270' horizontal net pay. The well was tested over a twelve day period with rates ranging from 600 -1,300 bopd of 16 -17 API crude using an ESP to lift the well. Analysis of the flow periods and build -up periods respectively indicates reservoir permeability in the range of 300 - 400 md. A full core was also recovered over the Schrader Bluff interval. PVT analysis of the crude showed a 16.3 0 API, 125 scf /bbl GOR fluid with an in -situ viscosity of 159 cp at a reservoir temperature of 89 The Tuvaaq exploration well was also drilled to test the continuity of the Schrader Bluff reservoirs. The Schrader Bluff OA was penetrated at 3,598' TVDSS with net pay approaching 30'. In this wellbore an additional Schrader Bluff N zone was encountered at 3,455' TVDSS with 12' net pay thickness. The Kigun exploration well was drilled to further investigate the Schrader Bluff intervals. The Schrader Bluff OA was penetrated at 3,643' TVDSS with a net pay thickness of 29'. The Schrader Bluff N zone was again encountered in this well at 3,492' with a net pay thickness of 30'. Full core was obtained over the Schrader Bluff OA in this well with similar rock properties from those in the Nikaitchuq #4 core. Sampling was attempted using Schlumberger's MDT tools. The wellbore was drilled with synthetic oil based mud which caused contamination of the samples. This raises some question as to the validity of the fluids analyzed. PVT analysis of the crude showed an 18 0 API, 59 scf /bbl GOR fluid with an in -situ viscosity of 82 cp at a reservoir temperature of 89 °F. In December 2006 & January 2007, two appraisal wells were drilled from OPP. The 0I -1 (eastern) well was drilled at 30 degrees as a pilot hole and downhole fluid samples were taken of 16 API crude oil. The 0I -2 (western) well was completed as a 6,000 ft long lateral and well - tested over three days at rates exceeding 2,000 bpd with little water or sand production again using an ESP to lift the well. The gravity of this oil was measured to be 19 API and further PVT fluid analysis show different composition with lower saturation pressure and lower oil viscosity compared to the 0I1 and NIK 4 wells. These results lead to define a new base case scenario where a sealing fault (partially seen from available 3D seismic) has been introduced to split the field in two blocks. Both of the 0I1 and OI 2 wells are planned to be used as development wells. Page 6 of 35 8/17/2010 0 0 The OP -I2 will be converted into an injector and the OP -I1 will be sidetracked through the intermediate casing and drilled and completed as a lateral injector. Two development wells were drilled in 2008 and 2009. The OP03 -P05 producing well was drilled and completed in the 4 th quarter of 2008. The OP26 -DSP02 disposal well was drilled and completed in the 1s quarter of 2009. These wells provided additional structural information and petrophysical properties. The data acquired is consistent with the depositional environment, geologic concept and reservoir model. Drilling has restarted in April 2010 with a water source well OP23 -WW02 followed by the producers OPO4 -07 and OP08 -04. The current and future naming convention of the wells is: Drill location: Producer (P) /Injector (I) : Slot # _ Production Section Path # Oliktok Point Wells: Producer example: OPO4 -07 Injector example: 0I11 -01 Spy Island Wells: Producer example: SPO4 -07 Injector example: SI11 -01 3.4 PROJECT SCOPE & OBJECTIVES The Nikaitchuq field is an oil discovery. The main reservoirs of the field are OA and N Cretaceous sands within the Schrader Bluff formation. Minor oil accumulations have been tested in the Triassic "Sag River Sandstones ". The Nikaitchuq development is based on the exploitation of the OA Reservoir. The N sand and Sag River are not currently included in the scope of development. The potential of these reservoirs will be re- evaluated in the future based on drilling results and further evaluation of the 2008 OBC seismic acquisition. The development strategy consists of an onshore gravel pad located at Oliktok Point (OPP) and an offshore island pad (SID) constructed in 6 feet (1.8 m) water depth. The onshore development will contain dedicated multiphase processing facilities with a capacity of 40 Kbopd whereas the SID development is mainly a drilling location from which offshore production is imported via a flowline bundle to Oliktok Point by remote operations. Finally, Nikaitchuq production will be exported through a dedicated 14 mile (22.5 km) pipeline tied -in to the Kuparuk pipeline which exports oil to the TAPS system. The general project objectives are to develop the Nikaitchuq Field safely, efficiently, economically, and without any negative impact to the environment. 3.5 PROJECT OVERVIEW The development concept consists of the following: • Construction of a offshore gravel drilling island near Spy Island (complete) • Expansion of the Oliktok Point gravel pad near the existing CPAI seawater treatment facility (complete) • Construction of a 7 -acre operations gravel pad (complete) • 3D seismic acquisition to complete reservoir picture (high quality data obtained over a smaller area of coverage than planned due to the available operational window) Page 7 of 35 8/17/2010 0 0 • Onshore drilling of 10 producers, 8 injectors, 3 water source, 1 disposal • OP -I1 appraisal well drilled to intermediate casing point - ready for lateral section and completion as an injector • OP -I2 appraisal well drilled and completed as a producer - ready for preproduction or conversion to water injection • OP03 -P05 drilled and completed in 4Q08 • Disposal well drilled and completed and put in operation in 1Q09 • Drilling restarted in April 2010 with a water source well OP23 -WW02 followed by production and injection development wells. • Construction of a -14 mile pipeline from Oliktok Point to a tie in near KRU DS -1Y pad for connection to the Kuparuk Transportation common carrier pipeline (complete) • Installation of a 3 -mile subsea flowline and utility bundle to Oliktok Point for fluid processing (complete) • Fabrication, transport and installation of a sealift module housing production facilities • Installation of offshore drilling and gathering facilities • Offshore drilling of 16 producers, 13 injectors, 1 disposal • Consideration of future modifications required to accommodate actual results of well performance, produced water and water injection requirements • Purchase of fuel gas from CPAI • Generation of own power • Continued appraisal of the N sand. • Continued appraisal of the Sag River sand. Based on data acquired and additional study in 2008 & 2009, a well pattern has been designed shown below overlain onto a Schrader Bluff OA fault map. Drilling feasibility has been assessed for this new pattern and all wells are within acceptable and safe drilling tolerances. The expected drainage area of the current planned well pattern is shown as well as the well count. See Exhibit 6 and 7. Exhibit 6: Current Well Development Area and Pattern and Fault Map Exhibit 7: Development Scenario Schematic The field will be developed with the highest respect for the environment and the citizens in the North Slope communities. For that reason, the development plan includes the following: • Minimizing footprint for facilities, welisites, flowlines and operations camp • Secondary containment around wellheads • Pipe -in -pipe construction for produced fluids being transported from the offshore island and for the diesel pumped to the island The development concept has been revised and optimized based on the acquired seismic data, development well drilling and continued study and analogue field experience: • The 2009 OBC 3D Seismic survey was acquired in the summer of 2008 by PGS. The survey covered the main development area filling in areas not covered by the existing seismic and overlapping with the existing seismic over development area well control. • The processed 2009 OBC 3D Seismic survey data quality is quite good and effectively images the OA reservoir. The coverage area of the acquired seismic was much smaller than planned and the barrier island Spy Island created some undershoot problems. • The Onshore drilling well pattern has been modified to accommodate the geologic faulting mapped from the new seismic with these resulting wells. Onshore OPP • 10 producers including 1 drilled • 8 injectors including 1 drilled • 3 water source Page 8 of 35 8/17/2010 0 0 • 1 disposal - drilled and successfully disposed drill cuttings. Offshore SID • 16 producers • 13 injectors • 1 disposal 4 GEOSCIENCE 4.1 FIELD LOCATION AND FIELD DATA The Nikaitchuq field is located in northern Alaska, North Slope region, offshore in the Beaufort Sea. The main reservoirs of the field are the OA and N Cretaceous sands within the Schrader Bluff formation. Minor oil accumulations have been tested in the Triassic "Sag River Sandstones ". Exhibit 8: Stratigraphic Column The Schrader Bluff formation consists dominantly of marine sandstones and shale deposited within a foreland basin (Colville Basin) during the late Cretaceous period. At that time the source of the sediments was from the South West and toward this direction the Schrader bluff is interfingering with the non marine or marginal marine sediments of the Prince Creek formation. Toward the basin, far from the sediment source, the Schrader Bluff is interfingering with the deeper marine shales of the Canning formation. During the Tertiary period the fluvio- deltaic deposits of the Sagavanirktok formation completely filled up the basin and closed the sedimentary cycle. A full field 3D reservoir model (static and dynamic) was constructed for the OA and N sands at time of project sanction. The N sand reservoir model has not been updated as not enough new data has been acquired to warrant an update. A Sag River reservoir model has not been built to date. Sag River and N sand development has been deferred to the future. The full field 3D reservoir model (static and dynamic) has been updated for the main OA reservoir to incorporate the acquired 2009 OBC 3D seismic survey, 2 drilled development wells and the new optimized well pattern. A total of eight exploratory and /or appraisal wells have been drilled within the structure. Moreover, seven