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Home My WebLink AboutCO 719INDEX CONSERVATION ORDER NO. 719 Pt Thomson Unit 1. July 16, 2015 Exxon’s application for Pt Thomson Pool Rules (confidential appendix held in secure storage) 2. July 20, 2015 Notice of Public Hearing, Affidavit of Publication, Email list, bulk mail list 3. July 23, 2015 (Revised) Notice of Public Hearing, Affidavit of Publication, Email list, bulk mail list 4. September 1, 2015 Hearing transcript, hearing sign in sheet, presentation 5. September 8, 2015 Exxon post hearing submission 6. April 9, 2021 Letter of Intent to provide an IPS Findings Report for Point Thomson Unit 7. April 12, 2021 Emails between Exxon and AOGCC INDEX CONSERVATION ORDER NO. 719 ORDERS • • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue Anchorage Alaska 99501 Re: THE APPLICATION OF ExxonMobil Alaska Production Inc. for an order for classification of a new oil pool and to prescribe pool rules for development of the Thomson Oil Pool within the Pt. Thomson Field, Pt. Thomson Unit, East Harrison Bay, Beaufort Sea, Alaska IT APPEARING THAT: Docket Number: CO-15-008 Conservation Order No. 719 Corrected Point Thomson Field Point Thomson Unit Thomson Oil Pool November 9, 2015 1. By application received July 16, 2015, ExxonMobil Alaska Production Inc. (ExxonMobil), as operator of the Point Thomson Unit (PTU) and on behalf of ExxonMobil, BP Exploration (Alaska) Inc., ConocoPhillips Alaska, Inc., and 21 other owners having a total combined working interest of less than 1 percent, requested an order defining a new oil pool, the Point Thomson -Thomson Oil Pool (Thomson Oil Pool), within the PTU and prescribing rules governing the development and operation of that pool, including an annual average allowable gas-offtake rate of 1.1 billion standard cubic feet per day (BSCFD). 2. Pursuant to 20 AAC 25.540, the Alaska Oil and Gas Conservation Commission (AOGCC) scheduled a public hearing for September 1, 2015. On July 20, 2015, the AOGCC published notice of that hearing on the State of Alaska's Online Public Notice website and on the AOGCC's website, electronically transmitted the notice to all persons on the AOGCC's email distribution list, and mailed printed copies of the Notice of Public Hearing to all persons on the AOGCC's mailing distribution list. On July 21, 2015, the notice was published in the ALASKA DISPATCH NEWS. 3. On July 23, 2015, the AOGCC published notice of that the location of the hearing had changed on the State of Alaska's Online Public Notice website and on the AOGCC's website, electronically transmitted the notice to all persons on the AOGCC's email distribution list, and mailed printed copies of the Notice of Public Hearing to all persons on the AOGCC's mailing distribution list. On July 24, 2015, the notice was published in the ALASKA DISPATCH NEWS. 4. No comments on the application were received. The hearing commenced at 9:00 AM on September 1, 2015, in the Alaska State Legislature Building, Legislative Information Office located at 716 West 4th Avenue, Anchorage, Alaska. 6. Testimony was received from representatives of ExxonMobil. 7. The record was held open until September 8, 2015, to allow the operator to respond to requests made during the hearing. Conservation Order No. 719 Corrected • November 9, 2015 Page 2 of 14 8. The AOGCC received the requested additional information from ExxonMobil on September 8, 2015, and the record was closed. FINDINGS: 1. Operator and Owners: ExxonMobil is the operator of the leases in the portion of the PTU that is currently proposed for development. ExxonMobil, BP Exploration (Alaska) Inc., ConocoPhillips Alaska, Inc., and 21 other partners are working interest owners, and the State of Alaska, Department of Natural Resources (DNR) is the landowner of the Affected Area, which is located within the North Slope Borough, approximately 50 miles east of Prudhoe Bay along Alaska's northern coastline. 2. Affected Area: The proposed Thomson Oil Pool, which underlies state lands onshore and state waters offshore, is shown on Figure 1, below.' This pool will be developed initially from the onshore Central Pad drill site (Central Pad), which is located in Section 34, Township ION, Range 23E, Umiat Meridian (UM). ExxonMobil's development plans include construction of a second onshore gravel drill site (termed the "West Pad") in Section 36, Township ION, Range 22E, UM, and likely a third onshore gravel drill site (termed the "East Pad") that is currently planned for Section 6 or 7 of Township 9N, Range 24E, UM. Beaufort Sea i�Tu a �"� pru fast ALASKA ST C 1 Ptd .....f W STAINES ST 18-09 ESE .......... . :....... . ¢ 4EKi.:,, " W STAINES ST Existing IPS Wells - BHL p Scheduled IPS Gas Production Well - BHL Q Tentative Gas Expansion Production Wells - BHL 0 3 Miles STAINES RIV ST 1A ANWR SOURDOUGH 3 SOURDOUGH 2 Figure 1. Affected Area, Proposed Thomson Oil Pool (The approximate outline of the Affected Area is indicated by the blue line.' Confidential wells are shown in red.) I This map is presented for illustration purposes only. For a more precise depiction of the Affected Area, refer to the legal description presented on pages 9, 10, and 11 of this order. Conservation Order No. 719 Corrected November 9, 2015 Page 3 of 14 Figure 2. PTU No. 15 – Type Well Log for Thomson Oil Pool2 2 Figure 2 is for illustration purposes only. Refer to the well log measurements recorded in exploratory well PTU No. 15 for the precise representation of the proposed Thomson Oil Pool. The horizontal grid lines in this figure represent increments of ten feet measured depth. The acronym TVDSS refers to true vertical depth subsea (true vertical depth below sea level). Measured Depth TVDSS Thomson Sand Oil Pool Hue / HRZ Shale Basement Canning Formation Conservation Order No. 719 CAed 0 November 9, 2015 Page 4 of 14 3. Exploration and Delineation History: The PTU No. 1 well discovered the Thomson Sand reservoir in 1977. Since that time, 17 additional wells have penetrated the reservoir or its equivalent subsurface horizon within the PTU area.3 Information from these wells and from seven overlapping seismic surveys was used to determine the geologic structure, reservoir distribution, and the area that will be affected by condensate -gas production and re- injection of residual produced gas. Production test, drill -stem test, down -hole sampling, core, and well log data were used to establish reservoir properties, fluid properties, and gas - oil and oil -water contacts for this proposed pool. 4. Pool Identification: The proposed Thomson Oil Pool is the accumulation of hydrocarbons underlying the Affected Area that is common to, and correlates with, the interval between 16,126 and 16,377 feet measured depth (MD), which is equivalent to-12,614 and -12,828 feet true vertical depth below mean sea level (also termed true vertical depth subsea and represented herein by the acronym TVDSS4) on the VISION/ScopeTM Measured Depth Log recorded in well PTU No. 15. 5. Pool Classification: Well tests conducted on the Thomson Sand reservoir in PTU-area wells yielded gas -oil ratio (GOR) values that rant/ from about 850 to 15,750 standard cubic feet of gas per stock tank barrel of oil (scf/stb). ExxonMobil's testimony stated that the initial producing GOR for PTU gas expansion project wells is expected to be less than 20,000 scf/stb. GOR values less than 100,000 scf/stb oblige the AOGCC to classify wells producing from the Thomson Sand as oil wells.6 Accordingly, the AOGCC classifies the hydrocarbon accumulation within the Thomson Sand reservoir as an oil pool. 6. Geology: (a) Stratig_raphy: The Thomson Oil Pool encompasses the early Cretaceous -aged Thomson Sand, which lies unconformably atop pre -Mississippian -aged basement rocks comprising dolomite, argillite, quartzite, and phyllite. Fractured and/or karsted dolomite appears restricted to the northern part of the field, and this rock may serve as a secondary reservoir in communication with the Thomson Sand. The rocks that underlay the Affected Area for this order are expected to be predominantly phyllite and quartzite. The sediments that comprise the Thomson Sand reservoir were derived from basement rocks that were exposed in the northern and northeastern portions of the Point Thomson Field and bordered to the southwest by a sea. Eroded sediments were transported down -gradient toward the southwest and progressively deposited in alluvial fan, fan -delta, and marine shoreface environments. Wave and current activity extensively reworked these sediments and distributed them in southeast -trending bands arranged subparallel to the shoreline. From northeast (proximal) to southwest (distal), these bands generally consist of alluvial fan breccia, conglomerate, conglomerate with 3 Twenty-two wells have been drilled in and near the PTU. Of those 22 wells, 18 penetrated the Thomson Sand or equivalent horizon. Of those 18 wells, 16 penetrated the Thomson Sand, which is absent in the remaining two wells because of erosion. 4 To avoid confusion, when depths presented represent true vertical depth subsea, the footage will be preceded by a minus sign and followed by the acronym TVDSS (e.g., 12,000 feet true vertical subsea will be depicted as -12,000 feet TVDSS). 5 AOGCC, 1984, Statistical Report, Reservoir Data for Wells Alaska State A-1 and Pt. Thomson Unit No. 1, p. 103; PTU 15 Well History File 209-014, p. 275; PTU 16 Well History File 209-015, p. 195. 6 Regulation 20 AAC 25.990(45): 'oil well' means a well that produces predominantly oil at a gas -oil ratio of 100,000 scf/stb or lower, unless on a pool -by -pool basis the AOGCC establishes another ratio. Conservation Order No. 719 Aed November 9, 2015 Page 5 of 14 minor sandstone, sandstone, silty sandstone, and siltstone. In general, coarser -grained, proximal lithologies are dominated by carbonate clasts, with quartz and ductile grains becoming increasingly prominent in the more distal areas that lie to the southwest. ExxonMobil informally divides the Thomson Sand into an upper member and a lower member based on core descriptions and well log correlations. The lower member is dominantly progradational, whereas the upper member is dominantly retrogradational. The Thomson Sand is unconformably overlain by siltstone, mudstone, and shale assigned to the Canning Formation, Hue Shale, and HRZ, in descending stratigraphic order. Erosion thinned the Hue and HRZ shale intervals toward the northeast, and completely removed these intervals from the northern and eastern portions of the PTU. (b) Structure: The structure of the proposed Thomson Oil Pool is a gently dipping, four- way anticlinal closure. Based on well and 3D-seismic control, the top of the pool lies about-12,500 feet TVDSS, and the structure extends to a depth of about-14,500 feet TVDSS within the PTU area. (c) Faults: The Thomson anticlinal closure is cut by several, north- and north -northeast - trending, normal faults. The vertical displacement of faults observed within the Thomson Sand interval averages about 65 to 95 feet, with a maximum of about 200', but none of these faults appear to completely displace the Thomson Sand or create isolated compartments within it. None of the faults are expected to act as flow barriers. (d) Trap Configuration and Seals: Well log and seismic information indicate that hydrocarbon distribution within the proposed Thomson Oil Pool is influenced by both structural and stratigraphic elements. A broad, east -southeast -trending anticlinal closure provides primary control for the accumulation. Internal facies changes within the Thomson Sand interval strongly influence reservoir quality and the distribution of hydrocarbons, especially in the southern and western portions of the PTU. The Thomson Sand is overlain by a thick, laterally extensive section of siltstone, mudstone, and shale assigned, in descending stratigraphic order, to the Canning Formation, Hue Shale, and HRZ Shale. These intervals provide the top seal for the proposed Thomson Oil Pool. In the northern and northeastern parts of the PTU, where the Hue and HRZ intervals are either absent or are very thin, mudstone and siltstone assigned to the lower Canning Formation provides a top seal. The Thomson Sand is underlain predominantly by thick Pre -Mississippian -aged dolomite, phyllite, and quartzite basement rocks that are fractured in part and may provide some contribution to production. (e) Reservoir Compartmentalization: Flow tests and reservoir pressure measurements indicate that the Thomson Oil Pool is not separated into isolated compartments within the Affected Area. (f) Permafrost Base: Permafrost base is about -1,800 feet TVDSS within the Affected Area. 7. Reservoir Properties: ExxonMobil informally subdivides the Thomson Sand reservoir into six petrofacies based on grain size, sorting, cementation, and ductile -grain content. These petrofacies are: cemented breccia and conglomerate, open -framework conglomerate, Conservation Order No. 719 Aed November 9, 2015 Page 6 of 14 bimodal conglomerate, clean sandstone, silty sandstone, and siltstone. Each of these petrofacies plots within a well-defined area on a chart of core porosity versus core permeability, and —for reservoir modeling purposes —each petrofacies has a distinct equation that is used to transform porosity measurements to estimated permeability values. Petrofacies Porosity Permeability' Average Sw in Reservoir Gas Cgp Quality to Open Framework Conglomerate Up t 100+ mD 5% Excellent 2 to 10+ D Bi-Modal Conglomerate ^-14% 1 mD to 10 D 25% Good Conglomerate & Breccia — < 8% < 0.1 mD 90% Poor Cemented (CaCO3 > 10%) Sandstone — Clean 100+ mD �24% 15% Very good (generally <10% ductile grains) to < 10 D Sandstone — Silty —12% < 10 mD 70% Poor (generally > 15% ductile grains) Siltstone - < 10 mD 70% Poor Pre -Miss. Basement _1% H: 1 mD; - Poor V: 78 mD8 8. Reservoir Fluid Properties: Within the Point Thomson Field, the accumulation within the Thomson Sand comprises a nearly 500-foot thick, high-pressure, condensate -gas "cap" (gas cap) and an underlying, 37-foot thick rim of viscous oil.9 Relict oil saturation exists within the gas cap due to multiple oil migration events. Relict oil saturation increases downward, toward the gas -oil contact. Average oil saturation within the gas cap is approximately 10%. Condensate yield for the reservoir is estimated to be about 60 to 65 stock tank barrels (stb) per 1 million standard cubic feet of gas (MMSCF). The oil rim consists of 10' to 18' API gravity oil that has a viscosity of about two centipoise at reservoir conditions. The lower portion of the oil rim consists of an oil -water transition zone, where both oil and water are partially mobile. 