other neighboring wells have been considered in order to better define the geological model of the field. Two development wells were drilled in the 4 th quarter 2008 (OP03 -P05 producer) and in the 1St quarter 2009 (disposal well) and have been incorporated into the reservoir model update. For the OA sands, which are the main target of the Nikaitchuq development project, two well tests have been carried out (NIKA 4 and OI 2) in order to evaluate the production rates, to investigate the reservoir behavior, to assess the sands petrophysical characteristics and to collect oil samples. The OP03 -P05 producer was drilled and completed from Oliktok Point. The well has not been tested for rate nor was a fluid sample collected. All existing wells are described in the Introduction Section under Exploration and Appraisal wells. The OA sand hydrocarbons are viscous oil (16 -19 API with 100 -180 cp) characterized by a low GOR (70 -150 scf /stb). The production test rate achieved by well 0-I2 was of 2000 Stb /day on ESP lift. The well has been drilled from Oliktok Point with 6100 ft of horizontal drain. Page 9 of 35 8/17/2010 No well tests are available for the N sands. Better petrophysical parameters, in terms of porosity and permeability, have been identified for this level in respect to the OA sands, with a petrophysical property quality reduction in the area of the new two appraisal wells. The N sand was penetrated and logged with the 2 development wells adding to the petrophysical data set available for the N sand appraisal. Options for acquiring a fluid sample are being evaluated. The N sand is separated from the OA by approximately 100 -150'. 4.1.1 Field Data 6 wells (Nikaitchuq 1, 2, 3, 4, Tuvaaq ST1, Kigun 1) were drilled starting from 2004 to 2006. Seven neighboring wells were also considered to define the geological model: Thetis Island, Oooguruk, East Harrison Bay 1, Oliktok Pt 2, Kuparuk River 30 -08, Milne Pt Unit -L -01 and Northwest Milne 1. Bottom -hole cores were taken in two wells (Nikaitchuq 4 and Kigun 1) the OA sand. 4.2 GEOPHYSICAL ANALYSYS In the area of interest there are three 3D seismic surveys and some 2D seismic lines. The main seismic data set used to define the Nikaitchuq Field is a 3D volume, merged from two different volumes: the Simpson Lagoon and Thetis Island (wg_obc_patch3D) 3D datasets. Outside the area coverage of this 3D volume, 2D seismic and well data have been used to support the subsurface mapping. A 3D volume known as the WBA Kalubik is present southwest of the Tuvaaq well. This dataset covers a significant portion of the investigated area but was not used due to the poor signal quality. Proper evaluation of the entire field was problematic mainly because the southern portion of the field had very sparse seismic coverage. To mitigate this risk, Eni contracted PGS to shoot a proprietary 3D survey that was designed to cover the entire development. The new OBC 3D Seismic survey was shot by seafloor cable array during the 2008 summer open water season. The final Dual Sensor (Hydrophone and Geophone) PSTM processed volume was delivered in May 2009. The new survey's footprint (shown in blue on the map below) covers Eni's leasehold position over the Nikaitchuq development and overlaps two existing 3D surveys "Simpson Lagoon" and "Thetis Island" (shown in grey on the map below). Due to logistical issues, the survey area was smaller than planned, but covered the most critical area for the development. Exhibit 9: Seismic Survey Outlines shown with Well Pattern and Fault Map Several benefits were realized with the completion of the new data: • New 3D data was collected in the gap between the two existing surveys. • Increased certainty on sand and fault geometries • Increased frequency content at reservoir level allowing for discreet sand bodies to be mapped. Structural Analysis A structural setting was carried on the OA Sand using a workflow where a regional marker above the OA was picked above the target horizon. The horizon, referred to as the Schrader Bluff Marker, is a regional extensive seismic event that is easily identified on well logs. The Schrader Page 10 of 35 8/17/2010 • • Bluff marker confirmed the previous interpretation of a southwest to northeast dipping structure with a series of northwest to southeast trending normal faults. This new structural picture still reveals a series of faults through the center of the development, but none of these faults bisect the entire reservoir. The new interpretation suggests the field may not be exclusively divided by structural faults but could be a combination of depositional /strategraphic features. Internal faulting within the reservoir may create localized no -flow boundaries. Fault throws are estimated to range from 0' -80'. Exhibit 10: Seismic Based Structure - Top of OA Sand 4.3 GEOLOGY AND GEOLOGICAL MODELING 4.3.1 Sedimentoiogy The Nikaitchuq sands were interpreted as shelfal lobe deposits. Starting from the bottom, the first zone was interpreted as a distal prodeltaic system characterized by the succession of laminated sand and silt. The overlying deposits were interpreted as "mixed depositional system - shelfal lobe complex "; this complex consists of turbidite -like facies encased in structural depressions within distal delta -front and prodeltaic deposits (Mutti et alii, 2003). Three different shelfal lobes separated by silty layers or cemented layers rich in calcite were recognized in the area. The areal extension of these "turbiditic" bodies was defined by means of well correlation, analogues, and the qualitative interpretation of seismic amplitude maps. The N sand interval (no core data available) was interpreted in the same way by analogy; however a shifted position of lobes with respect to the OA sand interval was defined accordingly to the Seismic anomaly distribution and to well correlations. Exhibit 11: Sedimentological Environment Concept & Core Description One of the main benefits of the new seismic is the increased frequency content of the data. This revealed the OA to be not one large lobe, but several discrete lobes. Within the Nikaitchuq OA four lobes were mapped. These lobes, which can be seismically seen, give a geologic alternative to the different fluid regions seen in the field. 4.3.2 Petrophysics The range of petrophysical properties from logs are as follows: • Gross Thickness: 35 -47 feet • Net -to- Gross: 65% - 93% (high side is from a lateral well) • Porosity: 24%- 35% • Water Saturation: 23% - 45% (high side is likely in a transition zone) • Permeability: 92 - 627 and Table 1 - CONFIDENTIAL - Table of well OA properties (Thickness, NtG, Sw & k) Reference Annex 9.1 page 36 Water Saturation The capillary pressure curves and Initial water saturation evaluation was approached by using a methodology (Petromation). However, based on well test results at Nikaitchuq 4 (where no formation water production was observed) and log data evidence (OWC at NIKA 2 and transition zone NIKA 4) the dynamic model was tuned to reproduce the experimental observation. Page 11 of 35 8/17/2010 Synthetic Permeability A synthetic permeability log was calculated using K /phi correlation from core data for three different groups of facies: sandy facies (1 to 3), laminated sand facies (4) and non -Pay facies (5, 6 and 7). Exhibit A - CONFIDENTIAL- kh v Porosity cross plot for High Quality Sand Facies Exhibit B - CONFIDENTIAL- kh v Porosity cross plot for Laminated Sand Facies 4.3.3 OA Geological Model Two new wells including a development producer (pilot hole and horizontal section) and a near vertical disposal well were drilled in 2008 and 2009 Exhibit 12 - Map of Well Data Set for Model The Nikaitchuq static model was built using Petrel modeling software. The main phases of the modeling workflow consisted of the construction of the geometrical model, the data analysis, the facies simulation, the petrophysical characterization, the OHIP evaluation and the uncertainty evaluation. See Exhibit 12 for well locations. Geometrical model - Structural setting The OA Sand Schrader Formation is the main reservoir of the Nikaitchuq area. Regionally, this reservoir was encountered at depths from 3,000' to 5,000' s.s.l. The structure is a monocline dipping very gently to the northeast; the continuity of the structure is interrupted by a set of normal faults with NW -SE strike, related mainly to the Cretaceous extension of the Beaufort Sea. The trap is structural and stratigraphic. The up -dip wells located south and west from the Nikaitchuq area record a thin oil sand (East Harrison Bay Statel) or no sand at all at the OA stratigraphic level (Thetis Island and Oooguruk). The structural closure is toward north -north east. Down dip (to the northeast) the OA sand is present in all the wells and it is oil full to base apart from the lowest wells ( Nikaitchuq 2, North West Milne 1 and Milne Pt Unit). The precise sand pinch out point between the oil wells and up dip shale equivalent wells has been interpreted from the 2008 OBC Seismic survey. Northward there are no wells but a sand pinch out is believed to be well north beyond the unit boundary based on amplitude maps coming from interpretation on 3D seismic volumes and the sedimentology evaluation. To the Southeast it is believed that the both the structure and both the N and OA sands extend beyond the requested pools toward Milne Point and West Sak. The top confining formation is the Schrader Bluff top shale between the Lower Ugnu and the N sand. The thickness of this top confining interval is approximately 50' to 100' thick. The bottom confining interval is the Canning Hue shale between the base of the OA sand and the Torok. This interval is over 2000' thick. On the Exhibit 2 Kigun No.1 type log the top and base of the N Sand and the OA sand are marked. The N sand is defined as the correlative interval from -3495' to -3531' TVD SS (3627' to 3663' MD) in the Kigun No.1. The OA sand is defined as the correlative interval from -3648' to -3690' TVD SS (3780' to 3822' MD) in the Kigun No.l. Due to the thinness of OA sand, the presence of continuous faults with stratigraphic throw higher than 20 -30' could represent a tight barrier. Page 12 of 35 8/17/2010 • • Section CONFIDENTIAL - Description of geophysical interpretation of depositional features and impact on structural interpretation and possible compartmentalization. Reference Annex 9.2.1 page 37 Exhibit C - CONFIDNNTIAL Structural Map; East Lobe Isolated Scenario Exhibit D - CONFIDENTIAL Structural Map: North & East Lobe Connected Scenario OA Thickness Model • The OA reservoir thickness cannot be resolved from the new seismic data. • OA isochore maps reflecting a Low, Base and High case have been generated by mean of well thickness control points. Outside well control area, 2007 model thickness constrains have been honored. Horizontal wells (OP -I2, Nik -4 and P05) fully integrated in the structural model. Petrophysical model - Section CONFIDENTIAL - Discussion of internal petrophysical analysis techniques. Reference Annex 9.2.2 page 37 Permeability - Section CONFIDENTIAL - Discussion of internal petrophysical analysis techniques. Reference Annex 9.2.3 page 38 Water saturation - Section CONFIDENTIAL - Discussion of internal petrophysical analysis techniques. Reference Annex 9.2.4 page 38 Contacts and compartmentalization The oil water contact was estimated at -4177' TVDSS in Nikaitchuq 2 based on the resistivity log. Two more wells encountered the OA sand at this depth but the presence of silty facies didn't allow recognizing the contact depth. 1 MDT measurement was recorded in the Kigun well, but it was not possible to compute the free water level because the measurement in water is not available. The OA sand in the drainage area is most likely divided into two blocks with different oil properties which split the area of Kigun 1 and 0I -2 from 0I -1 and NIKA -2 and NIKA -4 one. The transmissibility of the other minor faults has been considered. Section CONFIDENTIAL - Description of geophysical interpretation of depositional features and impact on structural interpretation and possible compartmentalization. Reference Annex 9.2.5 page 38 Static Uncertainty Evaluation In order to explore the field potential and to assess the possible range of outcomes of the project, an uncertainty evaluation was performed. The first step of this work was to identify the critical parameters that mainly impact the volumes estimate. Structure Two sensitivities were executed to test the impact on the bulk volume of the uncertainties related to the top depth and the OA sand thickness. Page 13 of 35 8/17/2010 0 M The uncertainty on structure is caused mainly by uncertainty on depth conversion (velocity field); the thickness, due to the thinness of the reservoir, was not identified by geophysical interpretation but was estimated using well data and, as soft information, the sedimentological model. The analysis highlights the strong effect due to thickness uncertainty ( + -14% on GBV) with respect to uncertainty on depth position ( + -2 %). Thus 3 cases from the sanction evaluation approximately equivalent to base, high and low are shown below. Exhibit E - Confidential OA sand gross thickness: base, high and low case In the 2009 Reservoir Model update three sensitivities were executed to test the impact on the bulk volume of the uncertainties related the OA sand thickness. The sensitivities impact the bulk volume primarily in the area outside of the well control. Within the well control the gross thickness is near equivalent. The thickness uncertainty outside of well control can not be resolved from the new seismic data due to the fact that the thickness of the OA reservoir is below seismic tuning thickness. Exhibit F - CONFIDENTIAL High and Low Case Net Thickness Maps The bulk volume difference within the lease varies from -7% to +4% from the Base Case. Porosity - Section CONFIDENTIAL - Discussion of internal petrophysical analysis techniques. Reference Annex 9.2.7 page 39 STOOIP Volumetrics (OA Reservoir) For the geostatic volumetric assessment, a Boi of 1.065 RB /STB has been applied on both reservoir regions (19 - 16 API). In addition, a constant OWC has been assumed corresponding to the OWC of 4177' TVDSS established by the Nik 2 well. Potential variability in the OWC has been assessed in the dynamic risk analysis. The static uncertainty evaluation of the Schrader Bluff OA reservoir resulted in an assessment of OOIP ranging from 800 -930 million STB. The median OOIP from the uncertainty evaluation was 870 million STB. Table 2 - CONFIDENTIAL Volumetric Results: Bulk Volume, Net Volume, Pore Volume, HCPV & OOIP Reference Annex 9.2.8 page 39 Exhibit 13 - OA Net thickness Base case 4.3.4 N Geological Model A static evaluation of the N Sand level was performed in 2007. It has to be highlighted that the results of this evaluation and moreover its reliability is strongly affected by the paucity of the available dataset: a complete set of logs are available on 4 wells only; for the other wells only GR and sometime Resistivity is present; no cores have been cut; no well tests have been performed; no valid and reliable Formation pressure measurements have been taken. Page 14 of 35 8/17/2010 The N sand complex is overlaying the OA reservoir. The average thickness of the shaly interlayer between the two is ranging from 80 to 120 ft. According to the well log correlation it can be assumed that the N Sand system has been sedimented in a very similar depositional environment as the OA sand. An evaluation of the N sand depositional environment is ongoing as the seismic data interpretation may impact the current understanding. The structural setting and the fault modeling does not change with respect to the OA sand. The geophysical interpretation provided the top of the level while the bottom of the reservoir was built using a thickness map honoring the wells. In the following table a brief lithological description and the petrophysical main values for each facies class is reported Litholow 4) effective me NtG SWi mean Facies 1 Very Qood sand ; 0 333 v l 1 0.13 Facies 2 Go sa nd 0.234 j 1 0.22 Facies 3 i Silt 0.13 0 1 F aa_ es 4 i _ _ Shale 0.052 Q__ Facies 5 Cemented sand rich in calciteT 0.083 0 j 1 With respect to the OA sand, the N Sand lobe extension was wider and the position shifted westward. It should be noted that there is considerable overlap of the N Sand and the OA Sand within the Pool Rules Area. The oil /water fluid contact in the N sand is uncertain. The contact may range between water -up- to (WUT) (3949' TVDSS at Nikaitchuq 4) and oil- down -to (ODT) (3643' TVDSS at Oliktok Point I- 1). These two depths plus a third one (hypothetical OWC at the intermediate position of -3796) has been considered in the N Sand volumetric evaluation for the Maximum, Minimum and Base Case respectively. N Sand compartmentalization: the presence of wet sand at the N sand stratigraphic position in East Harrison Bay, updip and westward respect to the main area of the field, lead to the conclusion that some sort of compartmentalization is present in the N sand. At Thetis Island 1 the log section is incomplete due to the surface casing point and therefore is not conclusive for the N sand. Within the 3D coverage the presence of almost continuous faults with throw higher than 20 -30 feet could represent a barrier, but, according to the fault interpretation there is not clear evidence of a continuous barrier in the area, even if major faults features are present. For the OOIP calculations a western boundary shown in red on the following maps, Exhibit 14, has been assumed as a notional fault boundary separating the East Harrison Bay St 1 and Kigan / Tuvaaq wells. Exhibit 14 - N Sand Structure Map with Possible Oil Water Contacts Another possible explanation, not supported by seismic or log interpretation, is the possible effect of a stratigraphic feature as pinching or shaling out of the sand bodies. In any case, assuming the alternative interpretation (sand pinch out) will not materially modify the final value of OOIP. To the Northwest the N sand thickness and saturation is unknown and prospective. Further interpretation of the new seismic data help may to better define the N sand extend and compartmentalization. Under these assumptions the range of OOIP for the N sand as a potential resource within the Nikaitchuq Unit has been calculated to be 300 to 600 million STB. Page 15 of 35 8/17/2010 0 0 The N sand Reservoir model has not been updated because not enough new data has been acquired to incorporate the N sand into the Nikaitchuq development project. Additional data acquisition for the N sand will result from LWD logging of OA development intermediate well sections. Dedicated operations to acquire N Sand fluid samples will be evaluated. The feasibility of N sand development will be re- evaluated when sufficient data become available. 4.3.5 OA and N Mapped and Prospective Limits within the Nikaitchuq Unit Sufficient well control, geologic and geophysical data exists to map the limits of the OA and N sands within the Nikaitchuq unit. There is a higher level of confidence in the central and southern area of the unit because of the well control and the interpretation of the 2008 OBC Seismic data. For the OA there interpretation of the seismic data has mapped a western boundary that is between the Thetis Island No.1 and Tuvaaq State No.1 that is consistent with the well control where Tuvaaq State No.1 shows oil filled reservoir and the Thetis Island has no sand. To the Northeast there are mapped notational depositional boundaries where seismic date is available, Beyond this seismic coverage area the OA is prospective based on the depositional model. No well control contradicts this prospective area. For the N sand the mapped extend is based on well control and the 2009 OBC seismic data. The N sand is more difficult to interpret on seismic. Along the north and western limit of well control the N sand is present in both the East Harrison Bay St 1 (wet), Nik well group (wet) and the Kigaun 1 /Tuvaaq State 1 wells (Oil). The N sand is prospective north of the 2008 OBC seismic data and to the Northeast and Northwest where no data exist. There is no evidence that the N sand does not extend up to the northern extent of the unit. Exhibit 15 - OA and N Sand Mapped and Prospective Sand Outlines Exhibit G - CONFIDENTIAL OA and N Sand Well Correlation & Cross Section West- East Exhibit H - CONFIDENTIAL OA and N Sand Well Correlation & Cross Section South -North 4.4 RESERVOIR MODELLING 4.4.1 Dynamic Model Introduction N Sand Development of the N sand was not sanctioned and there has not been enough h additional reservoir or fluid data acquired to date to advance the appraisal the N sand potential. A recovery of the N sand potential resource has been estimated to be 4 % -8% of OOIP based on the results of the 2007 Reservoir study. This relatively low recovery is due to the uncertainty of the rock and fluid properties. A plan for data acquisition has been developed that will allow for a proper appraisal of the N sand in the future during the initial OA drilling campaign. OA Sand The 2009 dynamic OA reservoir model update was built without upscaling of the geological models. The merged grid dimension is 300x236x38. The cell size is 300x300x2ft, tin. The structures and petrophysical data (facies, permeability, porosity, NTG, irreducible water saturations, regions) of geologic models have been imported into the dynamic model. The Page 16 of 35 8/17/2010 a 0 available PVT updated with 0 -I1 and 0 -I2 OA fluid samples analysis results have been incorporated into the model. Advanced core analysis data are honored in the dynamic models, where a saturation function for each facies has been introduced. The OA sand OWC has been observed at NIK 2 at - 4,177' TVDSS and is included in the dynamic model with a transition zone of about 15 feet as observed from logs and calibrated to honor the well testing results at NIKA -4 to avoid water production. Section CONFIDENTIAL - Description of Dynamic Reservoir Model (Eclipse) with respect to potential compartmentalization. Reference Annex 9.3.1 page 40 The pore volumes and the volume in place at reservoir conditions obtained from the initialization of the dynamic model have been checked with the volumetric from static model for the 189 realizations. There is no upscaling from geological to the simulation model. Exhibit I - CONFIDENTIAL Comparison of the Petrel & Eclipse - OOIP Saturation function The relative permeability curves and the end points from Nik #4 and Kigun #1 wells were selected and assigned to the various facies. Exhibit 3 - CONFIDENTIAL Relative Permeability Curves The relative permeability to water has a considerable impact on water breakthrough. A multiplier of Krwr was used to simulate the effect of Krwr endpoint scaling up to a value of 1 to represent observed analogue water breakthrough and water cut trends. PVT, Reservoir Pressure & Temperature Based on the available PVT data from Nik #4, Kigun #1, 0 -I1, and 0 -I2 wells, the PVT properties across the Pool vary from 16.3 API to 19 API with a viscosity range of 188 cp to 95 cp. The saturation pressure is in the range of 1050 - 1150 psia in the reservoir compartment containing the 0 -I1 well and is 750 psia in the reservoir compartment which includes the 0 -I2 well. The 0- I2 PVT results show different oil properties in respect to 0 -I1 as indicated in the next table: Well Oil Bubble Solution Formation Volume Gas Viscosity Gravity Point GOR (Rs) Factor (Bo) Gravity , cP °API psi scf /stb rb /stb OP -I1 16 1150 140 1.050 0.59 188 OP -I2 19 750 80 1.045 0.67 100 The initial reservoir pressure is 1700 psi at a datum of -3760' TVDSS based on MDT's in the OP -I1 and Kigan wells in the OA reservoir. The N sand appears to be on the same gradient based on MDT's in the Kigun well. Exhibit K - CONFIDENTIAL Nikaitchuq MDT Pressures Fluid Regions - Section CONFIDENTIAL - Description of the dynamic modeling of the potential compartmentalization within the OA sand. Reference Annex 9.3.2 page 40 Exhibit L - CONFIDENTIAL - Eclipse Fluid Regions Page 17 of 35 8/17/2010 Calibration of Geologic Models— Section CONFIDENTIAL Description of the well tests and the calibration of the reservoir model to the well test results Reference Annex 9.3.3 page 40 Exhibit M — CONFIDENTIAL Horizontal Well Test Results: Development Plan The development plan can be summarized as follows: • Two drilling pads, one onshore (Oliktok Point) and one offshore (Spy Island). 10 OA producers and 8 OA injectors drilled from Oliktok Point, 16 OA producers and 13 OA injectors drilled from Spy Island. Producers and injectors are horizontal wells with laterals ranging from 4000 - 8500 ft. • Producers and injectors are in pairs, located side by side. • In most cases com roducers rise the outboard wells P P ESP pumps to be used to artificially lift the oil to the surface. The water injection to be applied from the beginning of the production to maintain the reservoir pressure. The Ivishak formation water to be used to serve as the make -up water. The produced water will be treated and re- injected into the formation. Exhibit 6: Current Well Development Area and Pattern and Fault Map To develop the drilling pattern four objectives were identified as the basis for creating the pattern. 1. Where possible, drill wells in the maximum horizontal stress direction (Northwest - Southeast) to minimize risk of premature water breakthrough. 2. Optimize drilling order: With the well pattern set, the drilling order was optimized to gain data early to: a. Delineate the reservoir for Geologic and Reservoir Modeling b. Acquire data for drilling and completions 3. Optimize reservoir recovery: The reservoir sensitivity studies show that the most crucial factor in recovery is reservoir contact by the production wellbores. Reservoir contact in producers has a greater impact on recovery than reservoir contact with injectors. Therefore, the objective is to have more producers than injectors with maximum reservoir coverage in the laterals in the producers. To meet this objective, extending wells to the reservoir and /or lease boundaries, having outboard producers, and producers bordering faults were set out as requirements. Well spacing was also studied and it was determined that 1200' was optimal for this reservoir. 4. Well spacing of 900 to 2500 feet was studied. Even though Eni is planning to use nominal 1200 foot well spacing, we are asking for unlimited well spacing within the reservoir. A set back of 500 feet from exterior lease boundaries is requested. See Exhibit 6 for a depiction of the drilling pattern. Recovery Mechanism The crude quality imposes the need for the adoption of a secondary recovery mechanism to obtain an economic production profile. Water injection has been adopted as the main improved recovery process for the Nikaitchuq field and the water flood technique has been widely used on the North Slope such as in the Schrader Bluff formation at Milne Point, Prudhoe Bay and West Sak fields. Page 18 of 35 8/17/2010 0 0 4.5 RESERVES FORECAST AND PRODUCTION PROFILES 4.5.1 Reserves Forecast and Production Profiles The 2009 dynamic model was run out to 50 years in order to establish a potential technical reserve estimate. Although the viscous oil waterfloods on the North Slope of Alaska are relatively young (less than 10 years oil), 50 years is not an unreasonable field life with respect to worldwide viscous oil analogues. Many of the Canadian viscous oil waterfloods have achieved recover factors in the range of 30% to 40% over decades of operation. However, due to uncertainties of forecasting this far into the future, a 30 year reserve life has been imposed. Sensitivity work has been performed to assess the impact of various known uncertainties both n dynamic. Th r I f hi n sensitivity show the range of potential 30 a d e results o this se s geologic Y year technical 9 P Y recovery ranging from 15% to 22% of the lease OOIP. The economic recovery percentage could be substantially lower than the technical recovery percentage depending on the economic assumptions in the future. Taking a deterministic approach assuming the most likely value for all input results in a high side case with respect to the sensitivity analysis, The resulting profile from this deterministic case is shown in Exhibit 16. At the 30 year life the model predicts production to be approximately 7000 STB /day, which according to the economic condition of this time, may or may not be economic. Simulation constraints The constraints utilized in the dynamic model can be summarized as follow: • Geologic Model Mid Case OOIP • Geologic Scenario East Lobe as a separate fluid region • Oil -water contact - 4,177' TVDSS • PI multiplier (producers & injectors) 0.55 - well test HM • Skin factor 0 • Voidage Replacement Ratio 100% • Minimum flowing pressure (ESPs) 850 psi at bottom hole • Drawdown limit 300 psi • Max injection pressure 2384 psi at bottom hole • Max water cut 95% • Field Life 50 years Exhibit 16 - Deterministic Approach Recovery of Oil and Oil Rate Profile Other Sensitivities The following "Well Development" issues were investigated: • Primary Depletion • Well Spacing • Well Density Conclusions of the sensitivity analysis: • Primary depletion results in 30 year Recovery Factor of 4 -5% (All Wells completed as Producers) • Reducing Well Density results in lower recovery and lower recovery efficiency with respect to pore volumes injected in all scenarios. • Well spacing of 1200 feet optimizes recovery rate, overall recovery factor and development /operating costs. Page 19 of 35 8/17/2010 ! 0 5 DRILLING AND COMPLETION 5.1 GENERAL PLAN 5.1.1 Oliktok Point Drilling The Schrader Bluff -OA sand development from Oliktok Point is expected to consist of ten (10) producer wells and eight (8) injector wells. Also, three (3) water supply wells and one (1) disposal well will be required for drilling and production operations. Currently, one (1) producer well, OP03 -P05, and one (1) disposal well, OP26- DSP02, have been drilled by ENI. There are also two (2) wells drilled previously by Kerr McGee. OP -I2, at this time, is completed with an ESP and will be converted to an injector. OP -I1 has been plugged back to the surface casing. At present, no multilateral wells are planned for the Nikaitchuq development. All wells are anticipated to be directionally drilled from Oliktok Point into the Nikaitchuq acreage located offshore with tangent angles between a 50 inclination. The injection and production wells will include 4,000'- 10,000' lateral sections through the reservoir. The wells will be completed with slotted liners and will rely on surface sand management. Production and water source wells will rely on Electric Submersible Pumps (ESP's) as the artificial lift method. Eni has permission to transit wellbores though acreage held by CPAI to reach the Nikaitchuq unit. Drilling operations will be executed from the OPP drill site using the Nabors 245E rig. Lessons learned from onshore operations will be applied to SID. Drilling was restarted in April 2010 and will continue at least through 2Q 2012. 