9. Reservoir Fluid Contacts: For the proposed Thomson Oil Pool, the gas -oil contact is placed at—12,975 feet TVDSS from drill stem test results, Modular Dynamic Tests, and fluid samples from wells PTU 15 and PTU 16. The oil -water contact is estimated at—13,012 feet TVDSS based on fluid samples from PTU 16 and confidential well tests and well log data.lo The elevations of these contacts are believed to be constant throughout the Affected Area, and the entire hydrocarbon accumulation is considered to be in pressure communication. In 7 The abbreviation mD signifies millidarcies, and D signifies Darcies. Permeability values provided in this table represent air permeability. a Based on core analyses, ExxonMobil assigns these general reservoir properties to fractured Pre -Mississippian basement rocks: 1% porosity, 1mD horizontal permeability, and 78 mD vertical permeability. 9 Estimated from MDT pressure and fluid samples obtained in well PTU 16 supported by additional data from confidential wells 10 Records for several exploratory wells located in the eastern portion of the Point Thomson area are held confidential indefinitely because of their close proximity to unleased acreage in the Arctic National Wildlife Refuge. Conservation Order No. 719 Csed November 9, 2015 Page 7 of 14 shallower portions of the proposed pool, condensate -gas -bearing Thomson Sand directly overlies fractured, Pre -Mississippian basement rock. 10. Reservoir Pressure and Temperature: The proposed Thomson Oil Pool is abnormally geo- pressured: average reservoir pressure is about 10,100 psi at ExxonMobil's specified pressure datum of-12,700 feet TVDSS (a pore -pressure gradient of about 0.795 psi/ft).11 Reservoir temperature ranges from about 220' to 230' F. 11. In -Place Volumes: ExxonMobil's geologic and reservoir model suggests that the original gas in place for the PTU is about 8 trillion cubic feet (TCF). The 37-foot thick, viscous -oil rim is estimated to contain about 160 million barrels of original oil in place. 12. Proposed Gas Offtake Rate: The PTU Working Interest Owners (WIOs) requested an annual average allowable gas offtake rate of 1.1 BSCFD for input to the Alaska Liquefied Natural Gas (AKLNG) project and to fuel PTU operations. 13. Alternative Development Plans Considered: At the hearing, ExxonMobil presented evidence as to how the reservoir simulation model was built and showed simulation results for its proposal and several other development options including alternative offtake rates and various cases involving full field gas cycling ahead of major gas sales. The results showed that ultimate recovery from the Thomson Oil Pool was relatively insensitive to the development method and that the differences were arguably within the margin of error of the simulation model based on the current understanding of the reservoir. 14. Reservoir Development and Management: ExxonMobil proposes to develop the Thomson Oil Pool initially as a limited gas -cycling project, known as the Initial Production System (IPS), in order to gain information about condensate yield and reservoir connectivity. Gas will be produced at the rate of about 200 MMSCFD, and it will be routed to the Central Processing Facility, where up to 10,000 barrels of condensate per day will be extracted for sales. Some of the residual, produced gas will be used to fuel the PTU facilities, and the remainder will be injected back into the Thomson Sand reservoir to maintain pressure and conserve resources. This portion of the project is expected to begin production in early 2016. Beginning in or about 2025 ExxonMobil and the other WIOs expect to have the opportunity to start selling gas from the Thomson Oil Pool as part of the AKLNG project currently being planned. When major gas sales begin, the IPS wells will be converted to gas producers and additional production wells will be drilled in order to give the Thomson Oil Pool the capacity to meet the requested 1.1 BSCFD gas offtake rate. ExxonMobil currently has no plans to develop the oil rim. Achieving significant oil production from this 37-foot thick interval would be difficult —even using horizontal drilling technology —because the high viscosity oil contained within this relatively thin interval would initially yield only minimal oil production followed rapidly by breakthrough of overlying gas, underlying water, or both. Ultimate oil recovery would be very low, and separate facilities would be required to process the viscous oil. 15. Gas -Oil Ratio Limit Waiver: ExxonMobil requests a waiver from the gas -oil ration limits of 20 AAC 25.240(a) for the development wells in the Thomson Oil Pool. 11 Regulation 20 AAC 25.990(2): "abnormally geo-pressured strata" means subsurface zones where the pore pressure exceeds a gradient of 0.50 psi/ft. Conservation Order No. 719 Csed November 9, 2015 Page 8 of 14 CONCLUSIONS: Pool Rules for the development of the Thomson Oil Pool in the PTU are appropriate. 2. Per 20 AAC 25.990(45), the hydrocarbon accumulation within Thomson Sand is properly classified as an oil pool. 3. ExxonMobil's IPS project will provide reservoir pressure and condensate yield information that will promote more effective resource recovery. 4. During the IPS project, re -injection of residual produced gas into the Thomson Oil Pool will preserve reservoir energy and increase ultimate recovery. 5. Significant oil production from the 37-foot thick, viscous -oil rim that lies at the base of the proposed pool is not feasible with current technology. 6. Monitoring reservoir performance will ensure proper management of the pool. Annual reports and technical review meetings will keep the AOGCC apprised of reservoir performance, promote greater ultimate recovery and prevent the waste of resources. 7. Analyzing the results of the IPS project will provide valuable insight into the performance of the Thomson Oil Pool that will be necessary for optimizing future development of the Thomson Oil Pool. Annular pressure management is necessary to prevent failure of well integrity and uncontrolled release of fluids or pressure and to minimize threats to human safety and the environment. 9. A GOR limitation waiver is appropriate. During the IPS a waiver under 20 AAC 25.240(b)(1) is appropriate because an ongoing FOR project will be in place. Once major gas sales begin modelling has shown ultimate recovery to be relatively insensitive to the manner of development and thus a waiver of the GOR limits imposed by 20 AAC 25.240(a) will not promote waste or harm ultimate recovery. NOW, THEREFORE, IT IS ORDERED: The development and operation of the Thomson Oil Pool is subject to the following rules and the statewide requirements under 20 AAC 25 to the extent not superseded by these rules: Affected Area: Umiat Meridian Township, Range Description T10N, R24E Sections S/2 of 25, 26 to 36 T10N, R23E Sections 25 to 36 Conservation Order No. 719 Coed • November 9, 2015 Paee 9 of 14 Township, Range Description TRACT C30-114 (BF-114): A PORTION OF BLOCKS 799 AND 800 AS SHOWN ON THE "LEASING AND NOMINATION MAP" FOR THE FEDERAL/STATE BEAUFORT SEA OIL AND GAS LEASE SALE, DATED 1/30/79, MORE PARTICULARLY DESCRIBED AS FOLLOWS:THOSE LANDS LYING NORTHERLY OF THE SOUTH BOUNDARY OF SECTIONS 23 AND 24, T10N, R23E; U.M., AK., AND LYING NORTHERLY OF THE SOUTH BOUNDARY OF SECTIONS 19 AND 20, TION, R24E; U.M., AK., IN BLOCK 799 (BEING THE NORTHERLY PORTION) LISTED AS STATE AREA ON THE T ION, R24E & "SUPPLEMENTAL OFFICIAL O.C.S. BLOCK DIAGRAM" APPROVED T10N, R23E 10/4/79, CONTAINING 1081.11 HECTARES, AND THOSE LANDS LYING NORTHERLY OF THE SOUTH BOUNDARY OF SECTIONS 20, 21, AND 22, TION, R24E; U.M., AK., AND LYING WESTERLY OF 146 DEGREES 00'00" WEST LONGITUDE IN BLOCK 800 LISTED AS STATE AREA ON THE "SUPPLEMENTAL OFFICIAL O.C.S. BLOCK DIAGRAM" APPROVED 10/4/79, CONTAINING 916.21 HECTARES.(GENERAL LOCATION: T10N, R23E; TION, R24E; U.M., AK.) CONTAINING APPROXIMATELY 4935.47 ACRES, MORE OR LESS. THAT PORTION OF TRACT 65-020, "TRACT 65-020 ENCOMPASSES ALL THOSE LANDS IN THE S1/2 OF BLOCK 754 OCS OFFICIAL PROTRACTION DIAGRAM NR 6-4 APPROVED 4/29/79, CONTAINING 1152 HECTARES, AND THOSE LANDS LYING NORTHERLY OF THE SOUTH BOUNDARY OF SECTIONS 20, 21, 22 AND 23, T. 10 N., R. 23 E., TION, R23E UMIAT MERIDIAN, ALASKA IN BLOCK 798 (BEING IN THE NORTHERLY PORTION), LISTED AS STATE AREA ON THE "SUPPLEMENTAL OFFICIAL OCS BLOCK DIAGRAM" APPROVED 10/4/79, CONTAINING 1109.94 HECTARES.", LYING SOUTHERLY OF SECTIONS 14, 15, 16 AND 17, T. 10 N., R. 23 E., U.M.., ALASKA IN OCS BLOCK 798. THIS TRACT CONTAINS 1,909.74 ACRES, (772.85 HECTARES), MORE OR LESS. THAT PORTION OF TRACT 65-020, "TRACT 65-020 ENCOMPASSES ALL THOSE LANDS IN THE S1/2 OF BLOCK 754 OCS OFFICIAL PROTRACTION DIAGRAM NR 6-4 APPROVED 4/29/79, CONTAINING 1152 HECTARES, AND THOSE LANDS LYING NORTHERLY OF THE SOUTH BOUNDARY OF SECTIONS 20, 21, 22 AND 23, T. ION., R. 23 E., T10N, R23E UMIAT MERIDIAN, ALASKA IN BLOCK 798 (BEING IN THE NORTHERLY PORTION), LISTED AS STATE AREA ON THE "SUPPLEMENTAL OFFICIAL OCS BLOCK DIAGRAM"APPROVED 10/4/79, CONTAINING 1109.94 HECTARES", LYING IN THE S 1 /2 OF OCS BLOCK 754, AND LYING NORTHERLY OF SECTIONS 20, 21, 22 AND 23, T. ION., R. 23E., U.M., ALASKA IN OCS BLOCK 798. CONTAINING 3,684.31 ACRES, (1,490.00 HECTARES), MORE OR LESS. Conservation Order No. 719 Coed November 9, 2015 Pace 10 of 14 Township, Range Description TRACT C30-110 (BF-I10): A PORTION OF BLOCKS 753 AND 797 AS SHOWN ON THE "LEASING AND NOMINATION MAP" FOR THE FEDERAL/STATE BEAUFORT SEA OIL AND GAS LEASE SALE, DATED 1/30/79, MORE PARTICULARLY DESCRIBED AS FOLLOWS: THOSE LANDS LOCATED IN THE S1/2 OF BLOCK 753, BEING A PORTION OF BLOCK753 ON THE AFORESAID LEASING AND NOMINATION MAP, CONTAINING 1152.00 HECTARES, AND THOSE T10N, R23E & LANDS LYING NORTHERLY OF THE SOUTH BOUNDARY OF T10N, R22E SECTIONS 23 AND 24, T10N, R22E; U.M., AK., AND LYING NORTHERLY OF THE SOUTH BOUNDARY OF SECTIONS 19 AND 20, TION, R23E; U.M., AK., IN BLOCK 797 (BEING THE NORTHERLY PORTION) LISTED AS STATE AREA ON THE "SUPPLEMENTAL OFFICIAL O.C.S. BLOCK DIAGRAM" APPROVED 10/4/79, CONTAINING 1133.95 HECTARES.(GENERAL LOCATION: T10N, R22E; T10N, R23E; U.M., AK.) THIS TRACT CONTAINS 5648.68 ACRES MORE OR LESS. T10N, R22E Sections 25 to 36 T. ION., R. 22E., UMIAT MERIDIAN, ALASKA TRACT 65-017 IS A PORTION OF OCS BLOCKS 752 AND 796 AS SHOWN ON THE "LEASING AND NOMINATION MAP" FOR THE FEDERAL/STATE BEAUFORT SEA OIL AND GAS LEASE SALE, DATED 1/30/79, AND MORE PARTICULARLY DESCRIBED AS FOLLOWS: TRACT 65-017 ENCOMPASSES ALL THOSE LANDS IN THE S1/2 OF BLOCK 752, OCS OFFICIAL PROTRACTION DIAGRAM NR 6-4 APPROVED 4/29/75, TION, R22E CONTAINING 1152 HECTARES, AND THOSE LANDS LYING NORTHERLY OF THE SOUTH BOUNDARY OF SECTIONS 20, 21, 22 AND 23, T. ION., R. 22E., UMIAT MERIDIAN, ALASKA IN BLOCK 796 (BEING THE NORTHERLY PORTION) LISTED AS STATE AREA ON THE "SUPPLEMENTAL OFFICIAL OCS BLOCK DIAGRAM" APPROVED 10/4/79, CONTAINING 1153.17 HECTARES. THIS TRACT CONTAINS 5696.18 ACRES MORE OR LESS (2305.17 HECTARES MORE OR LESS). TRACT 65-016 ENCOMPASSES ALL THOSE LANDS IN THE S1/2 OF BLOCK 751, OCS OFFICIAL PROTRACTION DIAGRAM NR 6-4 APPROVED 4/29/75, CONTAINING 1152.00 HECTARES, AND THOSE LANDS LYING NORTHERLY OF THE SOUTH BOUNDARY OF SECTIONS 23 AND 24, T. ION., R. 21E., UMIAT MERIDIAN, ALASKA T ION, R22E & AND LYING NORTHERLY OF THE SOUTH BOUNDARY OF SECTIONS 19 AND 20, T. ION., R. 22E., UMIAT MERIDIAN, ALASKA IN BLOCK T 1 ON, R21 E 795 (BEING THE NORTHERLY PORTION) LISTED AS STATE AREA ON THE "SUPPLEMENTAL OFFICIAL OCS BLOCK DIAGRAM" APPROVED 10/4/79, CONTAINING 1167.58 HECTARES", LYING WITHIN T. 10 N., R. 22 E., U.M., ALASKA, AND THE E1/2E1/2 OF SECTIONS 1,12, 13 AND 24, T. 10 N., R. 21 E., U.M., ALASKA. THIS TRACT CONTAINS 2,779.16 ACRES (1,124.69), MORE OR LESS. T10N, R21E Sections 25, 26, 35, 36 Conservation Order No. 719 Coed November 9, 2015 Page 11 of 14 Township, Range Description T. 10 N., R. 21 E., UMIAT MERIDIAN, ALASKA "TRACT 65-016 ENCOMPASSES ALL THOSE LANDS IN THE S1/2 OF BLOCK 751, OCS OFFICIAL PROTRACTION DIAGRAM NR6-4 APPROVED 4/29/75, CONTAINING 1152.00 HECTARES, AND THOSE LANDS LYING NORTHERLY OF THE SOUTH BOUNDARY OF SECTIONS 23 AND 24, T. 10 N., R. 21 E., UMIAT MERIDIAN, ALASKA AND LYING T 1 ON, R21 E NORTHERLY OF THE SOUTH BOUONDARY OF SECTIONS 19 AND 20, T. 10 N., R. 22 E., UMIAT MERIDIAN, ALASKA IN BLOCK 795, BEING THE NORTHERLY PROTION)LISTED AS STATE AREA ON THE "SUPPLEMENTAL OFFICIAL OCS BLOCK DIAGRAM" APPROVED 10/4/79, CONTAINING 1167.58 HECTARES.", LYING WITHIN T. 10 N., R. 21 E.,U.M. ALASKA, EXCLUDING THE E1/2E1/2 OF SECTIONS 1,12,13 AND 24. THIS TRACT CONTAINS 2,952.62 ACRES, (1,194.89 HECTARES), MORE OR LESS. T09N, R24E Sections 2 to 9, N/2 of 10, SWA of 10, 15 (excluding ANWR), N/2 of 16, 17, 18, N/2 of 19, NW/4 of 20 SECTION 1: UNSURVEYED, ALL TIDE AND SUBMERGED LAND, T09N, R24E EXCLUDING STATE OF ALASKA OIL AND GAS LEASE ADL 372256 AND THE ARCTIC NATIONAL WILDLIFE REFUGE, 15.80 ACRES T09N, R23E Sections 1 to 18, N/2 of 21, N/2 of 22, N/2 of 23, N/2 of 24 T09N, R22E Sections 1 to 12 Rule 1 Field and Pool Name The field is the Pt. Thomson Field. Hydrocarbons underlying the Affected Area and within the interval identified in Rule 2, below, constitute the Thomson Oil Pool. Rule 2 Pool Definition The Thomson Oil Pool is the accumulation of hydrocarbons underlying the Affected Area that is common to, and correlates with, the interval between 16,126 and 16,377 feet MD on the VISION/ScopeTM Measured Depth Log recorded in reference well PTU No. 15. Rule 3 Reservoir Pressure Monitoring (a) A bottom -hole pressure survey shall be taken on each well prior to initial production or injection. (b) The operator shall obtain the pressure surveys needed to manage the hydrocarbon recovery processes effectively subject to the annual plan outlined in Rule 9, below. At a minimum a pressure survey shall be acquired from at least one well on each drill site each year. (c) The reservoir pressure datum will be-12,700' 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, and open -hole formation tests or other methods approved by the AOGCC. Conservation Order No. 719 CAted November 9, 2015 Page 12 of 14 (e) A Reservoir Pressure Report, Form 10-412, shall be utilized for all surveys; all relevant data shall be attached to the report. The data submitted shall include, at a minimum, rate, pressure, depth, fluid gradient, temperature, and all other well conditions necessary for a complete analysis of each survey being conducted. (f) The results and data from any special reservoir pressure monitoring tests or surveys shall also be submitted in accordance with paragraph (e) of this rule. Rule 4 Gas -Oil Ratio Exemption Wells producing from the Thomson Oil Pool are exempt from the GOR limits of 20 AAC 25.240(a). Rule 5 Annual Reservoir Review (a) An annual reservoir surveillance report must be filed by April 1st of each year and include future development plans, reservoir depletion plans, and surveillance information for the prior calendar year, including: (i) The voidage balance, by month, of produced fluids and injected fluids and the cumulative status for each producing interval; (ii) A reservoir pressure map at datum, and a summary and analysis of the reservoir pressure surveys within the pool; (iii) The results and, where appropriate, an analysis of production and injection log surveys, tracer surveys, observation well surveys, and any other special monitoring; (iv) A review of pool production allocation factors and issues over the prior year. (v) A review of the progress of the enhanced recovery project; and (vi) A reservoir management summary, including results of any reservoir simulation studies. (b) By June 1st of each year, the operator shall schedule and conduct a technical review meeting with the AOGCC to discuss the annual reservoir surveillance report and items that may require action within the coming year. The AOGCC may audit the technical data and analyses relating to the surveillance report's conclusions and reservoir depletion plans. Rule 6 Initial Production System Results Report After five years of sustained production under the IPS or 12 months before gas sales from Pt. Thomson are scheduled to begin, whichever comes first, the operator shall submit a report to the AOGCC on the results and findings from conducting the IPS. The report shall include the following information: (a) A description of what the operator expected the IPS to show about the performance of the Thomson Oil Pool and the fluids contained within before the IPS project began producing; (b) A description of what the IPS actually showed about the performance of the Thomson Oil Pool and the fluids contained within; Conservation Order No. 719 Coed • November 9, 2015 Page 13 of 14 (c) A discussion, with appropriate supporting information, on whether or not the IPS showed the Thomson Oil Pool to be compartmentalized; (d) A discussion, with appropriate PVT data, on what the IPS showed about the reservoir fluid properties; and (e) A discussion on whether or not the development method proposed in this order is still the best method to optimize ultimate recovery and prevent waste. Rule 7 Annular Pressures (a) At the time of installation or replacement, the operator shall conduct and document a pressure test of tubulars and completion equipment in each development well that is sufficient to demonstrate that planned well operations will not result in failure of well integrity, uncontrolled release of fluid or pressure, or threat to human safety. (b) The operator shall monitor each development well daily to check for sustained pressure, except if prevented by extreme weather conditions, emergency situations, or unavoidable circumstances. Monitoring results shall be made available for AOGCC inspection. (c) The operator shall notify the AOGCC within three working days after the operator identifies a well as having (i) sustained inner annulus pressure that exceeds 2, 000 psig for all development wells, or (ii) sustained outer annulus pressure that exceeds 1, 000 psig. (d) The AOGCC 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 AOGCC may approve the operator's proposal or require other corrective action or surveillance. The AOGCC may require corrective action be verified by a mechanical integrity test or other approved diagnostic tests. The operator shall give the AOGCC sufficient notice of the testing schedule to allow the AOGCC 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 AOGCC within three working days and take corrective action. Unless well conditions require the operator to take emergency corrective action before AOGCC approval can be obtained, the operator shall submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action. The AOGCC may approve the operator's proposal or require other corrective action. The AOGCC may also require corrective action be verified by mechanical integrity testing or other AOGCC approved diagnostic tests. The operator shall give the AOGCC sufficient notice of the testing schedule to allow the AOGCC to witness the tests. (f) Except as otherwise approved by the AOGCC under (d) or (e) of this rule, before a shut-in well is placed in service, any annulus pressure must be relieved to a sufficient degree (1) that the inner annulus pressure at operating temperature will be below 2,000 psig, and (2) that the outer annulus pressure at operating temperature will be below Conservation Order No. 719 Coed • November 9, 2015 Page 14 of 14 1,000 psig. A well 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 AOGCC under (c) of this rule, unless the AOGCC 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; and 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 8 Allowable Gas Offtake Rate The maximum allowable annual average gas offtake rate from the Thomson Oil Pool is 1.1 billion standard cubic feet per day (BSCFD). Rule 9 Administrative Action Upon proper application, or its own motion, and unless notice and public hearing are otherwise required, the AOGCC may administratively waive the requirements of any rule stated herein or administratively amend this order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater. 0< AOILAti_ DONE at Anchorage, Alaska and dated November 9, 2015. a&17 lq� Cathy V. Foerster Daniel T. Se--a-mount, Jr. Chair, Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC malls, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Singh, Angela K (DOA) From: Carlisle, Samantha J (DOA) Sent: Monday, November 09, 2015 2:48 PM To: Ballantine, Tab A (LAW); Bender, Makana K (DOA); Bettis, Patricia K (DOA); Bixby, Brian D (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Cook, Guy D (DOA); Crisp, John H (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Herrera, Matthew F (DOA); Hill, Johnnie W (DOA); Jones, Jeffery B (DOA); Kair, Michael N (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Wallace, Chris D (DOA); AKDCWellIntegrityCoordinator, Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew VanderJack, Anna Raff; Barbara F Fullmer, bbritch; bbohrer@ap.org; Bob Shavelson; Brian Havelock; Bruce Webb; Burdick, John D (DNR); Caleb Conrad; Carrie Wong; Cliff Posey; Colleen Miller; Crandall, Krissell; D Lawrence; Dave Harbour; David Boelens; David Duffy; David House; David McCaleb; David Steingreaber; David Tetta; Davide Simeone; ddonkel@cfl.rr.com; Dean Gallegos; Delbridge, Rena E (LAS); DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Frank Molli; Gary Oskolkosf, George Pollock, ghammons; Gordon Pospisil; Gregg Nady; gspfoff, Hyun, James J (DNR); Jacki Rose; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Williams, Jennifer L (LAW); Jerry Hodgden; Jerry McCutcheon; Solnick, Jessica D (LAW); Jim Watt; Jim White; Joe Lastufka; Joe Nicks; John Adams; Easton, John R (DNR); Jon Goltz; Juanita Lovett; Judy Stanek; Houle, Julie (DNR); Julie Little; Kari Moriarty; Kazeem Adegbola; Keith Wiles; Kelly Sperback; Laney Vazquez; Gregersen, Laura S (DNR); Leslie Smith; Lisa Parker; Louisiana Cutler, Luke Keller, Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (ma rk.han ley@ anada rko.com); Mark Landt; Mark Wedman; Kremer, Marguerite C (DNR); Mary Cocklan-Vendl; Michael Calkins; Michael Duncan; Michael Moora; Mike Bill; mike@kbbi.org; Mikel Schultz; MJ Loveland; mkm7200; Morones, Mark P (DNR); Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nick W. Glover, Nikki Martin; NSK Problem Well Supv; Oliver Sternicki; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Renan Yanish; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Skutca, Joseph E (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Stephen Hennigan; Moothart, Steve R (DNR); Suzanne Gibson; sheffield@aoga.org; Tania Ramos; Ted Kramer; Davidson, Temple (DNR); Terence Dalton; Teresa Imm; Thor Cutler, Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater, Anne Hillman; Brian Gross; Bruce Williams; Bruno, Jeff J (DNR); Caroline Bajsarowicz; Casey Sullivan; Diane Richmond; Don Shaw; Donna Vukich; Eric Lidji; Gary Orr, Smith, Graham O (DNR); Greg Mattson; Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Holly Pearen; Jason Bergerson; Jim Magill; Joe Longo; John Martineck, Josh Kindred; Kenneth Luckey, King, Kathleen J (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Franger, James M (DNR); Morgan, Kirk A (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Richard Garrard, - Robert Province; Ryan Daniel; Sandra Lemke; Sarah Baker, Peterson, Shaun (DNR); Pollard, Susan R (LAW); Talib Syed; Terence Dalton; Tina Grovier (tmgrovier@stoel.com); Todd, Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster, William Van Dyke Subject: Conservation Order 719 Corrected (PTU) 19 Attachments: co7corrected.pdf • On page 8 there was an error in Conclusion 9. The regulation referenced was 20 AAC 25.140(a) and it should be 20 AAC 25.240(a). The corrected order has been updated to reflect the correct regulation. Thank you, Samantha CarCisCe Executive Secretary II At4ska Oil and Gas Conservation Commission 333 West 7" Avenue .Anchorage, AX 99501 (907) 793-I223 (phone) (907) 276-7542 (fax) CONFIDENT M-MY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Samantha Carlisle at (907) 793-1223 or Samantha.Carlisle(a)alaska.eov. • 0 James Gibbs Jack Hakkila Bernie Karl P.O. Box 1597 P.O. Box 190083 K&K Recycling Inc. Soldotna, AK 99669 Anchorage, AK 99519 P.O. Box 58055 Fairbanks, AK 99711 Gordon Severson Penny Vadla George Vaught, Jr. 3201 Westmar Cir. 399 W. Riverview Ave. P.O. Box 13557 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Cory E. Quarles Richard Wagner Darwin Waldsmith Alaska Production Manager P.O. Box 60868 P.O. Box 39309 ExxonMobil Production Company Fairbanks, AK 99706 Ninilchik, AK 99639 P.O. Box 196601 Anchorage, AK 99519-6601 ,Aa z L.@ Angela K. Singh • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 71h Avenue Anchorage Alaska 99501 Re: THE APPLICATION OF ExxonMobil ) Docket Number: CO-15-008 Alaska Production Inc. for an order for ) Conservation Order No. 719 classification of a new oil pool and to ) prescribe pool rules for development of the ) Point Thomson Field Thomson Oil Pool within the Pt. Thomson ) Point Thomson Unit Field, Pt. Thomson Unit, East Harrison Bay, ) Thomson Oil Pool Beaufort Sea, Alaska ) October 15, 2015 IT APPEARING THAT: 1. By application received July 16, 2015, ExxonMobil Alaska Production Inc. (ExxonMobil), as operator of the Point Thomson Unit (PTU) and on behalf of ExxonMobil, BP Exploration (Alaska) Inc., ConocoPhillips Alaska, Inc., and 21 other owners having a total combined working interest of less than 1 percent, requested an order defining a new oil pool, the Point Thomson -Thomson Oil Pool (Thomson Oil Pool), within the PTU and prescribing rules governing the development and operation of that pool, including an annual average allowable gas-offtake rate of 1.1 billion standard cubic feet per day (BSCFD). 