5.1.2 Spy Island Drilling The Schrader Bluff OA sand development from Spy Island is expected to consist of sixteen (16) producer wells and thirteen (13) injector wells. Also, one (1) disposal well will be drilled to inject Spy Island cuttings only. All OA wells are anticipated to be directionally drilled from the island into the Schrader Bluff reservoir with tangent angles between 50 -80 inclination. The injection and production wells will include 6,000' - 10,000' lateral sections through the reservoir. The wells will be completed with slotted liners and will rely on surface sand management. The producing wells will rely on ESP's as the artificial lift method. A dedicated drilling rig will be mobilized to the offshore island in the third quarter 2011. Drilling will also commence during the third quarter 2011. 5.2 WELL PATTERN In the summer of 2009 new seismic was acquired in the Nikaitchuq lease revealing several different sand lobes then previously thought. With this new information the well trajectories were redefined to better exploit the reservoir geology. See Exhibit 17 OPP SID Totals m Injector 8 13 21 Producer 10 16 26 Disposal 1 1 2 3: lWater source 3 0 3 Totals 22 J 30 52 Page 20 of 35 8/17/2010 Exhibit 17 - Well Drilling Field Spider Diagram 5.3 WELLS DESIGN Wells will be drilled through pre - installed 20" Conductors set +/ -120' below ground level following pad construction. On Oliktok Point, conductor pipe (CP) has been set. On Spy Island the 20" CP will be driven. 5.3.1 Casing design ➢ 13 - 3 /8" 68# L -80 BTC set below permafrost and any productive hydrocarbon bearing zone in the Ugnu formation +/- 2,100' - 2900' SSTVD. ➢ 9 - 5 /8" L -80 40 -47# BTC -MOD is set at the heel of the production horizontal (top -OA sand). ➢ 5 - L -80 15.5 -17# DWC / Hydril 521 slotted liner set at TD. The slot- configuration for the 5 - slotted liner would be designed to enable rotation with torque loads of > 10 kft- I bs. The following figure Exhibit 18, provides an example schematic of the Schrader Bluff producers and injectors showing their proposed long reach casing profile as well as cementing detail. Completion details follow in the next sections. Exhibit 18 - Example Well Bore Schematic 5.4 DIRECTIONAL PLANS All Schrader Bluff wells will incorporate horizontal completions. The directional profiles will build and hold to the reservoir entry point where the angle will be built to 85 0 /90 0 to land in the Schrader Bluff. The intermediate hole section will then be cased prior to drilling the lateral section. Drilling below the intermediate casing will consist of maintaining a 6,000710,000' lateral section through the reservoir interval. Navigation through the reservoir will be achieved by Geo- Steering using a Rotary Steerable System to remain in the reservoir. Most lateral sections are oriented parallel to the Northwest- Southeast maximum insitu stress direction. Routine pilot holes are not planned, but an initial pilot hole was utilized to define the top of the reservoir in OP03 -P05. It is assumed that build rates of 3.5 0 /100' will be used, with KOP at approximately 200'. Planning build & turn rates for the longest reach wells will be limited to <- 4 0 /100'. Slide- drilling will not be possible in all hole sections; therefore, wellpath planning will be within Rotary Steerable BHA equipment capability. A Steerable motor BHA will be used in the surface hole, while a Rotary Steerable BHA (RSS) will be used in the intermediate and production hole. 5.5 DRILLING SCHEDULE On Oliktok Point, one producer (OP03 -P05) has been drilled and completed. The disposal well (OP26- DSP02) has also been drilled and completed. There are also two (2) wells drilled previously by Kerr McGee. OP -I2, at this time, is completed with an ESP and will be converted to an injector. OP -I1 has been plugged back to the surface casing. All wells will be drilled and completed in a sequential order. The water source well, OP23 -WW02, was spudded in April 2010. Page 21 of 35 8/17/2010 0 0 On Spy Island, the disposal well will be the first well to be drilled. The wells to be drilled beginning mid -2011 will be consistent with the needs of the Reservoir Formation Evaluation Plan and Drilling learning curve. All wells will be drilled and completed in a sequential order. 5.6 RIG TYPE 5.6.1 Oliktok Point Plans are to use Nabors 245E, currently under contract to Eni, for development drilling at Oliktok Point. The rig is capable of moving on its tracked moving system. Once positioned, the rig floor cantilevers over the wells. The rig will be utilized for drilling and workover operations. During the development of Oliktok Point, the rig will be capable of performing workovers on failed ESP producers. 5.6.2 Spy Island Currently, plans are to use Doyon 15 for development drilling on Spy Island. The rig is anticipated to be mobilized to the island by barge in the summer season of 2011. The rig will be utilized for drilling and workover operations. During the development of Spy Island, the rig will be capable of performing workovers on failed ESP producers. 5.7 WELL COMPLETION STRATEGY The current completion strategy utilized for the Nikaitchuq development was chosen to provide the capability of integrating a complex reservoir monitoring plan and also minimize cost and risk for the initial installation. The completion will provide a simplified means of rigless intervention operations for both injection and production wells. When using the data gathered from the monitoring program and the intervention options provided by the completion design, more efficient well operations will be realized to help maintain optimum production capacity. Well operations should result in more timely and minimized operational expenditures throughout the long -term life of the development 5.8 COMPLETION REQUIREMENTS The project completion requirements were discussed and agreed upon among the Eni Completion, Production and Reservoir departments. The requirements were determined by considering factors such as installation feasibility, well cleanup options, reservoir monitoring and data gathering, value of collected data, ease of injection control and remediation options with respect to cost and time. Each type of completion will have individual requirements as outlined by the following descriptions. PRODUCTION WELLS CONFIDENTIAL - Completion detail and schematic. See Annex 9.4 Exhibit N - CONFIDENTIAL Production Well Completion Plan INJECTION WELLS CONFIDENTIAL - Completion detail and schematic. See Annex 9.5 Exhibit O - CONFIDENTIAL Injector with Injection Control Exhibit P - CONFIDENTIAL Injector with Monitoring and Injection Control Page 22 of 35 8/17/2010 9 6 5.9 COMPLETION AND RESERVOIR MONITORING STRATEGY The completion and monitoring strategy for Nikaitchuq is designed to offer several strategic benefits throughout the life of the development. The planned strategy will provide a good understanding of the reservoir early in the project as production facilities become operational. The SID development will also benefit from this early understanding which will be incorporated as appropriate. The data monitoring strategy will provide valuable information used in the management of production and injection to sustain optimized production rates. The combined 9 P J P P completion and monitoring system will also provide tools to analyze and remediate wells with minimized intervention operations for events such as early water breakthrough. This will prove to be a valuable feature as the reservoir will be managed through water -flood injectors. 5.10 FACILITIES CONCEPT The Nikaitchuq development concept is for a stand alone development with minimal required support from existing near -by facilities and infrastructure. As such, the field will be developed to produce, process, and transport sales quality crude oil to a sales oil transportation line. Personnel and equipment required for the operation will for the most part be dedicated to Nikaitchuq. Exhibit 19 - Development Plan Map Exhibit 7 - Development Scenario Schematic SITE PLANS The current layout drawings for the three gravel pads are shown below - See Exhibits 20, 21 and 22. (see also Annex 2): Exhibit 20 - Oliktok Point Pad (OPP) Exhibit 21 - Spy Island Drill Site (SID) Exhibit 22 - Nikaitchuq Operations Center (NOC) 5.11 DESIGN CAPACITY The nominal design throughput capacity of the Nikaitchuq facility is as follows: Design Throughput Initial Gross Liquid (blpd) 161,000 ** Oil Production (bopd) 40,000 Gas Production (MMscfd) 6.2 Gas Injection (MMscfd) 0 (dedicated to fuel use) Produced Water (bwpd) 121,000* Water Injection (bwpd) 171,000 * - Approx 81,000 bpd re- circulated water ** - Total oil, produced water and re- circulated water Note: Re- circulated water volumes decrease as natural water -cut increases. Design is to create 75% water -cut at the facility from initial start-up Page 23 of 35 8/17/2010 9 0 S. 12 TRANSPORTATION TO MARKET Oil processed at the Oliktok Point Facility will be transported via a 10" oil gathering line to the Kuparuk Pipeline which transports oil to TAPS (Trans - Alaska Pipeline System). TAPS transports oil to the port of Valdez, Alaska where oil is loaded out on oil tankers for shipment to the West Coast of the United States. 5.13 PRODUCTION AND OPERATIONS The overriding priority in production operations is the safety of all who work in the Nikaitchuq facilities, and care for the environment. Safety and the environment will never be compromised for the sake of expediency. This ideal is built into the facilities design and into the philosophy of operations. The Facilities will be managed at a minimum to meet all applicable standards in place by the State of Alaska, EPA and all other governing bodies who have jurisdiction. Continuous improvement will be the guiding philosophy at all times and with all aspects of operations. Nikaitchuq will be the first stand -alone processing facility operated on the North Slope by a company other than BP or CPAI. In addition, the Nikaitchuq facilities will be the first operated facilities for Eni in the State of Alaska. The Company will be judged by regulatory agencies, partners, other operators and the public based on these facilities. Thus the facilities will remain throughout their lives well maintained, clean, efficient and attentive to all EH&S criteria. 5.13.1 Genera/ The wells will be started up in accordance with the Well Start-Up Guidelines which are still being developed. The ramp up of rates on the wells will be slow in order to minimize the chance of sand production. The wells will be produced to maintain an optimal bottom hole pressure. The start up and operation of the Facility Systems will be in accordance with the Start up and Normal Operating Procedures developed for each system. These developed Operating Procedures will meet all requirements of the Process Safety Management for Hazardous Chemicals Guideline 29 CFR 1910.119. 5.13.2 Sales Metering and Well Testing Custody q transfer of Nikaitchuq oil will take place in the Oliktok Point Processing Facility LACT just prior to entry into the 14 mile gathering line that connects Nikaitchuq with the Kuparuk Pipeline (KPL). At the end of the gathering line, just prior to entering the KPL pipeline, there will be a check meter that will communicate back to the control room at the Nikaitchuq facility. This meter will be a critical environmental tool as it will be an immediate indicator of the integrity of the gathering line. Proving of the LACT meter will be done on a regular basis. The frequency will at a minimum be that which is required by the AOGCC (yet to be determined for Nikaitchuq). Other considerations are the needs of the Nikaitchuq Unit and the owners of the Kuparuk Pipeline. The proving will be done by a qualified company approved by the AOGCC and KPL. Multiphase meters (MPM) will be used for well testing. There will be no test separators. Schlumberger VX multiphase flow meters will be used. Good reservoir management and good well management depend on accurate measurement. Wrong decisions can be made and money lost by relying on inaccurate data. Properly applied, Nikaitchuq will have accurate tests with the MPM. The following are some of the advantages: • More accurate measurement with foam and heavy oil emulsions • Smaller footprint Page 24 of 35 8/17/2010 0 0 • No need to separate fluids twice, saving money on chemicals and heat • Faster well tests, as there is no need to come to stable conditions as with a test separator. This allows quicker detection of problem wells. • Continuous measurement allows for better troubleshooting of problem wells • MPM can handle the expected sand production without damage 6 DEVELOPMENT SCHEDULE • Sealift Modules arrival to the Slope Aug 2010 • Onshore process facilities install Aug - Oct 2010 • FCO / Precommissioning Oct -Dec 2010 • Onshore First Oil Jan - 2011 7 PROPOSED NIKAITCHUQ SCHRADER BLUFF POOL RULES Eni, in its capacity as Nikaitchuq Unit Operator, respectfully requests that the Commission adopt the following Pool Rules for the Nikaitchuq Schrader Bluff Oil Pool: Rule 1: Field and Pool Name The field is the Nikaitchuq Field and the pool is the Nikaitchuq Schrader Bluff Pool. The Nikaitchuq Schrader Bluff Pool is classified as an Oil Pool. Rule 2: Pool Definition The Nikaitchuq Schrader Bluff Oil Pool is defined as the accumulation of hydrocarbons common to and correlating with the interval between log measured depths 3,530 feet MD and 3,867 feet MD in the Kigun No.1 well ( -3,398 and -3,735 feet TVDSS, respectively), within the area described below. 390433 T. 15 N., R. 9 E., UMIAT MERIDIAN Section: 31 Protracted, All tide and submerged lands shoreward of the line fixed by coordinates found in Exhibit A of the Final Decree in U.S. v. Alaska, No. 84 Original Section: 32 Protracted, All tide and submerged lands shoreward of the line fixed by coordinates found in Exhibit A of the Final Decree in U.S. v. Alaska, No. 84 Original 389720 T. 15 N., R. 9 E., UMIAT MERIDIAN Section: 33 Protracted, All tide and submerged lands shoreward of the line fixed by coordinates found in Exhibit A of the Final Decree in U.S. v. Alaska, No. 84 Original Section: 34 Protracted, All tide and submerged lands shoreward of the line fixed by coordinates found in Exhibit A of the Final Decree in U.S. v. Alaska, No. 84 Original 389719 T. 15 N., R. 9 E., UMIAT MERIDIAN Section: 25 Protracted, All tide and submerged lands shoreward of the line fixed by coordinates found in Exhibit A of the Final Decree in U.S. v. Alaska, No. 84 Original Section: 26 Protracted, All tide and submerged lands shoreward of the line fixed by coordinates found in Exhibit A of the Final Decree in U.S. v. Alaska, No. 84 Original Section: 35 Protracted, All Section: 36 Protracted, All 388581 T14N., R.9 E., UMIAT MERIDIAN Sec: 5 Protracted, All tide and submerged lands Sec: 6 Protracted, All tide and submerged lands Sec: 7 Protracted, All tide and submerged lands Page 25 of 35 8/17/2010 0 6 Sec: 8 Protracted, All tide and submerged lands 388580 T14N., R.9 E., UMIAT MERIDIAN Sec: 3 Protracted, All tide and submerged lands Sec: 4 Protracted, All tide and submerged lands Sec: 9 Protracted, All tide and submerged lands Sec: 10 Protracted, All tide and submerged lands 388579 T14N., R.9 E., UMIAT MERIDIAN Sec: 1 Protracted, All tide and submerged lands Sec: 2 Protracted, All tide and submerged lands 388583 T14N., R.9 E., UMIAT MERIDIAN Sec: 17 Unsurveyed, All tide and submerged lands Sec: 18 Unsurveyed, All tide and submerged lands Sec: 20 Protracted, All tide and submerged lands T14N., R.9 E., UMIAT MERIDIAN TRACT A Sec: 17 Unsurveyed, All Uplands Sec: 18 Unsurveyed, All Uplands 388582 T14N., R.9 E., UMIAT MERIDIAN Sec: 16 Unsurveyed, All tide and submerged lands Sec: 21 Unsurveyed, All tide and submerged lands T14N., R.9 E., UMIAT MERIDIAN TRACT A Sec: 16 Unsurveyed, All Uplands Sec: 21 Unsurveyed, All Uplands 390615 T14N., R.9 E., UMIAT MERIDIAN Sec: 28 Protracted, All Sec: 33 Protracted, All 390616 T14N., R.9 E., UMIAT MERIDIAN Sec: 29 Protracted, All Sec: 32 Protracted, All 388571 T14N., R.8 E., UMIAT MERIDIAN Sec: 1 Protracted, All tide and submerged lands Sec: 2 Protracted, All tide and submerged lands within the computed territorial sea, listed as "State Acreage" on Alaska's seaward boundary diagram approved by the State on April 15, 1996 Sec: 11 Protracted, All tide and submerged lands Sec: 12 Protracted, All tide and submerged lands T15N., R.8 E., UMIAT MERIDIAN Sec: 35 Protracted, All tide and submerged lands within the computed territorial sea, listed as "State Acreage" on Alaska's seaward boundary diagram approved by the State on April 15, 1996 Sec: 36 Protracted, All tide and submerged lands within the computed territorial sea, listed as "State Acreage" on Alaska's seaward boundary diagram approved by the State on April 15, 1996 388572 T14N., R.8 E., UMIAT MERIDIAN Sec: 3 Protracted, All tide and submerged lands within the computed territorial sea, listed as "State Acreage" on Alaska's seaward boundary diagram approved by the State on April 15, 1996 Sec: 4 Protracted, All tide and submerged lands within the computed territorial sea, listed as "State Acreage" on Alaska's seaward boundary diagram approved by the State on April 15, 1996 Sec: 9 Protracted, All tide and submerged lands Sec: 10 Protracted, All tide and submerged lands T15N., R.8 E., UMIAT MERIDIAN Sec: 33 Protracted, All tide and submerged lands within the computed territorial sea, listed as "State Acreage" on Alaska's seaward boundary diagram approved by the State on April 15, 1996 388573 T14N., R.8 E., UMIAT MERIDIAN Sec: 5 Protracted, All tide and submerged lands Sec: 6 Protracted, All tide and submerged lands Sec: 7 Protracted, All tide and submerged lands Sec: 8 Protracted, All tide and submerged lands Page 26 of 35 8/17/2010 T15N., R.8 E., UMIAT MERIDIAN Sec: 31 Protracted, All tide and submerged lands within the computed territorial sea, listed as "State Acreage" on Alaska's seaward boundary diagram approved by the State on April 15, 1996 Sec: 32 Protracted, All tide and submerged lands within the computed territorial sea, listed as "State Acreage" on Alaska's seaward boundary diagram approved by the State on April 15, 1996 388574 T14N., R.8 E., UMIAT MERIDIAN Sec: 13 Protracted, All tide and submerged lands Sec: 14 Protracted, All tide and submerged lands Sec: 23 Protracted, All tide and submerged lands 388575 T14N., R.8 E., UMIAT MERIDIAN Sec: 15 Protracted, All tide and submerged lands Sec: 16 Protracted, All tide and submerged lands Sec: 21 Protracted, All tide and submerged lands Sec: 22 Protracted, All tide and submerged lands 388577 TUN., R.8 E., UMIAT MERIDIAN Sec: 26 Protracted, All tide and submerged lands Sec: 35 Protracted, All tide and submerged lands 388578 T14N., R.8 E., UMIAT MERIDIAN Sec: 27 Protracted, All tide and submerged lands Sec: 34 Protracted, All tide and submerged lands 391283 T14N., R.8 E., UMIAT MERIDIAN Segment 2 Sec: 24 Protracted, All Sec: 25 Protracted, All Sec: 36 Protracted, All T14N., R.9 E., UMIAT MERIDIAN Segment 2 Sec: 19 Protracted, All Sec: 30 Protracted, All Sec: 31 Protracted, All Rule 3: Well Spacing The requirements of 20 AAC 25.055 are waived for development wells in the Nikaitchuq Schrader Bluff Oil Pool. Without prior notification, development wells, either injection wells or production wells, may not be completed closer than 500 feet to an external boundary where working interest ownership changes. Rule 4: Drilling and Completion Practices (a) In addition to the requirements of 20 AAC 25.030, the conductor casing must be set at least 80 feet below the surface. (b) To provide proper anchorage for the blowout prevention equipment, surface casing shall be set at the base of the permafrost, and the annulus shall be filled with cement. (c) Injection Well Completion: Injection wells may be completed with a slotted liner in the injection interval provided a sealbore, packer or other isolation device is positioned not over 400 feet MD above the top of the producing or injection interval. (d) A