2. Pursuant to 20 AAC 25.540, the Alaska Oil and Gas Conservation Commission (AOGCC) scheduled a public hearing for September 1, 2015. On July 20, 2015, the AOGCC published notice of that hearing on the State of Alaska's Online Public Notice website and on the AOGCC's website, electronically transmitted the notice to all persons on the AOGCC's email distribution list, and mailed printed copies of the Notice of Public Hearing to all persons on the AOGCC's mailing distribution list. On July 21, 2015, the notice was published in the ALASKA DISPATCH NEWS. 3. On July 23, 2015, the AOGCC published notice of that the location of the hearing had changed on the State of Alaska's Online Public Notice website and on the AOGCC's website, electronically transmitted the notice to all persons on the AOGCC's email distribution list, and mailed printed copies of the Notice of Public Hearing to all persons on the AOGCC's mailing distribution list. On July 24, 2015, the notice was published in the ALASKA DISPATCH NEWS. 4. No comments on the application were received. 5. The hearing commenced at 9:00 AM on September 1, 2015, in the Alaska State Legislature Building, Legislative Information Office located at 716 West 4th Avenue, Anchorage, Alaska. 6. Testimony was received from representatives of ExxonMobil. 7. The record was held open until September 8, 2015, to allow the operator to respond to requests made during the hearing. Conservation Order No. 719 October 15, 2015 Page 2 of 14 8. The AOGCC received the requested additional information from ExxonMobil on September 8, 2015, and the record was closed. FINDINGS: 1. Operator and Owners: ExxonMobil is the operator of the leases in the portion of the PTU that is currently proposed for development. ExxonMobil, BP Exploration (Alaska) Inc., ConocoPhillips Alaska, Inc., and 21 other partners are working interest owners, and the State of Alaska, Department of Natural Resources (DNR) is the landowner of the Affected Area, which is located within the North Slope Borough, approximately 50 miles east of Prudhoe Bay along Alaska's northern coastline. 2. Affected Area: The proposed Thomson Oil Pool, which underlies state lands onshore and state waters offshore, is shown on Figure 1, below.' This pool will be developed initially from the onshore Central Pad drill site (Central Pad), which is located in Section 34, Township ION, Range 23E, Umiat Meridian (UM). ExxonMobil's development plans include construction of a second onshore gravel drill site (termed the "West Pad") in Section 36, Township ION, Range 22E, UM, and likely a third onshore gravel drill site (termed the "East Pad") that is currently planned for Section 6 or 7 of Township 9N, Range 24E, UM. Existing IPS Wells - BHL SOURDOUGH p Scheduled IPS Gas Production Well - BHL 0 Tentative Gas Expansion Production Wells - BHL 0 3 Miles Figure 1. Affected Area, Proposed Thomson Oil Pool (The approximate outline of the Affected Area is indicated by the blue line.' Confidential wells are shown in red.) I This map is presented for illustration purposes only. For a more precise depiction of the Affected Area, refer to the legal description presented on pages 9, 10, and 11 of this order. Conservation Order No. 719 • October 15, 2015 Page 3 of 14 0 Comletion Depth Rests Pomsity GR ResD RHOS end -SiN-Shale 7✓D`_1S� ResM _ DRHO .5 MOM 500 .2 G/C3 0. *V0 R.eS NPOR NPHI Depth TVDSS rzna 15700, ,?,oa Canning 15800 Formation - ,100 15900 12500 -12500 16000 -16 6000 ��Euo Hue / HRZ 16100 12601 Shale t10 16200 1 Thomson Sand Oil Pool 16300rnnn i2eoJ Basement 2500 -A 16500 Figure 2. PTU No. 15 — Type Well Log for Thomson Oil Poole 2 Figure 2 is for illustration purposes only. Refer to the well log measurements recorded in exploratory well PTU No. 15 for the precise representation of the proposed Thomson Oil Pool. The horizontal grid lines in this figure represent increments of ten feet measured depth. The acronym TVDSS refers to true vertical depth subsea (true vertical depth below sea level). Conservation Order No. 719 • October 15, 2015 Page 4 of 14 3. Exploration and Delineation History: The PTU No. 1 well discovered the Thomson Sand reservoir in 1977. Since that time, 17 additional wells have penetrated the reservoir or its equivalent subsurface horizon within the PTU area.3 Information from these wells and from seven overlapping seismic surveys was used to determine the geologic structure, reservoir distribution, and the area that will be affected by condensate -gas production and re- injection of residual produced gas. Production test, drill -stem test, down -hole sampling, core, and well log data were used to establish reservoir properties, fluid properties, and gas - oil and oil -water contacts for this proposed pool. 4. Pool Identification: The proposed Thomson Oil Pool is the accumulation of hydrocarbons underlying the Affected Area that is common to, and correlates with, the interval between 16,126 and 16,377 feet measured depth (MD), which is equivalent to-12,614 and -12,828 feet true vertical depth below mean sea level (also termed true vertical depth subsea and represented herein by the acronym TVDSS4) on the VISION/ScopeTM Measured Depth Log recorded in well PTU No. 15. 5. Pool Classification: Well tests conducted on the Thomson Sand reservoir in PTU-area wells yielded gas -oil ratio (GOR) values that range from about 850 to 15,750 standard cubic feet of gas per stock tank barrel of oil (scf/stb).5 ExxonMobil's testimony stated that the initial producing GOR for PTU gas expansion project wells is expected to be less than 20,000 scf/stb. GOR values less than 100,000 scf/stb oblige the AOGCC to classify wells producing from the Thomson Sand as oil wells.6 Accordingly, the AOGCC classifies the hydrocarbon accumulation within the Thomson Sand reservoir as an oil pool. 6. Geology: (a) Stratigraphy: The Thomson Oil Pool encompasses the early Cretaceous -aged Thomson Sand, which lies unconformably atop pre -Mississippian -aged basement rocks comprising dolomite, argillite, quartzite, and phyllite. Fractured and/or karsted dolomite appears restricted to the northern part of the field, and this rock may serve as a secondary reservoir in communication with the Thomson Sand. The rocks that underlay the Affected Area for this order are expected to be predominantly phyllite and quartzite. The sediments that comprise the Thomson Sand reservoir were derived from basement rocks that were exposed in the northern and northeastern portions of the Point Thomson Field and bordered to the southwest by a sea. Eroded sediments were transported down -gradient toward the southwest and progressively deposited in alluvial fan, fan -delta, and marine shoreface environments. Wave and current activity extensively reworked these sediments and distributed them in southeast -trending bands arranged subparallel to the shoreline. From northeast (proximal) to southwest (distal), these bands generally consist of alluvial fan breccia, conglomerate, conglomerate with 3 Twenty-two wells have been drilled in and near the PTU. Of those 22 wells, 18 penetrated the Thomson Sand or equivalent horizon. Of those 18 wells, 16 penetrated the Thomson Sand, which is absent in the remaining two wells because of erosion. 4 To avoid confusion, when depths presented represent true vertical depth subsea, the footage will be preceded by a minus sign and followed by the acronym TVDSS (e.g., 12,000 feet true vertical subsea will be depicted as-12,000 feet TVDSS). 5 AOGCC, 1984, Statistical Report, Reservoir Data for Wells Alaska State A-1 and Pt. Thomson Unit No. 1, p. 103; PTU 15 Well History File 209-014, p. 275; PTU 16 Well History File 209-015, p. 195. 6 Regulation 20 AAC 25.990(45): 'oil well" means a well that produces predominantly oil at a gas -oil ratio of 100,000 scf/stb or lower, unless on a pool -by -pool basis the AOGCC establishes another ratio. • Conservation Order No. 719 October 15, 2015 Page 5 of 14 minor sandstone, sandstone, silty sandstone, and siltstone. In general, coarser -grained, proximal lithologies are dominated by carbonate clasts, with quartz and ductile grains becoming increasingly prominent in the more distal areas that lie to the southwest. ExxonMobil informally divides the Thomson Sand into an upper member and a lower member based on core descriptions and well log correlations. The lower member is dominantly progradational, whereas the upper member is dominantly retrogradational. The Thomson Sand is unconformably overlain by siltstone, mudstone, and shale assigned to the Canning Formation, Hue Shale, and HRZ, in descending stratigraphic order. Erosion thinned the Hue and HRZ shale intervals toward the northeast, and completely removed these intervals from the northern and eastern portions of the PTU. (b) Structure: The structure of the proposed Thomson Oil Pool is a gently dipping, four- way anticlinal closure. Based on well and 3D-seismic control, the top of the pool lies about-12,500 feet TVDSS, and the structure extends to a depth of about-14,500 feet TVDSS within the PTU area. (c) Faults: The Thomson anticlinal closure is cut by several, north- and north -northeast - trending, normal faults. The vertical displacement of faults observed within the Thomson Sand interval averages about 65 to 95 feet, with a maximum of about 200', but none of these faults appear to completely displace the Thomson Sand or create isolated compartments within it. None of the faults are expected to act as flow barriers. (d) Trap Configuration and Seals: Well log and seismic information indicate that hydrocarbon distribution within the proposed Thomson Oil Pool is influenced by both structural and stratigraphic elements. A broad, east -southeast -trending anticlinal closure provides primary control for the accumulation. Internal facies changes within the Thomson Sand interval strongly influence reservoir quality and the distribution of hydrocarbons, especially in the southern and western portions of the PTU. The Thomson Sand is overlain by a thick, laterally extensive section of siltstone, mudstone, and shale assigned, in descending stratigraphic order, to the Canning Formation, Hue Shale, and HRZ Shale. These intervals provide the top seal for the proposed Thomson Oil Pool. In the northern and northeastern parts of the PTU, where the Hue and HRZ intervals are either absent or are very thin, mudstone and siltstone assigned to the lower Canning Formation provides a top seal. The Thomson Sand is underlain predominantly by thick Pre -Mississippian -aged dolomite, phyllite, and quartzite basement rocks that are fractured in part and may provide some contribution to production. (e) Reservoir Compartmentalization: Flow tests and reservoir pressure measurements indicate that the Thomson Oil Pool is not separated into isolated compartments within the Affected Area. (f) Permafrost Base: Permafrost base is about -1,800 feet TVDSS within the Affected Area. 7. Reservoir Properties: ExxonMobil informally subdivides the Thomson Sand reservoir into six petrofacies based on grain size, sorting, cementation, and ductile -grain content. These petrofacies are: cemented breccia and conglomerate, open -framework conglomerate, Conservation Order No. 719 October 15, 2015 Page 6 of 14 bimodal conglomerate, clean sandstone, silty sandstone, and siltstone. Each of these petrofacies plots within a well-defined area on a chart of core porosity versus core permeability, and —for reservoir modeling purposes —each petrofacies has a distinct equation that is used to transform porosity measurements to estimated permeability values. Petrofacies Porosity Permeability' Average Sw in Reservoir Gas Cap Qualit Open Framework Conglomerate to Up t 100+ mD 5% Excellent 2 to 10+ D Bi-Modal Conglomerate ^-14% 1 mD to 10 D 25% Good Conglomerate & Breccia — < 8% < 0.1 mD 90% Poor Cemented (CaCO3 > 10%) Sandstone — Clean 100+ mD �24% 15% Very good (generally <10% ductile grains) to < 10 D Sandstone — Silty —12% < 10 mD 70% Poor (generally >15% ductile grains) Siltstone - < 10 mD 70% Poor H: 1 mD;- Pre -Miss. Basement _1% Poor V: 78 mD' 8. Reservoir Fluid Properties: Within the Point Thomson Field, the accumulation within the Thomson Sand comprises a nearly 500-foot thick, high-pressure, condensate -gas "cap" (gas cap) and an underlying, 37-foot thick rim of viscous oil.9 Relict oil saturation exists within the gas cap due to multiple oil migration events. Relict oil saturation increases downward, toward the gas -oil contact. Average oil saturation within the gas cap is approximately 10%. Condensate yield for the reservoir is estimated to be about 60 to 65 stock tank barrels (stb) per 1 million standard cubic feet of gas (MMSCF). The oil rim consists of 10' to 18' API gravity oil that has a viscosity of about two centipoise at reservoir conditions. The lower portion of the oil rim consists of an oil -water transition zone, where both oil and water are partially mobile. 9. Reservoir Fluid Contacts: For the proposed Thomson Oil Pool, the gas -oil contact is placed at—12,975 feet TVDSS from drill stem test results, Modular Dynamic Tests, and fluid samples from wells PTU 15 and PTU 16. The oil -water contact is estimated at—13,012 feet TVDSS based on fluid samples from PTU 16 and confidential well tests and well log data.10 The elevations of these contacts are believed to be constant throughout the Affected Area, and the entire hydrocarbon accumulation is considered to be in pressure communication. In 7 The abbreviation mD signifies millidarcies, and D signifies Darcies. Permeability values provided in this table represent air permeability. Based on core analyses, ExxonMobil assigns these general reservoir properties to fractured Pre -Mississippian basement rocks: 1 % porosity, 1 mD horizontal permeability, and 78 mD vertical permeability. 