complete petrophysical log suite acceptable to the AOGCC is required from below the conductor to TD for at least one well per drill site in lieu of the requirements of 20 AAC 25.071(a). Rule 5: Automatic Shut -in Equipment (a) All wells must be equipped with a fail -safe automatic surface safety valve system Page 27 of 35 8/17/2010 capable of preventing an uncontrolled flow. (b) All injection wells must be equipped with landing nipple at a depth below permafrost, which is suitable for the future installation of a down hole flow control device. The Commission may require such installation by administrative action. (c) Operation and performance tests must be conducted at intervals and times as prescribed by the Commission to confirm that the safety valve systems are in proper working condition. Rule 6: Reservoir Pressure Monitoring (a) Prior to regular production or injection an initial pressure survey shall be taken on each well except those equipped with a subsurface pump. (b) A minimum of one pressure survey will be taken annually in each reservoir compartment. (c) The reservoir pressure datum will be - 3,760' feet true vertical depth subsea. (d) Pressure surveys may consist of stabilized static pressure measurements (bottom -hole or extrapolated from surface), pressure fall -off tests, pressure build -up tests, multirate tests, drill stem tests, and open -hole formation tests. (e) Data and results from pressure surveys shall be submitted with the annual reservoir surveillance report. All data necessary for analysis of each survey need not be submitted with the report but must be available to the Commission upon request. Rule 7: Well Testing (a) All producing wells must be tested at least once per month. (d) The operator shall submit a monthly report (in printed and electronic form) including well tests and daily allocated production and allocation factors for the Pool. (c) Schlumberger VX multi -phase meters will be used to measure produced oil, gas and water volumes during periodic well testing operations and will be used. Rule 8: Gas -Oil Ratio Exemption Wells producing from the Nikaitchuq Schrader Bluff Pool are exempt from the gas -oil ratio limits of 20 AAC 25.240(a) so long as requirements of 20 AAC 25.240 (b) (1) or (2) are met. Rule 9: Pressure Maintenance Project Waterflood is required for purposes of pressure maintenance and enhanced oil recovery in the Nikaitchuq Schrader Bluff Oil Pool. Production and injection must ensure the average reservoir pressure in each sand lobe or reservoir compartment is maintained at or above the bubble point for that respective sand lobe or reservoir compartment. The pressure maintenance waterflood will be initiated within 1 year of the start of regular production from each drill site. Rule 10: Reservoir Surveillance An annual report must be filed on or before April 1 St of each year. The report must include future development plans, reservoir depletion plans, and surveillance information for the prior calendar year, including: (a) Progress of enhanced recovery project implementation and reservoir management Page 28 of 35 8/17/2010 0 0 summary including results of reservoir studies: (b) Voidage balance by month of produced fluids and injected fluids and cumulative status. (c) Reservoir pressure map at datum, summary and analysis of reservoir pressure surveys within the pool. (d) Results and, where appropriate, analysis of production and injection log surveys, tracer surveys, observation well surveys, and any other special monitoring. By June 1 of each year, the Operator shall schedule and conduct a technical review meeting with the Commission to discuss the report contents and to review items that may require action within the coming year by the Commission. Rule 12: Administrative Action Upon proper application, 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 on sound engineering and geosciences principles, and will not result in an increased risk of fluid movement into fresh water. Page 29 of 35 8/17/2010 Table of Contents • Exhibit 1: Proposed Pool Area — shown in Green Dashed Outline Highlighted in Yellow • Exhibit 2: Type Log with Proposed Pool Correlative Interval • Exhibit 3: North Slope Location Map • Exhibit 6: Current Well Development Area and Pattern and Fault Map • Exhibit 7: Development Scenario Schematic i • Exhibit 8: Strategraphic Column • Exhibit 9: Seismic Survey Outlines shown with Well Pattern and Fault Map • Exhibit 10: Seismic Based Structure - Top of OA Sand • Exhibit 11: Sedimentological Environment Concept & Core Description • Exhibit 12 — Map of Well Data Set for Model • Exhibit 13 - OA Net thickness Base case • Exhibit 14 — N Sand Structure Map with Possible Oil Water Contacts • Exhibit 15 - OA and N Sand Mapped and Prospective Sand Outlines • Exhibit 16 — Deterministic Approach Recovery of Oil and Oil Rate Profile • Exhibit 17 — Well Drilling Field Spider Diagram • Exhibit 18 — Example Well Bore Schematic • Exhibit 19 — Development Plan Map • Exhibit 20 — Oliktok Point Pad (OPP) • Exhibit 21 — Spy Island Drill Site (SID) • Exhibit 22 — Nikaitchuq Operations Center (NOC) i Table of Contents of Confidential Material • Exhibit A — CONFIDENTIAL- kh v Porosity cross plot for High Quality Sand Facies • Exhibit B — CONFIDENTIAL- kh v Porosity cross plot for Laminated Sand Facies • Exhibit C — CONFIDENTIAL East Lobe Isolated Scenario • Exhibit D — CONFIDENTIAL North & East Lobe Connected Scenario • Exhibit E — Confidential OA sand gross thickness: base, high and low case • Exhibit G - CONFIDENTIAL OA and N Sand Well Correlation & Cross Section West — East • Exhibit F — CONFIDENTIAL High and Low Case Net Thickness Maps • Exhibit H - CONFIDENTIAL OA and N Sand Well Correlation & Cross Section South - North • Exhibit I — CONFIDENTIAL Comparison of the Petrel & Eclipse — OOIP • Exhibit J — CONFIDENTIAL Relative Permeability Curves • Exhibit K — Confidential Nikaitchuq MDT Pressures • Exhibit L — CONFIDENTIAL — Eclipse Fluid Regions • Exhibit M — CONFIDENTIAL Horizontal Well Test Results: • Exhibit N — CONFIDENTIAL Production Well Completion Plan • Exhibit O — CONFIDENTIAL Injector with Injection Control • Exhibit P — CONFIDENTIAL Injector with Monitoring and Injection Control i I Exhibit 1: Proposed Pool Area — shown in Green Dashed Outline Highlighted in Yellow W eni petroleum ADL389719 Tract 003 ADL�90433 AD 9720 Eni (100 %) Traci) 001 Tract 002 Eni (100 %) Eni (100% . _T ADL308579 Tract 006 -- ------ +-- -- - - -- Eni (1 %) ADL388571 ADL388581 ADL388580 ADL388573 Tract 011 Tract 004 - Track 005 - Eni (1;00 %) Tract 013 - ADL388572 ----- Eni t"100 %) Eni (100 %) ai ( 100 %) Tract 012 Eni (100%) - AM388583 Tract 007 ADL388574 Eni (100 °7°) Tract 014 _ " -_ = _ _ L388582 - - ADL388575 Eni (100 ° r6) "- - Tract -00g - a -_ -- Tracto95 Eni (1007 °f Eni (100 %) J I - ADL355024 Tract 018 • Eni (100 °1 °) ADL390616 ADL390515 ADL388578 ADL388577 _ _ Tract 4-10 - Tract 009 - Tra,t 017 - -Tract-016 _ _. Eni (100 °k) Eni (100 %) Eni (100°7°) Eni (100 1/6) • a Exhibit 2: Type Log with Proposed Pool Correlative Interval Kim fSSTVD SSTVD 0 GR- PI 1 50.0 0.2 AHF10 200.0 1.65 AK RhoB 2.65 14 . K -DT 4 MD 1:500 0.2 AHF 200.0 0.60 AK NPhi 0.00 — 3500 200 . I - i ;chrader Bluff, 3400 — Schrader Blut 3550 7 m 3450 I 3600 i N Top _ TOP 3500 -, N -2 Z 3650 N Bottom N Bottom 3550 s Inter Marker — — - - -- -- - -- -- —17M Inter Marker T III l0 3600 c 3750 OA Top 3650 OA -1 A Top M Q 3800 O OA -4 OA Bottom A Bottom 3700 3 3850 S rn SB Pool Base — - -� - -- - -- — —� -- SB Pool Base U 3750 3774 3906 PETREL Exhibit 3: North Slope Location Map - - I BEAUFORT I SEA i Nika" chuq I I 4 I - 4 IF I_ 1 _ i i National Petroleum ' •� Reserve Alaska _. e9ettd Nikaftchuq Uni Units I Eni Leasehold 't snn saw Pipelines i Towns Exhibit 4: Historic Lease and Ownership Map (prior to January 1, 2007) ADL389719 j ADL390433 ENI (30) ADL389720 KMC (70) j I ENI (30) ENI (30) KMC (70) KMC (70) , ADL388579 • ENI (30) KMC (70) ADL388573 ! ENI ( 571 ADL388581 ADL388580 ENI (18) KMC (82) ADL388572 KMC (82) ENI (30) ENI (30) KMC (70) KMC (70) ENI (18) KMC (82) i ADL355021 ADL388574 ADL388583 ENI (30) ENI (18) ENI (30) ADL388575 KMC (82) KMC (70) ADL388582 KMC (70) ENI (18) - - - - --- `-- ------ - - - - -- ENI (30) KMC (82) KMC (70) I � i , j ADL355024 ENI (45) KMC (55) • LKMC(82) ADL388577 I ADL390616 ADL390615 - ENI (18) ENI (30) ENI (30) KMC (82) ( KMC (70) KMC (70) I , En! WI% - �- 18 T - l'___ 30 45 Exhibit 5: Base Map as of July 2010 591r�0 now 5 ,.Too a g o w m Nik -01 ° s ° s � 8 Nik -04 Tuvaaq Nik -02 n s KR sland 1 NW -Milne 1 KR F-92 6 Kigun KR F 8 KR F54 K -42 KR -38 KR F-90 R m OPO4 -07 -- F410 P8 F� 1 KR F- 8 R F. R F -70 KR F-9 OP03 -P05 KR F-79 K 10 F4 KR F -18 OP -12 OP08 -04 K -9P81 KR a J R OGRK -1 OP23 WWO2 F�8 KR F-85 F 2 g . F-08 KR 1 KR 5 026 -DS 2 OP -I KR L-2 KR .. O 2 PB -01 afktok P1. sr �• F -0 _1 P -14 K R F-09 KR 1 Eni Oliktok Point KRU 3R -10 KR F-63 o 8 RU 3R -10 A KRU -15 F -05 Ii o oint 2 A KR F KR U 3 Q - NRU 3R -18 12 A 8 KR . K EHB St 1 KR - Nikaftchu Field - Schrader Bluff Deveb ment 0 0 2000 40006000 6000 �10000ft weoaa wzaoa waoaa s00000 s,s000 -wo mm w• �• KRU 3R Milne =Point mw,z I D _ 1:40000 �� Exhibit 6: Current Well Development Area and Pattern and Fault Map 490000 4e4000 499000 462000 460000 500000 504000 We= 512000 510000 520000 524000 528000 532000 QQ .6 t� �R! 8P i S '8 SP 6I-NS' pp . .iP, fs k.01 8 04 SP's: S1. N2 N T—v SC fil . SI SI \ 1 o tMlis Mar,4 i S4. Fs `1W r F �f. Weflbme Location fsEC - 4 Styr Is1a1M ONktok PONH E r. 4SE Via. CR.. of j Plodecets 16 10 2F 0103 ^� 1� E 01o5 SE'S 81-S2 14 ., Injectol 13 8 21 8 Sa} � ppp n n, 778b Service 2 4 1 Ois sal t Junk 1 as Sal 3 VM Total 31 22 S 40 26.0=. a „ O 12 PB ::EeaT ftA2 acre mileA2 kmA2 i OA Drainage 2009 513,034,000 11778 18.40 47.66 t kPa 490000 48+000 48860 462000 40600 W0000 5040W 508000 512000 515000 520000 524000 528000 532000 Nikaitchuq 2009 Proposed Optimized Well Pattern 0 1000 y 145000 PrfMt Note: Horizontal Producer drain holes are shown in Green. Horizontal Injector drain holes are shown in Blue. Exhibit 7: Development Scenario Schematic Offshore i ♦ ti� Onshore ♦ , drillsite ♦ I d ♦ I C ♦ U1 :` M ♦ Process facility Coastlin C1 / C I c W Sales oil O perations -� 3 -phase produced fluids camp Water injection 3� �♦. Fuel gas t0� Diesel Power & Fibre -optic cable To Kuparuk Pipeline & TAPS 0 Exhibit 8: Strategraphic Column Exhibit 9: Seismic Survey Outlines shown with Well Pattern and Fault Map 472000 47E000 48]000 464000 488070 492000 496000 500000 5]4000 50 512]00 5100 5 524000 528000 532000 555000 540000 344000 548000 55:000 . ...i.. .. �... .�.. .i ... i....i... �. .. �. ...i... i... �. .. ..i..�. �. ...i. .. �.. ....�... .8000 .. �.... .i... 60 ...i... �.. .� ....i. ...i.. �. ...� i.... �. ................. ......... i.......... `c m Thetis Island s �� a Simpson �__— . / �. 1 .1•F Lagoon 3D r � u _ —4, P- I Trietis.land I Z � c rP \ r C p. z r Nikaitchuq n 3D PGS 2008 4 472000 47E000 48]000 484000 488030 492000 496000 500000 534000 MOO 512300 516000 5I= 524000 528000 53'e000 533000 540000 544000 548000 552000 Nikaitchuq Development 6 � Soo` c ,00o` W 1:70000 Exhibit 10: Seismic Based Structure - Top of OA Sand Demo OTT .ewm .main aurae iamoo winos so'000 mmm s,am s +moo an® sz.000 stems s3xoo srmaa Nik -01 Nik -04 �� Niic�p2 sland 1 L— �VV- Miln? 1 F 1 �F -90 P9i `E F � Q4 -0 `tw. a .H F SU � �Q3 P05E VP F.79 -04 Ftk -F -79 P6/ F � w0 OGRK -1 KP 1.R OP -1 / R L T< P 01 rkmo- c. n / F oY kR a F-W KRU 3P40 KR F-83 RU 3R 10A KRU 15 F -U5 li o oint 2 A KR F U 30 %RU 3R -18 - 12 A EHB St 1 IOR , • .eeom .samo .seam sssoos eaoos soeom s,amo scour szs000 u,000 s�mm s+moo sxmo e+ooao Nlkaltchu Held - Schrader Bluff Develo ment 0 2000 4000 8000 8000 10000R sc,w san e.,e.. coMOw;z n.x 1'40000 Exhibit 11: Sedimentological Environment Concept & Core Description NIKAITCHUQ 4 4.3 Km -- - I ' KIGUN 1 - _ atzs - . - . O tar ----- = a 135 ;: • y -; 3780 ., 4140 Shelfal Lobe ,37" _ _ 4145 _ -_: 379t} - �• —¢lit! Shelfal Lobe t 379 � F I.. f - f 3000 ..._ n x 4160 _ ss y . .....i Shelfal Lobe Y • i 3805 V 416S _.v� _ - _ i .�._ - °� ... :: ta _t Pradet# ..,� t t- - 41 _ 7s ._.... V.S.: lcm:4' - - --_-- _ - - - - - H.S.: 1':20000' - V.E.: ? Mudstone (massive & /or laminated) ❑ Sandstone F & VF grained (massive & /or laminated) ® Siltstone & Mudstone (high hioturbation) F-1 Sandstone M & F grained with clast trains Exhibit 12 — Map of Well Data Set for Model 469000 470000 475003 487000 485000 480000 485000 500000 503000 510000 515000 E20000 525000 530000 535000 540030 545000 55000[ 555000 i I i i I i I o I ! m I I I I 1 I I ' Ni k -04 � I T—" Ni k -02 m � n��is IslaN • � NW MArn ( ! O a , ' O h m OP03- ° o GGRK1 SP02 ! j k • O 03-P05 PB1 Ildek P!3 e .... .FHB St1 ._�.... MP-PR L7 • O 03� P05 KR03 Ilk OP26 -DSP02 1 , 465000 47 0000 475000 487000 465000 480[00 405000 500000 509000 510000 516000 :20000 525000 530000 536000 540070 546000 550000 555000 Nikaitchuq 2009 Well Dataset o 5000 10000 160°° 200°° 2500M 1:60000 i I I Exhibit 13 - OA Net thickness Base case 0 470000 480000 400000 500000 510000 520000 540000 ° o ickness \ °' o \ \ °o m \o 44 38 32 c 28 r o � r 24 20 \ o Ni 888 I Tuva 2 Ni M Spy Is nd 4is Island 1 ❑ 11 i - Ine 1 3- 05 OP -12 i OP P. L i EHB 1 / M ° �1 - 8 470000 480 400000 50000n 510000 520000 530000 540000 o 2000 4000 e000 e000x Nikaitchuq 2009 OA Thickness BC ,:85000 r PfTMRI DqAh _ Top N Sand - WUT @ -3949 ADD !, O ETI 1 ND_ t 9 t` ! 9� 0006URUN 1 Ytl Ytl Op - P I aM_ 'nt }1 8 !F R•RR. R P X\ _....- ! I�nhlRq FW° 1 1N/! °a11 ®— ® ® — ®— Exhibit 14 — N Sand Structure Map with Possible .� ®� ® ®� t Oil Water Contacts ! \ dRDD li NI ITC _<( N ! O Etl of ND_ T -- ! R HWE OOOOURUN 1 ! alLPOln _� \ ! nm as �® .® ® ® e® n � � - -�� +•� rm Top N Sand - ODT @ -3643 Exhibit 15 - OA and N Sand Mapped and Prospective Sand Outlines areaoo to 00 4e400a 4eeaoo 4.T. s�eaoo sze000 —0oo stn ...iii ..• $ „ r ....... ..............................° Prospective OA E . ...... ............................... .. .. .. Prospective N Nik -01 Nik -04 Tuvaaq Nik -02 a kT KR Stand I KR F92 Kigun NW -Mir1e 1 KR F. KR F-54 K <2 KR 38 e KR FAO R m $ OPO4 -07 FAO PB1 KR F- F30 ° g R F- KR F9 R F -70 OP03 -P05 K -10 KR F -79 Fd K -79 PB7 KR F -18 R OP -12 OP08 -04 KR 3 � � � • OP23 WWO F 2 OGRK -1 KR FAS F� F -08 KR 1 KR 5 Mapped OA 026 -DS 2 Mapped N 0 2 PB-01 OP KR L-2 FAQ KR $ Qliktok Pt. 5 P -14 K F R F -09 .. KR 1 a KRU 3R -10 KR F33 � RU 3R -10 A KRU -15 R F -05 li o oint 2 A KR KR U 3 Q -0 'kRU 3R -18 12 A ° o KR K i EHB St 1 KR 4aeaao sooa00 sa0o0 12..Oa 124w 12— szz00a 1-00 040000 Nikahchu Field - Schrader Bluff Development 4e2000 4ae000 0 400a 2000 4000 00 8000 8000 00 10000t co,rcou, mo o.re 1:40000 I Exhibit 16 — Deterministic Approach Recovery of Oil and Oil Rate Profile Nikaitchuq 2009 Reservoir Model Field Oil Rate and Cum Oil @ 30 Years 40,000 Cumulative Oil: 180 million STB 200 Recovery Factor: 21 % 180 35,000 • 160 0 00 30,000 I' 4 0000 140 m 00 N .2 in 25,000 c ,,. 120 c O 20,000 100 >' > o / 80 4 ) 15,000 60 V Q 10,000 • 40 5,000 20 10001* 0 0 2010 2015 2020 2025 2030 2035 2040 2045 Year Daily Oil Rate — Cum Oil i 0 • Exhibit 17 — Well Drilling Field Spider Diagram 1 � �i l I 1 I 1 4 i • 0 Exhibit 18 — Example Well Bore Schematic En! Petroleum Schrader Bluff Nikaitchuq Field CSG Profile North Slope - Alaska DIR I LWD FORM DEPTH HOLE CASING MUD INFO MWD MD TVD SIZE SPECS INFO Cement to Surface = =- 20" 20" Conductor Shoe 120' 120' WA Welded / Driven N/A MWD /GR/RES =- _— Surface Csg 13 -3/8" Top of Permafrost 0' 0' 68 Ibs /ft Wellbore Stability L -80, BTC +/ 10.0 ppg Lost Circulation - nn KOP.180 450' - - Hole Cleaning g DLS: -- 2 -4 de /100' - 9 - Sail Angles: 30 -70 Base Permafrost +/ -1950 +/ -1860 Top of Tail Cement 13 -318" Casing Point +/ -2900 +/ -2100 16" 50" F WBM MWD /GR/ RES /A PVVD Inter. Casing Wellbore Stability Rotary Steerables 9 -5/8" Lost Circulation IIFR/Cas 47 Ibs /ft +/ -9.0 ppg Hole Cleaning L -80, BTC-M Torque & Drag Sail Angles: PM 50 -80 degrees Top of Cement +/ -8500 WBM 9 -518" Casing Point 9,000' 3,825' 90° 12 -1/4" 85" F MWD /GR/ RES /APWD I I Wellbore Stability Lost Circulation Schrader Bluff Slotted Liner Hole Cleaning Lateral 1 90° 1 5 -1/2" Torque & Drag 1 I 17 Ibs /ft +/ -9.0 ppg Horizontal L -80, DWG drain I I r ydm szt 1 I 1 90o Rotary Steerable 1 (Geo- Steering) I I I I I 1 I 1 I I Proposed TD 17,000' 3,825' 1 90" I 8 -1/2" 85° F SBM Exhibit 19 — Development Plan Map Development Plan Gravel- - = _ Offshore Island Isl • One gravel pad initially a Eti v • Water depth N6 feet • Accommodate barge access "$"` "° ; �.- - • Flowlin tO o� r • - a e Bundle i •• - 3.1 -mile buried flowline r till bundle • Pipe -in -Pipe Production / �,� �I , ;_~` . I " :� �� ¢°• - ° 4 WI / Pipe -in -Pipe Diesel Gas •- -- ,. , . ,. �- .. ,. • -- � .. • Power & comms cable Oliktok Point -- r - r- . • r ,.. Production Pad - • Process 3 phase flow Export Line ;t� • 14 -mile export line to • ... o. ` . F .r`!'„ .rte f h '-` L� Kuparuk Pipeline on new ' °`` -` " " '''�� lee N VSMs (10 line pipe •-, ,:. c r L °� _- already purchased) ,...,..+ ,: � -- --_ i � i 1 \:. _, 1 +,�� fL r•st�.r'� 1l�`ti' r- I _ Exhibit 20 — Oliktok Point Pad (OPP) OPP ENSIBLD CONCRETE I P�JN4T PLA MATS ON SLOPE I NO A ,, FLOINNE �� SR PAD 4I �`k SEAFLOUR PR....N Pam AND I WINOS CABLE ROUTE ( J IS RVE MR 1 I r FAN AfTW SEE TAYK FARM K EDULE I I I IN CRA10M FOR TNNI I + MERIP 1MM AND YOLUYES I WELL OWN LRY OMM AS 9i09N OY LO�RJSB ORA9NIG, _ 20 WIDE — R OADWAY — — — _ — I I STATE PLANE am MAD U EK4 EA97N6 1,e50`714,7IN! P€ — T + + I t es�ae• •aeeea •eee III 3: I \ �AUA `TOP O F PAD ELEVA71d1 12.0 BPNSL ARFJL TOP OF PAD 315NO 50. FT. NEIL CODRD NX-4. A9 SHUN 7.24 ACRES I ON LOOIS ORAfXR N9t�.01 -01986 OPUS M TALE E PL ANE I OPUS MAD 87, ENE 4 FUTURE REQUIRED 'I Vi } I DISPOSAL OWN m1E OF RD40 y I I O I NOi1H IC OAM,SR,B7 EASIM76 1,67Q,AIBO' $ I I x I w PU NT COORDS. *491.00 E -88600 W. +fly HATCHING IIEfNOTE 69' /60�/WI o o I ��t:L/I11 F I� I S:AilA PIPELINE R OUTE HIM COORDOIAIE I I A S s+ 11 ON Riwe E J I ' ALA9G STATE RAff MAR ed zaps 4 e xQenixa q¢is,aec.oC Eesnre; f,esr,,s7D.R� � O + fa I i 5 1 J 27 PLANT CDOM N. C -C E. 7 -O' yf 6 H a fe CPUS ME 93 00011. ,qO L N. 447471117 LAT. 7a 3D 32.0 E F - 1 E. 1.097%4479' LaNR 144 52 07.4 J , 0 0 A e Ra is 0 Z APPRi2RAATE LOI9INWL , OF ULNE11CNa1910 - - PLND1 PIPELINE I I �j SEE TANK FAN 3[Nmu , THIN Dung MR 1ANN DROLPTIM AND YCLUNLS I L 50 0 50 100 OLIKTOK POINT SITE PLAN 4 Scale: 1 Inch = 50 Feet SID Exhibit 21 — Spy Island Drill Site (SID) PLANT NORTH PR; MILIN INOS W 11' e1o• -v / t6 BaNt71 � E 6T%65G 53 aLO Rt.✓'NtFRN a:1 yt NO MO. LAN7EI¢F E07 VV j GSNIDS70MOEAREA -WWW m%q V- \ 1/ 1t f t • 1 art 4 7 VCS -a$ Y t 172 VCS-Ol PL 31% L in 1 / \ h Mt. PL.— AL¢im S 13PUt / ; hb -t NAO 03. A SPUR NAB 11a, ¢m 4 e3, 2 4 / / NoPShMg 609330833DO3 8 NeVLhhg 6693A @118 F — — 'firs] Spn"33 TOPCRPAD0AK1!VA8CN1W6V- Easift 7671769 � / TFMSITDN j scow► I M SLOPE k— AM NO BENCH TOE OF I $1 BLOM I i Al SAFE �I IeI at co 1 I ES IT CAMS MAY D1P01 0=3 S I � I g U1E04 mm ® ®O I To or D7EOR b I (I1 O�w I ah�aorf 13 00000U c o o a�DS OQLroa 02M ® 1 ,AOfP9aRAMP I 07L7D8 ) ® I r1 3&R4 0013 ®®®® i ll 30 I unum7S ar I I : I A 6016D smmoL�L2St") AMCTOS / ,11 • I - amw7uENWfN9AY- E- id919B11D TOP Or SLOPE � afl an / t A Ar J/ i -------- R190' -0� TTP ---- -- ----- --— ^'^ IN FER SEE IN KA L EC LB:EIL i \ 1QT�_1� / tGE OFaLAPP SEE WEGH DVG.B \\ � 71H.6DDl- S7D-DRk- DO -SeeM - 2RtipS1E l00Mi'MY- / + N-60SeB61.99 / E- 1651L776Y\ 1 ®IgE11#+ f/ / Rt�_y NOTES. 3A' TRMdSRIDN 10 1. COORDOIATES S ARE ALASKA STATE BEN ��`- - - - - -- - - - -- '�'� NO CH SLOPE S PLANE, O PUS 15 SH N ARE D 83 DATUM BASED " ON A FMN PAD ELEMION OF 100'. 3. ELEVATIONS LISTED BI THE NODDLE /PIATFON TABLE ARE AT THE TOP OF STROCfURE fiD 0 60 120 �f RAND SITE PLAN UNLESS NOMD O"ERMASE, Sc61x 1 Inch = 60 Feet Exhibit 22 — Nikaitchuq Operations Center (NOC) SMUS (TOP OF GRAVEL PAD) —EMST GRAVEL PAD LEASE BOUNDARY (751.45') AWUNIMS 3SV3 FUTURE GEN. 71 FUTURE COMM SLOG, FUTURE COOL TOWER BLDG CS 002 i STORAGE SUILOM L SNOW S M STORAGE FUTURE FUEL TANKS AREA 22 PARKING AND DISPENSING SPACESvd STATION BULL RAIL EFFLUENT DISCMAR GE i i 7 VATERTWwER . ......... 7TT 114CMIERATOR FUTURE OPEN STORAGE AREA VIAI I AM SNOW STORAG AREA UT,UOOP3 FUTURE WARM --_.__ ! FUTURE SECURE AVM A TORAGE BUILDING STORAGE AREA - A ll 9 FUTURE "EUPAD SVAPORM Q .- LEASE BOUNDARY (762 AbVaN .937 me 3SV31 E? I? LU P - L"IG SITE 1 '. 50'-0" PLAN �L Pages 30 -35 and Exhibits A -P Held Confidential