9 Estimated from MDT pressure and fluid samples obtained in well PTU 16 supported by additional data from confidential wells 10 Records for several exploratory wells located in the eastern portion of the Point Thomson area are held confidential indefinitely because of their close proximity to unleased acreage in the Arctic National Wildlife Refuge. • Conservation Order No. 719 0 October 15, 2015 Page 7 of 14 shallower portions of the proposed pool, condensate -gas -bearing Thomson Sand directly overlies fractured, Pre -Mississippian basement rock. 10. Reservoir Pressure and Temperature: The proposed Thomson Oil Pool is abnormally geo- pressured: average reservoir pressure is about 10,100 psi at ExxonMobil's specified pressure datum of-12,700 feet TVDSS (a pore -pressure gradient of about 0.795 psi/ft).11 Reservoir temperature ranges from about 220' to 230' F. 11. In -Place Volumes: ExxonMobil's geologic and reservoir model suggests that the original gas in place for the PTU is about 8 trillion cubic feet (TCF). The 37-foot thick, viscous -oil rim is estimated to contain about 160 million barrels of original oil in place. 12. Proposed Gas Offtake Rate: The PTU Working Interest Owners (WIOs) requested an annual average allowable gas offtake rate of 1.1 BSCFD for input to the Alaska Liquefied Natural Gas (AKLNG) project and to fuel PTU operations. 13. Alternative Development Plans Considered: At the hearing, ExxonMobil presented evidence as to how the reservoir simulation model was built and showed simulation results for its proposal and several other development options including alternative offtake rates and various cases involving full field gas cycling ahead of major gas sales. The results showed that ultimate recovery from the Thomson Oil Pool was relatively insensitive to the development method and that the differences were arguably within the margin of error of the simulation model based on the current understanding of the reservoir. 14. Reservoir Development and Management: ExxonMobil proposes to develop the Thomson Oil Pool initially as a limited gas -cycling project, known as the Initial Production System (IPS), in order to gain information about condensate yield and reservoir connectivity. Gas will be produced at the rate of about 200 MMSCFD, and it will be routed to the Central Processing Facility, where up to 10,000 barrels of condensate per day will be extracted for sales. Some of the residual, produced gas will be used to fuel the PTU facilities, and the remainder will be injected back into the Thomson Sand reservoir to maintain pressure and conserve resources. This portion of the project is expected to begin production in early 2016. Beginning in or about 2025 ExxonMobil and the other WIOs expect to have the opportunity to start selling gas from the Thomson Oil Pool as part of the AKLNG project currently being planned. When major gas sales begin, the IPS wells will be converted to gas producers and additional production wells will be drilled in order to give the Thomson Oil Pool the capacity to meet the requested 1.1 BSCFD gas offtake rate. ExxonMobil currently has no plans to develop the oil rim. Achieving significant oil production from this 37-foot thick interval would be difficult —even using horizontal drilling technology —because the high viscosity oil contained within this relatively thin interval would initially yield only minimal oil production followed rapidly by breakthrough of overlying gas, underlying water, or both. Ultimate oil recovery would be very low, and separate facilities would be required to process the viscous oil. 15. Gas -Oil Ratio Limit Waiver: ExxonMobil requests a waiver from the gas -oil ration limits of 20 AAC 25.240(a) for the development wells in the Thomson Oil Pool. 11 Regulation 20 AAC 25.990(2): "abnormally geo-pressured strata" means subsurface zones where the pore pressure exceeds a gradient of 0.50 psi/ft. i Conservation Order No. 719 October 15, 2015 Page 8 of 14 CONCLUSIONS: 1. Pool Rules for the development of the Thomson Oil Pool in the PTU are appropriate. 2. Per 20 AAC 25.990(45), the hydrocarbon accumulation within Thomson Sand is properly classified as an oil pool. 3. ExxonMobil's IPS project will provide reservoir pressure and condensate yield information that will promote more effective resource recovery. 4. During the IPS project, re -injection of residual produced gas into the Thomson Oil Pool will preserve reservoir energy and increase ultimate recovery. 5. Significant oil production from the 37-foot thick, viscous -oil rim that lies at the base of the proposed pool is not feasible with current technology. 6. Monitoring reservoir performance will ensure proper management of the pool. Annual reports and technical review meetings will keep the AOGCC apprised of reservoir performance, promote greater ultimate recovery and prevent the waste of resources. 7. Analyzing the results of the IPS project will provide valuable insight into the performance of the Thomson Oil Pool that will be necessary for optimizing future development of the Thomson Oil Pool. 8. Annular pressure management is necessary to prevent failure of well integrity and uncontrolled release of fluids or pressure and to minimize threats to human safety and the environment. 9. A GOR limitation waiver is appropriate. During the IPS a waiver under 20 AAC 25.240(b)(1) is appropriate because an ongoing FOR project will be in place. Once major gas sales begin modelling has shown ultimate recovery to be relatively insensitive to the manner of development and thus a waiver of the GOR limits imposed by 20 AAC 25.140(a) will not promote waste or harm ultimate recovery. NOW, THEREFORE, IT IS ORDERED: The development and operation of the Thomson Oil Pool is subject to the following rules and the statewide requirements under 20 AAC 25 to the extent not superseded by these rules: Affected Area: Umiat Meridian Township, Range Description T10N, R24E Sections S/2 of 25, 26 to 36 T10N, R23E Sections 25 to 36 • Conservation Order No. 719 October 15, 2015 Page 9 of 14 Township, Range Description TRACT C30-114 (BF-114): A PORTION OF BLOCKS 799 AND 800 AS SHOWN ON THE "LEASING AND NOMINATION MAP" FOR THE FEDERAL/STATE BEAUFORT SEA OIL AND GAS LEASE SALE, DATED 1/30/79, MORE PARTICULARLY DESCRIBED AS FOLLOWS:THOSE LANDS LYING NORTHERLY OF THE SOUTH BOUNDARY OF SECTIONS 23 AND 24, TION, R23E; U.M., AK., AND LYING NORTHERLY OF THE SOUTH BOUNDARY OF SECTIONS 19 AND 20, TION, R24E; U.M., AK., IN BLOCK 799 (BEING THE T10N R24E & NORTHERLY PORTION) LISTED AS STATE AREA ON THE T10N, R23E "SUPPLEMENTAL OFFICIAL O.C.S. BLOCK DIAGRAM" APPROVED 10/4/79, CONTAINING 1081.11 HECTARES, AND THOSE LANDS LYING NORTHERLY OF THE SOUTH BOUNDARY OF SECTIONS 20, 21, AND 22, TION, R24E; U.M., AK., AND LYING WESTERLY OF 146 DEGREES 00100" WEST LONGITUDE IN BLOCK 800 LISTED AS STATE AREA ON THE "SUPPLEMENTAL OFFICIAL O.C.S. BLOCK DIAGRAM" APPROVED 10/4/79, CONTAINING 916.21 HECTARES.(GENERAL LOCATION: T10N, R23E; TION, R24E; U.M., AK.) CONTAINING APPROXIMATELY 4935.47 ACRES, MORE OR LESS. THAT PORTION OF TRACT 65-020, "TRACT 65-020 ENCOMPASSES ALL THOSE LANDS IN THE S1/2 OF BLOCK 754 OCS OFFICIAL PROTRACTION DIAGRAM NR 6-4 APPROVED 4/29/79, CONTAINING 1152 HECTARES, AND THOSE LANDS LYING NORTHERLY OF THE SOUTH BOUNDARY OF SECTIONS 20, 21, 22 AND 23, T. 10 N., R. 23 E., T10N, R23E UMIAT MERIDIAN, ALASKA IN BLOCK 798 (BEING IN THE NORTHERLY PORTION), LISTED AS STATE AREA ON THE "SUPPLEMENTAL OFFICIAL OCS BLOCK DIAGRAM" APPROVED 10/4/79, CONTAINING 1109.94 HECTARES.", LYING SOUTHERLY OF SECTIONS 14, 15, 16 AND 17, T. 10 N., R. 23 E., U.M.., ALASKA IN OCS BLOCK 798. THIS TRACT CONTAINS 1,909.74 ACRES, (772.85 HECTARES), MORE OR LESS. THAT PORTION OF TRACT 65-020, "TRACT 65-020 ENCOMPASSES ALL THOSE LANDS IN THE S1/2 OF BLOCK 754 OCS OFFICIAL PROTRACTION DIAGRAM NR 6-4 APPROVED 4/29/79, CONTAINING 1152 HECTARES, AND THOSE LANDS LYING NORTHERLY OF THE SOUTH BOUNDARY OF SECTIONS 20, 21, 22 AND 23, T. 1ON., R. 23 E., T10N, R23E UMIAT MERIDIAN, ALASKA IN BLOCK 798 (BEING IN THE NORTHERLY PORTION), LISTED AS STATE AREA ON THE "SUPPLEMENTAL OFFICIAL OCS BLOCK DIAGRAM"APPROVED 10/4/79, CONTAINING 1109.94 HECTARES", LYING IN THE SI/2 OF OCS BLOCK 754, AND LYING NORTHERLY OF SECTIONS 20, 21, 22 AND 23, T. ION., R. 23E., U.M., ALASKA IN OCS BLOCK 798. CONTAINING 3,684.31 ACRES, (1,490.00 HECTARES), MORE OR LESS. • Conservation Order No. 719 October 15, 2015 Page 10 of 14 Township, Range Description TRACT C30-110 (BF-110): A PORTION OF BLOCKS 753 AND 797 AS SHOWN ON THE "LEASING AND NOMINATION MAP" FOR THE FEDERAL/STATE BEAUFORT SEA OIL AND GAS LEASE SALE, DATED 1/30/79, MORE PARTICULARLY DESCRIBED AS FOLLOWS: THOSE LANDS LOCATED IN THE S1/2 OF BLOCK 753, BEING A PORTION OF BLOCK753 ON THE AFORESAID LEASING AND NOMINATION MAP, CONTAINING 1152.00 HECTARES, AND THOSE T10N, R23E & LANDS LYING NORTHERLY OF THE SOUTH BOUNDARY OF TION, R22E SECTIONS 23 AND 24, T1ON, R22E; U.M., AK., AND LYING NORTHERLY OF THE SOUTH BOUNDARY OF SECTIONS 19 AND 20, TION, R23E; U.M., AK., IN BLOCK 797 (BEING THE NORTHERLY PORTION) LISTED AS STATE AREA ON THE "SUPPLEMENTAL OFFICIAL O.C.S. BLOCK DIAGRAM" APPROVED 10/4/79, CONTAINING 1133.95 HECTARES.(GENERAL LOCATION: TION, R22E; T10N, R23E; U.M., AK.) THIS TRACT CONTAINS 5648.68 ACRES MORE OR LESS. T1ON, R22E Sections 25 to 36 T. ION., R. 22E., UMIAT MERIDIAN, ALASKA TRACT 65-017 IS A PORTION OF OCS BLOCKS 752 AND 796 AS SHOWN ON THE "LEASING AND NOMINATION MAP" FOR THE FEDERAL/STATE BEAUFORT SEA OIL AND GAS LEASE SALE, DATED 1/30/79, AND MORE PARTICULARLY DESCRIBED AS FOLLOWS: TRACT 65-017 ENCOMPASSES ALL THOSE LANDS IN THE S1/2 OF BLOCK 752, OCS OFFICIAL PROTRACTION DIAGRAM NR 6-4 APPROVED 4/29/75, TION, R22E CONTAINING 1152 HECTARES, AND THOSE LANDS LYING NORTHERLY OF THE SOUTH BOUNDARY OF SECTIONS 20, 21, 22 AND 23, T. ION., R. 22E., UMIAT MERIDIAN, ALASKA IN BLOCK 796 (BEING THE NORTHERLY PORTION) LISTED AS STATE AREA ON THE "SUPPLEMENTAL OFFICIAL OCS BLOCK DIAGRAM" APPROVED 10/4/79, CONTAINING 1153.17 HECTARES. THIS TRACT CONTAINS 5696.18 ACRES MORE OR LESS (2305.17 HECTARES MORE OR LESS). TRACT 65-016 ENCOMPASSES ALL THOSE LANDS IN THE S1/2 OF BLOCK 751, OCS OFFICIAL PROTRACTION DIAGRAM NR 6-4 APPROVED 4/29/75, CONTAINING 1152.00 HECTARES, AND THOSE LANDS LYING NORTHERLY OF THE SOUTH BOUNDARY OF SECTIONS 23 AND 24, T. ION., R. 21E., UMIAT MERIDIAN, ALASKA T10N, R22E & AND LYING NORTHERLY OF THE SOUTH BOUNDARY OF SECTIONS 19 AND 20, T. 1 ON., R. 22E., UMIAT MERIDIAN, ALASKA IN BLOCK T 1 ON, R21 E 795 (BEING THE NORTHERLY PORTION) LISTED AS STATE AREA ON THE "SUPPLEMENTAL OFFICIAL OCS BLOCK DIAGRAM" APPROVED 10/4/79, CONTAINING 1167.58 HECTARES", LYING WITHIN T. 10 N., R. 22 E., U.M., ALASKA, AND THE E1/2E1/2 OF SECTIONS 1,12, 13 AND 24, T. 10 N., R. 21 E., U.M., ALASKA. THIS TRACT CONTAINS 2,779.16 ACRES (1,124.69), MORE OR LESS. TION, R21E Sections 25, 26, 35, 36 • Conservation Order No. 719 • October 15, 2015 Page 11 of 14 Township, Range Description T. 10 N., R. 21 E., UMIAT MERIDIAN, ALASKA "TRACT 65-016 ENCOMPASSES ALL THOSE LANDS IN THE S1/2 OF BLOCK 751, OCS OFFICIAL PROTRACTION DIAGRAM NR6-4 APPROVED 4/29/75, CONTAINING 1152.00 HECTARES, AND THOSE LANDS LYING NORTHERLY OF THE SOUTH BOUNDARY OF SECTIONS 23 AND 24, T. 10 N., R. 21 E., UMIAT MERIDIAN, ALASKA AND LYING T10N, R21E NORTHERLY OF THE SOUTH BOUONDARY OF SECTIONS 19 AND 20, T. 10 N., R. 22 E., UMIAT MERIDIAN, ALASKA IN BLOCK 795, BEING THE NORTHERLY PROTION)LISTED AS STATE AREA ON THE "SUPPLEMENTAL OFFICIAL OCS BLOCK DIAGRAM" APPROVED 10/4/79, CONTAINING 1167.58 HECTARES.", LYING WITHIN T. 10 N., R. 21 E.,U.M. ALASKA, EXCLUDING THE E1/2E1/2 OF SECTIONS 1,12,13 AND 24. THIS TRACT CONTAINS 2,952.62 ACRES, (1,194.89 HECTARES), MORE OR LESS. T09N, R24E Sections 2 to 9, N/2 of 10, SW/4 of 10, 15 (excluding ANWR), N/2 of 16, 17, 18, N/2 of 19, NW/4 of 20 SECTION 1: UNSURVEYED, ALL TIDE AND SUBMERGED LAND, T09N, R24E EXCLUDING STATE OF ALASKA OIL AND GAS LEASE ADL 372256 AND THE ARCTIC NATIONAL WILDLIFE REFUGE, 15.80 ACRES T09N, R23E Sections 1 to 18, N/2 of 21, N/2 of 22, N/2 of 23, N/2 of 24 T09N, R22E Sections 1 to 12 Rule 1 Field and Pool Name The field is the Pt. Thomson Field. Hydrocarbons underlying the Affected Area and within the interval identified in Rule 2, below, constitute the Thomson Oil Pool. Rule 2 Pool Definition The Thomson Oil Pool is the accumulation of hydrocarbons underlying the Affected Area that is common to, and correlates with, the interval between 16,126 and 16,377 feet MD on the VISION/ScopeTM Measured Depth Log recorded in reference well PTU No. 15. Rule 3 Reservoir Pressure Monitoring (a) A bottom -hole pressure survey shall be taken on each well prior to initial production or injection. (b) The operator shall obtain the pressure surveys needed to manage the hydrocarbon recovery processes effectively subject to the annual plan outlined in Rule 9, below. At a minimum a pressure survey shall be acquired from at least one well on each drill site each year. (c) The reservoir pressure datum will be-12,700' 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, and open -hole formation tests or other methods approved by the AOGCC. • Conservation Order No. 719 October 15, 2015 Page 12 of 14 (e) A Reservoir Pressure Report, Form 10-412, shall be utilized for all surveys; all relevant data shall be attached to the report. The data submitted shall include, at a minimum, rate, pressure, depth, fluid gradient, temperature, and all other well conditions necessary for a complete analysis of each survey being conducted. (f) The results and data from any special reservoir pressure monitoring tests or surveys shall also be submitted in accordance with paragraph (e) of this rule. Rule 4 Gas -Oil Ratio Exemption Wells producing from the Thomson Oil Pool are exempt from the GOR limits of 20 AAC 25.240(a). Rule 5 Annual Reservoir Review (a) An annual reservoir surveillance report must be filed by April 1 st of each year and include future development plans, reservoir depletion plans, and surveillance information for the prior calendar year, including: (i) The voidage balance, by month, of produced fluids and injected fluids and the cumulative status for each producing interval; (ii) A reservoir pressure map at datum, and a summary and analysis of the reservoir pressure surveys within the pool; (iii) The results and, where appropriate, an analysis of production and injection log surveys, tracer surveys, observation well surveys, and any other special monitoring; (iv) A review of pool production allocation factors and issues over the prior year. (v) A review of the progress of the enhanced recovery project; and (vi) A reservoir management summary, including results of any reservoir simulation studies. (b) By June 1st of each year, the operator shall schedule and conduct a technical review meeting with the AOGCC to discuss the annual reservoir surveillance report and items that may require action within the coming year. The AOGCC may audit the technical data and analyses relating to the surveillance report's conclusions and reservoir depletion plans. Rule 6 Initial Production System Results Report After five years of sustained production under the IPS or 12 months before gas sales from Pt. Thomson are scheduled to begin, whichever comes first, the operator shall submit a report to the AOGCC on the results and findings from conducting the IPS. The report shall include the following information: (a) A description of what the operator expected the IPS to show about the performance of the Thomson Oil Pool and the fluids contained within before the IPS project began producing; (b) A description of what the IPS actually showed about the performance of the Thomson Oil Pool and the fluids contained within; • Conservation Order No. 719 October 15, 2015 Page 13 of 14 (c) A discussion, with appropriate supporting information, on whether or not the IPS showed the Thomson Oil Pool to be compartmentalized; (d) A discussion, with appropriate PVT data, on what the IPS showed about the reservoir fluid properties; and (e) A discussion on whether or not the development method proposed in this order is still the best method to optimize ultimate recovery and prevent waste. Rule 7 Annular Pressures (a) At the time of installation or replacement, the operator shall conduct and document a pressure test of tubulars and completion equipment in each development well that is sufficient to demonstrate that planned well operations will not result in failure of well integrity, uncontrolled release of fluid or pressure, or threat to human safety. (b) The operator shall monitor each development well daily to check for sustained pressure, except if prevented by extreme weather conditions, emergency situations, or unavoidable circumstances. Monitoring results shall be made available for AOGCC inspection. (c) The operator shall notify the AOGCC within three working days after the operator identifies a well as having (i) sustained inner annulus pressure that exceeds 2, 000 psig for all development wells, or (ii) sustained outer annulus pressure that exceeds 1, 000 psig. (d) The AOGCC 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 AOGCC may approve the operator's proposal or require other corrective action or surveillance. The AOGCC may require corrective action be verified by a mechanical integrity test or other approved diagnostic tests. The operator shall give the AOGCC sufficient notice of the testing schedule to allow the AOGCC 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 AOGCC within three working days and take corrective action. Unless well conditions require the operator to take emergency corrective action before AOGCC approval can be obtained, the operator shall submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action. The AOGCC may approve the operator's proposal or require other corrective action. The AOGCC may also require corrective action be verified by mechanical integrity testing or other AOGCC approved diagnostic tests. The operator shall give the AOGCC sufficient notice of the testing schedule to allow the AOGCC to witness the tests. (f) Except as otherwise approved by the AOGCC under (d) or (e) of this rule, before a shut-in well is placed in service, any annulus pressure must be relieved to a sufficient degree (1) that the inner annulus pressure at operating temperature will be below 2,000 psig, and (2) that the outer annulus pressure at operating temperature will be below • Conservation Order No. 719 October 15, 2015 Page 14 of 14 1,000 psig. A well 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 AOGCC under (c) of this rule, unless the AOGCC 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; and 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 8 Allowable Gas Offtake Rate The maximum allowable annual average gas offtake rate from the Thomson Oil Pool is 1.1 billion standard cubic feet per day (BSCFD). Rule 9 Administrative Action Upon proper application, or its own motion, and unless notice and public hearing are otherwise required, the AOGCC may administratively waive the requirements of any rule stated herein or administratively amend this order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater. DONE at Anchorage, Alaska and dated October 15, 2015. t Cathy . Foerster Daniel T. Sea ount, Jr. (,Po Chair, Commissioner Commissioner ,pr, RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. 9 • Singh. Angela K (DOA) From: Carlisle, Samantha J (DOA) Sent: Thursday, October 15, 2015 3:32 PM To: AKDCWellIntegrityCoordinator, Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew Vanderlack; Anna Raff; Barbara F Fullmer, bbritch; bbohrer@ap.org; Bob Shavelson; Brian Havelock, Bruce Webb; Burdick, John D (DNR); Carrie Wong; Cliff Posey, Colleen Miller, Crandall, Krissell; D Lawrence; Dave Harbour, David Boelens; David Duffy; David House; David McCaleb; David Steingreaber; David Tetta; Davide Simeone; ddonkel@cfl.rr.com; Dean Gallegos; Delbridge, Rena E (LAS); DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Frank Molli; Gary Oskolkosf, George Pollock; ghammons; Gordon Pospisil; Gregg Nady; gspfoff, Jacki Rose; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Williams, Jennifer L (LAW); Jerry Hodgden; Jerry McCutcheon; Solnick, Jessica D (LAW); Jim Watt; Jim White; Joe Lastufka; Joe Nicks; John Adams; Easton, John R (DNR); Jon Goltz; Juanita Lovett; Judy Stanek; Houle, Julie (DNR); Julie Little; Kari Moriarty; Kazeem Adegbola; Keith Wiles; Kelly Sperback; Gregersen, Laura S (DNR); Leslie Smith; Lisa Parker; Louisiana Cutler; Luke Keller, Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Kremer, Marguerite C (DNR); Mary Cocklan-Vendl; Michael Calkins; Michael Duncan; Michael Moora; Mike Bill; mike@kbbi.org; Mikel Schultz; MJ Loveland; mkm7200; Morones, Mark P (DNR); Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nick W. Glover, Nikki Martin; NSK Problem Well Supv; Oliver Sternicki; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Renan Yanish; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Moothart, Steve R (DNR); Suzanne Gibson; sheffield@aoga.org; Tania Ramos; Ted Kramer, Davidson, Temple (DNR); Terence Dalton; Teresa Imm; Terry Templeman; Thor Cutler; Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater, Anne Hillman; Brian Gross; Bruce Williams; Bruno, Jeff J (DNR); Caroline Bajsarowicz; Casey Sullivan; Diane Richmond; Don Shaw; Donna Vukich; Eric Lidji; Gary Orr, Smith, Graham O (PCO); Greg Mattson; Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Holly Pearen; Hyun, James 1 (DNR); Jason Bergerson; jill.a.mcleod@conocophillips.com; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Kenneth Luckey, King, Kathleen J (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck, Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Franger, lames M (DNR); Morgan, Kirk A (DNR); Pat Galvin; Bettis, Patricia K (DOA); Pete Dickinson; Peter Contreras; Richard Garrard; Robert Province; Ryan Daniel; Sandra Lemke; Sarah Baker, Peterson, Shaun (DNR); Pollard, Susan R (LAW); Talib Syed; Terence Dalton; Tina Grovier (tmgrovier@stoel.com); Todd, Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster; William Van Dyke; Ballantine, Tab A (LAW); Bender, Makana K (DOA); Bixby, Brian D (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Cook, Guy D (DOA); Crisp, John H (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Herrera, Matthew F (DOA); Hill, Johnnie W (DOA); Jones, Jeffery B (DOA); Kair, Michael N (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, lames B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Wallace, Chris D (DOA) Subject: Conservation Order 719 (Point Thomson Unit) 0 • Attachments: co719.pdf Please see attached. Samantha Carlisfe Executive Secretary 11 Alaska Oil and Gas Conservation Commission 333 -West 7" Avenue .Anchorage, AX 99501 (907) 793-1223 (phone) (907) 276-7542 (fax) CONFIDENTIALFFY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it and, so that the AOGCC is aware of the mistake in sending it to you, contact Samantha Carlisle at (907) 793-1223 or Samantha.Carhsle@alaska.gov. • • James Gibbs Jack Hakkila Bernie Karl P.O. Box 1597 P.O. Box 190083 K&K Recycling Inc. Soldotna, AK 99669 Anchorage, AK 99519 P.O. Box 58055 Fairbanks, AK 99711 Gordon Severson Penny Vadla George Vaught, Jr. 3201 Westmar Cir. 399 W. Riverview Ave. P.O. Box 13557 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Cory E. Quarles Richard Wagner Darwin Waldsmith Alaska Production Manager P.O. Box 60868 P.O. Box 39309 ExxonMobil Production Company Fairbanks, AK 99706 Ninilchik, AK 99639 P.O. Box 196601 Anchorage, AK 99519-6601 oka &(eL Oc�o►�e� ��e� 201� Angela K. Singh Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVAL CONSERVATION ORDER NO. 719.001 January 5, 2022 Mr. Todd Griffith, Asset Manager ExxonMobil Alaska Production, Inc. P.O. Box 196601 Anchorage, AK 99519-6601 Re: Docket Number: CO-21-028 Request for Administrative Approval to Clarify Point Thomson Unit IPS Findings Report Submission Date Thomson Oil Pool Point Thomson Unit Dear Mr. Griffith: By letter dated April 9, 2021, ExxonMobil Alaska Production, Inc. requested the Alaska Oil and Gas Conservation Commission (AOGCC) amend Rule 6 of Conservation Order No. 719 (CO 719) to indicate that the Initial Production System (IPS) Results Report are due by November 1, 2023. The AOGCC hereby GRANTS this request. Rule 6 of CO 719 requires the operator of the Thomson Oil Pool (TOP) to submit an IPS Results Report “[a]fter five years of sustained production under the IPS or 12 months before gas sales from Pt. Thomson are scheduled to begin, whichever comes first.” Production began from the TOP in April 2016; but during the first two and a half years of production and plant commissioning, the plant was rarely able to produce at full capacity for any length of time and was often offline completely. By November 2018, the plant was fully commissioned and operating stably for extended periods of time. Because of the frequent production upsets prior to November 2018, the data from April 2016 through October 2018 does not provide an accurate means by which to determine the reservoir performance, and in turn the viability of the gas cycling project in the TOP. Having the IPS Results Report due five years from reaching regular stable production at the plant’s designed capacity will provide a more accurate depiction of reservoir performance than to have it based on 2.5 years of erratic production followed by 2.5 years of steady production. 20 AAC 25.556(d) allows the AOGCC to administratively amend any order as long as the proposed change is based on sound engineering and geoscience principles, does not promote waste or jeopardize correlative rights, and the risk of fluids moving into freshwater is not increased. Defining a firm date CO 719.001 January 5, 2022 Page 2 of 2 for when the IPS Results Report is due is a purely administrative procedure so it will have no impact whatsoever on waste, correlative rights, or fluids moving into freshwater. Requiring the report to be submitted after five years of stable production at the plant capacity will ensure it has more useful data to evaluate performance than if the report was due five years after initial production commenced. Now therefore it is ordered that Rule 6 of CO 719 is repealed and replaced by the following : Rule 6 Initial Production System Results Report By November 1, 2023, or 12 months before gas sales from Pt. Thomson are scheduled to begin, whichever comes first, the operator shall submit a report to the AOGCC on the results and findings from conducting the IPS. The report shall include the following information: (a) A description of what the operator expected the IPS to show about the performance of the Thomson Oil Pool and the fluids contained within before the IPS project began producing; (b) A description of what the IPS actually showed about the performance of the Thomson Oil Pool and the fluids contained within; (c) A discussion, with appropriate supporting information, on whether or not the IPS showed the Thomson Oil Pool to be compartmentalized; (d) A discussion, with appropriate Pressure Volume Temperature data, on what the IPS showed about the reservoir fluid properties; and (e) A discussion on whether or not the development method proposed in this order is still the best method to optimize ultimate recovery and prevent waste. DONE at Anchorage, Alaska and dated January 5, 2022. Jeremy M. Price Daniel T. Seamount, Jr. Jessie L. Chmielowski Chair, Commissioner Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Dan Seamount Digitally signed by Dan Seamount Date: 2022.01.05 11:08:34 -09'00' Jeremy Price Digitally signed by Jeremy Price Date: 2022.01.05 13:03:47 -09'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2022.01.05 12:49:29 -10'00' From:Salazar, Grace (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] AOGCC Conservation Order No. 719.001 Date:Wednesday, January 5, 2022 3:08:19 PM Attachments:CO 719.001.pdf The Alaska Oil and Gas Conservation Commission has issued the attached administrative approval, granting ExxonMobil Alaska Production, Inc.’s request to amend Rule 6 of Conservation Order No. 719. Grace ____________________________________ Respectfully, M. Grace Salazar, Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Direct: (907) 793-1221 Email: grace.salazar@alaska.gov https://www.commerce.alaska.gov/web/aogcc/ __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: grace.salazar@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/grace.salazar%40alaska.gov AOGCC 333 W 7th Avenue, Anchorage, AK 99501 TO: BERNIE KARL K&K RECLYCLING, INC. PO BOX 58055 FAIRBANKS, AK 99711 Mailed 1/5/22gs INDEXES 7 From:Mayfield, Claire C To:Roby, David S (CED) Cc:EM Alaska Correspondence /SM Subject:RE: IPS Results Report status Date:Monday, April 12, 2021 11:24:24 AM Attachments:IPS_Findings_Report_Submission_Date_Letter_Signed.pdf Hi Dave, Please see attached letter in response to our conversations on the IPS Findings Report timing, and let me know if you or the commissioners have any questions. Thank you, Claire Campbell Mayfield Point Thomson Production Engineer ExxonMobil Upstream Oil & Gas Point Thomson Operations 3700 Centerpoint Dr., Suite 600 Anchorage, AK 99503 (907) 564-3651 Office / (713) 443-3631 Mobil From: Roby, David S (CED) [mailto:dave.roby@alaska.gov] Sent: Tuesday, March 23, 2021 4:40 PM To: Mayfield, Claire C <claire.c.mayfield@exxonmobil.com> Cc: EM Alaska Correspondence /SM <emalaskacorrespondence@exxonmobil.com> Subject: RE: IPS Results Report status External Email - Think Before You Click Hi Claire, You can send the letter to me and I’ll make sure it gets routed to the proper people. Also, I talked with the Commissioners about this and they agree that setting the date for sustained production to the point where the facility finally reached reliable stable production, as you’re recommending, is the way to go so there’ll be no problems having them sign off on this. Regards, Dave Roby 907-793-1232 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Dave Roby at 907-793-1232 or dave.roby@alaska.gov. From: Mayfield, Claire C <claire.c.mayfield@exxonmobil.com> Sent: Tuesday, March 23, 2021 4:32 PM To: Roby, David S (CED) <dave.roby@alaska.gov> Cc: EM Alaska Correspondence /SM <emalaskacorrespondence@exxonmobil.com> Subject: RE: IPS Results Report status Hi Dave, I appreciate your recommendation to create clarity; I will plan draft up a letter to the commissioner on PTU’s behalf. When you say submitted electronically, does that mean submitting through the aogcc.permitting@alaska.gov email address, or a different method? Thanks, Claire From: Roby, David S (CED) [mailto:dave.roby@alaska.gov] Sent: Wednesday, March 17, 2021 6:23 PM To: Mayfield, Claire C <claire.c.mayfield@exxonmobil.com> Cc: EM Alaska Correspondence /SM <emalaskacorrespondence@exxonmobil.com> Subject: RE: IPS Results Report status External Email - Think Before You Click Hi Claire, We never did define sustained production in the Pt Thomson Pool Rules (CO 719), nor do we define it in our regulations or statutes. We do however have a definition for “regular production” in our statutes, AS 31.05.170 defines regular production as “means continuing production of oil or gas from a well into production facilities and transportation to market, but does not include short term testing, evaluation, or experimental pilot production activities that have been approved by permit or order of the commission.” This definition is probably what we were thinking of in regards to sustained production but at the same time I don’t think anyone thought Pt Thomson would have the teething problems it did early on in terms of achieving planned rates and up time. I actually brought this point up with the commissioners prior to reaching out to you in regards to the IPS report status, so I think a case could be made and the commissioners would likely be amenable to define the commencement of sustained production as you propose, especially since the erratic production in the first couple of years wouldn’t really provide any insight into the viability of gas cycling as a recovery mechanism. I think probably the best and cleanest route, in terms of maintaining a record, to take would be for ExxonMobil to submit a letter, addressed to our chair Jeremy Price, formally requesting that the start of sustained production be defined as you propose below and outlining your reasoning for that. Then, assuming the Commissioners agree (which again I think they will) we’ll send a letter (maybe issue an admin approval to modify CO719 to specify the date of sustained production and when the IPS report is due) saying we concur. A request letter can be submitted electronically. Regards, Dave Roby 907-793-1232 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Dave Roby at 907-793-1232 or dave.roby@alaska.gov. From: Mayfield, Claire C <claire.c.mayfield@exxonmobil.com> Sent: Wednesday, March 17, 2021 5:39 PM To: Roby, David S (CED) <dave.roby@alaska.gov> Cc: EM Alaska Correspondence /SM <emalaskacorrespondence@exxonmobil.com> Subject: RE: IPS Results Report status Hi Dave, Hope you’re doing well. I wanted to follow up on your question regarding the IPS Findings Report. PTU interpreted the start of “sustained production” to begin in November of 2018 (up until that point, PTU hadn’t sustained full rate for more than a few weeks at a time), so we have in our plans to submit the IPS Findings Report in November of 2023. Let me know if the commission agrees with the planned submission date or has further questions and we can discuss. My phone number is 907-564-3651 if you’d like to talk over the phone. Best, Claire Mayfield From: Mayfield, Claire C Sent: Wednesday, March 10, 2021 1:40 PM To: Roby, David S (CED) <dave.roby@alaska.gov> Cc: EM Alaska Correspondence /SM <emalaskacorrespondence@exxonmobil.com> Subject: RE: IPS Results Report status Hi Dave, Just saw Kenley’s email today, let me check with our development team and get back to you. Thanks, Claire From: Scarlett, Kenley Sent: Tuesday, March 9, 2021 11:59 AM To: Roby, David S (CED) <dave.roby@alaska.gov>; Mayfield, Claire C <claire.c.mayfield@exxonmobil.com> Cc: EM Alaska Correspondence /SM <emalaskacorrespondence@exxonmobil.com> Subject: RE: IPS Results Report status Hi Dave, I have moved into a new role, and Claire Mayfield (cc’d) has taken over my prior position. Claire – can you provide Dave an update on the IPS report? Regards, Kenley Scarlett OIMS/EP&R Advisor ExxonMobil Alaska Production 3700 Centerpoint Drive, Suite 600 Anchorage, Alaska 99503 Skype: (907) 564-3606 Cell: (907) 290-1451 From: Roby, David S (CED) [mailto:dave.roby@alaska.gov] Sent: Tuesday, March 09, 2021 11:40 AM To: Scarlett, Kenley <kenley.scarlett1@exxonmobil.com> Subject: IPS Results Report status External Email - Think Before You Click Hi Kenley, Rule 6 of the Pool Rules for the Pt Thomson Oil Pool (CO 719) require a report on the Initial Production System after 5 years of sustained production. Production from the Pt Thomson commenced, albeit haltingly, in May 2016 which would mean the report required by Rule 6 will be due in a couple of months. I just wanted to make sure this requirement was on your radar and to see if you think ExxonMobil will be submitting the report at that time or will be seeking an extension? Thanks in advance. Regards, David Roby Senior Reservoir Engineer Alaska Oil and Gas Conservation Commission 907-793-1232 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Dave Roby at 907-793-1232 or dave.roby@alaska.gov. April 9th, 2021 ER-2021-OUT-070 Mr. Jeremy Price, Chair Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue, Suite 100 Anchorage, Alaska 99501-3572 Re: Point Thomson Unit IPS Findings Report Submission Date Dear Commissioner Price, ExxonMobil Alaska Production Inc. (EMAP) has received an email, dated March 17, 2021, from Dave Roby at the AOGCC, regarding Rule 6 of AOGCC Conservation Order No. 719 (CO 719). At Mr. Roby’s request, we are sending you this letter to confirm our intent to provide a Point Thomson Unit (PTU) Initial Production System (IPS) Findings Report under Rule 6 of CO 719 by November 1, 2023. As Mr. Roby notes in his email, Rule 6 requires EMAP to submit a report to AOGCC five years after the IPS achieves “sustained production.” In the context of Rule 6, it appears that this term is intended to ensure that AOGCC receives a complete, five-year picture of the performance of the reservoir from the IPS production data to evaluate the approved development method for the Thomson Oil Pool. As you are aware, from startup until November 2018, the PTU IPS was in an extended commissioning period. Until this date, the IPS facilities experienced periods of extended downtime and single -train operations and rarely operated at full capacity, and thus the reservoir and production data prior to this date is intermittent and is not useful for showing overall performance trends. In light of these facts, EMAP intends to conduct the reservoir performance evaluation of the IPS and submit the Findings Report contemplated by Rule 6 by November 1, 2023. Receiving this report with five years of data on sustained IPS production will facilitate a more comprehensive analysis of the IPS and the reservoir as intended by CO 719. EMAP will of course also continue to submit reservoir surveillance reports on an annual basis as required by Rule 5 of CO 719. If you have any questions or require additional information, please contact Claire Mayfield at (907) 564-3651. Sincerely, Todd Griffith CC: cm ExxonMobil Alaska Production Inc. P. O. Box 196601 Anchorage, Alaska 99519-6601 907 564 3607 Telephone Todd Griffith Asset Manager DocuSign Envelope ID: 39D2A002-07AF-4A3A-A6B6-4341D8309423 Certificate Of Completion Envelope Id: 39D2A00207AF4A3AA6B64341D8309423 Status: Completed Subject: Please DocuSign: IPS Findings Report Date Proposal Letter.docx Source Envelope: Document Pages: 1 Signatures: 1 Envelope Originator: Certificate Pages: 2 Initials: 0 Claire Mayfield AutoNav: Enabled EnvelopeId Stamping: Enabled Time Zone: (UTC-06:00) Central Time (US & Canada) Address Redacted claire.c.mayfield@exxonmobil.com IP Address: 158.26.2.168 Record Tracking Status: Original 4/9/2021 12:56:47 PM Holder: Claire Mayfield claire.c.mayfield@exxonmobil.com Location: DocuSign Security Appliance Status: Connected Pool: Main SecApp 1 Signer Events Signature Timestamp Todd Griffith todd.griffith@exxonmobil.com Asset Manager - Pt Thomson ExxonMobil General Security Level: Email, Account Authentication (None) Signature Adoption: Pre-selected Style Using IP Address: 47.221.73.100 Signed using mobile Sent: 4/9/2021 12:58:03 PM Viewed: 4/11/2021 8:31:56 AM Signed: 4/11/2021 8:32:27 AM Electronic Record and Signature Disclosure: Accepted: 3/26/2021 12:16:17 PM ID: 9ff541f8-11ab-4bb4-bd0c-2157352195db Company Name: Exxon Mobil Corporation In Person Signer Events Signature Timestamp Editor Delivery Events Status Timestamp Agent Delivery Events Status Timestamp Intermediary Delivery Events Status Timestamp Certified Delivery Events Status Timestamp Carbon Copy Events Status Timestamp Witness Events Signature Timestamp Notary Events Signature Timestamp Envelope Summary Events Status Timestamps Envelope Sent Hashed/Encrypted 4/9/2021 12:58:03 PM Certified Delivered Security Checked 4/11/2021 8:31:56 AM Signing Complete Security Checked 4/11/2021 8:32:27 AM Completed Security Checked 4/11/2021 8:32:27 AM Payment Events Status Timestamps Electronic Record and Signature Disclosure ELECTRONIC RECORD AND SIGNATURE DISCLOSURE Exxon Mobil Corporation (ExxonMobil) [1] uses the DocuSign service to collect signatures, endorsements, and approvals for corporate purposes. 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[1] ExxonMobil and/or ExxonMobil Affiliates mean (a) Exxon Mobil Corporation or any parent of Exxon Mobil Corporation, (b) any company or partnership in which Exxon Mobil Corporation or any parent of Exxon Mobil Corporation now or hereafter, directly or indirectly (1) owns or (2) contro ls, more than fifty per cent (50%) of the ownership interest having the right to vote or appoint its directors or functional equivalents ("Affiliated Company") and (c) any joint venture in which Exxon Mobil Corporations, any parent of Exxon Mobil Corporati on or an Affiliated Company has day to day operational control. Electronic Record and Signature Disclosure created on: 12/30/2016 6:17:43 AM Parties agreed to: Todd Griffith ExxonMobil Develop ent Company 22777 Springwoods Village Parkway Spring, TX 77389 September 3, 2015 US PT-PU-BALTR-00-000006 Ms. Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Keith E. Breiner, P.E. Technical Manager Point Thomson Unit Gas Expansion Project Re: ExxonMobil Alaska Production Inc. Response to Questions During Point Thomson Unit Pool Rules Public Hearing on September 1, 2015 Commissioner Foerster, SEP 08 2015 ExxonMobil Alaska Production Inc. (EMAP) appreciates the consideration given by the Commission to the application for Pool Rules for the Point Thomson Unit. We are providing the answers below in response to the questions that were raised during the hearing and for which the record has been held open until September 8. 1. Question: What would the calculated in -place volume be for the oil rim if the Oil/Water contact was assumed to be as deep as possible, by setting it at the base of the drill stem test (DST) interval? Answer: The calculated in -place volume for a 57 feet thick oil rim that results from this deeper oil/water contact assumption would increase to 241 million barrels, compared to our best estimate volume of 160 million barrels. 2. Question: What is the area of the Prudhoe Bay Unit (PBU) and how does that compare to the area of the Point Thomson Unit (PTU) ? Answer: The PBU area is about 160,000 acres. The PTU pool rule area is roughly half the size, at approximately 81,000 acres. 3. Question: What is the volume of water production expected to be after startup of the Initial Production System (IPS)? Answer: PTU-17 will be the producing well when full IPS production is onstream. PTU-17 is expected to produce less than 200 stock tank barrels per day of condensed water from the reservoir gas; the IPS facility water handling capacity is 1,000 stock tank barrels per day. If you have any further questions, please contact me at (832) 624-3763 or via email (keith.e.breiner@exxonmobil.com). For and on Behalf of ExxonMobil Alaska Production Inc. cc: Commissioner Seamount , ExxonMobf ," gin. • 0 1 ALASKA OIL AND GAS CONSERVATION COMMISSION 2 3 Before Commissioners: Cathy Foerster, Chair 4 Daniel T. Seamount 5 6 In the Matter of the Application of ) 7 ExxonMobil Alaska Production, Inc. for ) 8 the Establishment of Pool Rules Governing ) 9 Development of the Proposed Thomson Oil ) 10 Pool in the Point Thomson Unit. ) 11 ) 12 Docket No.: CO 15-08 13 14 ALASKA OIL and GAS CONSERVATION COMMISSION 15 Anchorage, Alaska 16 17 September 1, 2015 18 9:00 o'clock a.m. 19 20 VOLUME I 21 PUBLIC HEARING 22 23 BEFORE: Cathy Foerster, Chair 24 Daniel T. Seamount, Commissioner 1 TABLE OF CONTENTS 2 Opening remarks by Chair Foerster 03 3 Remarks by Mr. Breiner 08 4 Remarks by Ms. Dougherty 15 5 Remarks by Mr. Eleftheriou 43 6 Remarks by Mr. MacEachern 49 7 Remarks by Mr. Naymich 54 14 1 P R O C E E D I N G S 2 (On record) 3 CHAIR FOERSTER: I'd like to call this hearing 4 to order. Today is September 1st, 2015, it's 9:00 a.m. 5 We're located at the Anchorage Legislative Information 6 Office Building at 716 West Fourth Avenue, Anchorage, 7 Alaska. 8 To my left is Dan Seamount, Commissioner and 9 I'm Cathy Foerster, Chair of the AOGCC. 10 We're here today in reference to Docket number 11 CO 15-08, Point Thomson unit proposed pool rules. 12 ExxonMobil Alaska Production, Inc. by letter 13 dated July 16th, 2015 requests that the Alaska Oil and 14 Gas Conservation Commission issue an order under 20 AAC 15 25.250 which establishes pool rules governing 16 development of the proposed Thomson oil pool in the 17 Point Thomson unit. 18 Computer Matrix will be recording these 19 proceedings and you can get a copy of the transcript 20 from Computer Matrix Reporting. 21 Before we begin I'd like to thank the Alaska 22 Legislature for allowing us to use this conference room 23 and especially Senator Gary Stevens for offering this 24 as a solution to our space problem. And I'd like to 25 recognize that again Senator Giessel is in the room and 3 • 0 1 I made a big speech about her and the spelling of her 2 name last week and we'll forego that this week. 3 And I trust that the representatives from Exxon 4 are familiar with the purpose of this hearing and the 5 statutory authority of the AOGCC in this matter, but we 6 have folks in the audience today that may not be so 7 familiar so I'll just explain those things briefly for 8 their benefit. It'll probably save some time and 9 confusion as we proceed and help everyone with their 10 expectations on today's proceedings. 11 Exxon has requested a gas offtake rate of 1.1 12 billion standard cubic feet per day annual average 13 premised on a major sale development plan that will 14 produce gas for delivery to facilities of the Alaska 15 LNG project and produce liquid condensate for delivery 16 to the TransAlaska Pipeline System. The purpose of 17 this hearing is to gather sufficient information to 18 make a determination on this request and the other 19 components of the pool rules. The AOGCC's statutory 20 authority statutory authority requires that our 21 decisions in these matters be based on maximizing 22 greater ultimate hydrocarbon recovery and preventing 23 hydrocarbon waste. Although we can hear other 24 considerations, these two are overriding. 25 Looking at our sign in sheet it looks like we • 1 have about four or five -- five representatives of 2 Exxon who wish to testify and no one else from any -- 3 representing anyone else has signed up indicating that 4 they're going to testify. However if any other parties 5 become compelled to get up and say something we'll 6 provide that opportunity later. 7 So during testimony the Commissioners will ask 8 questions, we may also take a recess to consult with 9 staff to determine whether additional information or 10 clarifying questions is necessary. If a member of the 11 audience has a question that he or she feels should be 12 asked please submit that question in writing to either 13 Jody Colombie or Sam Carlisle, they're over to the side 14 doing the float wave. They will provide the question 15 to the Commissioners and if we feel that asking that 16 question will assist us in making our determination we 17 will ask it. If your question doesn't get asked I 18 apologize for your hurt feelings. 19 We will start by taking testimony from and 20 asking questions of the original applicant, Exxon. We 21 will then open -- we will then ask additional questions 22 and then open the hearing up to others who wish to 23 testify. A few reminders for people testifying. Keep 24 in mind that you must speak into the microphone so that 25 those in the audience, the court reporter and those on R 0 0 1 teleconference or watching the live feed can hear you. 2 Also please remember to reference your slides so that 3 someone reading this public record in the future can 4 follow along. For example refer to slides by their 5 numbers if numbered or their titles if not numbered, I 6 am now going to be addressing slide number 1, I'm now 7 going to be addressing the slide titled blah, blah, 8 blah. 9 We have a few ground rules on what is allowed 10 relative to testimony. First all testimony must be 11 relevant to the purposes of the hearing that I outlined 12 a few minutes ago and to the statutory authority of the 13 AOGCC. Anyone desiring to testify may do so, but if 14 the testimony drifts off subject we will limit it to 15 three minutes. Additionally testimony may not take the 16 form of cross examination. As I said before the two 17 Commissioners will be asking the questions. And 18 finally testimony that is disrespectful or 19 inappropriate will not be allowed. It happens. 20 Dan, do you have anything to add for the good 21 of the order? 22 COMMISSIONER SEAMOUNT: Nothing. 23 CHAIR FOERSTER: Okay. All right. Let's start 24 with Exxon. So before you begin let's work through the 25 administrative bits. Are you plan -- if you're J 1 planning to request an in camera session or present any 2 confidential testimony you'll need to be prepare to 3 preface that session with a description of what you 4 plan to present and if we do not agree if it warrants 5 confidential treatment then you will need to be 6 prepared to present it as nonconfidential or not 7 present it at all and not have it included in our 8 decision making process. Are you aware of that? 9 (No comments) 10 CHAIR FOERSTER: Okay. Do you have any plans 11 for confidential testimony? 12 MR. BREINER: No, not today. 13 CHAIR FOERSTER: Thank you. All right. Please 14 begin. And if -- are you the attorney? 15 MR. BREINER: I don't think so. 16 CHAIR FOERSTER: Okay. I mean, that makes it 17 simple, we have no attorneys up here. So I can swear 18 you both in. We don't trust attorneys to tell the 19 truth so we don't bother swearing them in. 20 All right. Please raise your right hand. 21 (Oath administered) 22 MR. BREINER: I do. 23 MS. DOUGHERTY: I do. 24 CHAIR FOERSTER: And as you're presenting 25 testimony we'll start with you introducing yourself, 0 • 1 saying who you represent and if you want to be 2 recognized by the Commission as an expert in a 3 particular area then you need to identify that area, 4 explain your qualifications and then allow us time to 5 choose to recognize you as an expert or not. So you 6 may begin. 7 KEITH BREINER 8 called as a witness on behalf of ExxonMobil Alaska 9 Production, Inc., testified as follows on: 10 DIRECT EXAMINATION 11 MR. BREINER: Good morning, Commissioner 12 Foerster, Commissioner Seamount. My name is Keith 13 Breiner, I've been an employee of ExxonMobil for 33 14 years and I'm the technical manager for the Point 15 Thomson gas expansion project. By way of background 16 I'm a graduate of the University of Illinois at 17 Champaign Urbana with both a bachelor's and master's 18 degree in civil engineering. I'm also a registered 19 engineer, licensed in the states of California and 20 Texas. 21 I will summarize the agenda today and then 22 introduce the experts that will walk -- that will walk 23 through their materials. And although I have 24 substantial relevant oil and gas experience I'm not 25 asking to be recognized as an expert today. E 0 0 1 CHAIR FOERSTER: So does your CEO share your 2 enthusiasm with a civil engineering degree? 3 (No comments) 4 CHAIR FOERSTER: Yeah. Okay. 5 MR. BREINER: We have four experts who will 6 testify today, they're in the areas of geoscience, 7 reservoir, drilling and facilities. I'll let them 8 introduce themselves and Sue and I have already been 9 sworn in, but we can swear them in as they come. 10 CHAIR FOERSTER: We'll swear them in as they 11 come up, that'll be fine. 12 MR. BREINER: On behalf of Point Thomson 13 working interest owners ExxonMobil Alaska Production, 14 Inc. submitted an application for Point Thomson pool 15 rules on July 16th, 2015 as you mentioned. The 16 information we will present today is all from that 17 application, but the materials we are not requesting 18 confidentiality on these. 19 Slide two provides an outline of the testimony 20 we will be presenting. We will cover a one page 21 background on the Alaska LNG project, the Point Thomson 22 field history, gas expansion project overview, geology 23 and reservoir, drilling and completion and facility and 24 operations. After these slides our reservoir engineer, 25 George Eleftheriou, will wrap -- will cover the W 1 proposed pool rules then I'll wrap up with a conclusion 2 side. 3 I'll be manning the laptop here today and have 4 others come up on the right so I'll be available to 5 answer any general project questions as -- as may 6 arise. 7 CHAIR FOERSTER: So we'll recognize you as an 8 expert as pushing the arrow forward and the arrow back. 9 MR. BREINER: I can work PowerPoint. We're 10 seeking to establish pool rules at this time to enable 11 each of the Point Thomson working interest owners to 12 access the potential sales opportunities of the gas 13 through the Alaska LNG project. 14 To provide some context for today's discussion 15 we've included slide three to give a high level 16 overview of the scope proposed by the Alaska LNG 17 project. Alaska LNG is an integrated, liquified 18 natural gas export project that would also provide 19 access to domestic gas for Alaska residents. The sixth 20 key scope elements are shown on the boxes of this 21 slide. The first two elements are transmission lines 22 that would move gas from Point Thomson and Prudhoe Bay 23 respectively to the gas treatment facility. The gas 24 treatment plant will process the gas and remove 25 impurities including carbon dioxide before sending 10 0 1 treated gas through a roughly 800 miles gas pipeline to 2 the liquefaction facility in Nikiski. At the 3 liquefaction facility the gas will be chilled to minus 4 260 degrees Fahrenheit where it's condensed by a factor 5 of roughly 600. The liquified gas then flows from 6 there to the LNG storage and marine terminal where 7 special ships designed to safely transport LNG can move 8 the gas, the liquified gas, to market around the world. 9 The AKLNG project is scheduled for start up in 2025. 10 On slide four you can see the Point Thomson 11 unit off to the right in yellow, it's about 60 miles 12 east of Prudhoe Bay and about 60 miles west of 13 Kaktovik. The nearest infrastructure is at Badami -- 14 at the Badami field roughly 22 miles to the west. The 15 Point Thomson unit was formed in 1977 and ExxonMobil is 16 the operator. There are 24 working interest owners 17 with these approximate splits. ExxonMobil is 62 18 percent, BP Exploration Alaska, Inc. is 32 percent, 19 ConocoPhillips Alaska, Inc. is 5 percent and there are 20 21 other owners with a combined working interest of 21 less than 1 percent. 22 CHAIR FOERSTER: So before we go into this 23 slide would you guys be okay if we put into the pool 24 rules that you're required to drill horizontal wells 25 into ANWR to prove that it's production? No, I'm just 11 0 • 1 kidding. 2 MR. BREINER: I would take no exception to that 3 requirement. 4 Slide five provides a simplified overview of 5 the scope for the initial production system project 6 which we refer to as IPS. That project is underway at 7 this point. You received information about IPS during 8 the recent Point Thomson unit hearing for an area 9 injection order that I believe was recently approved. 10 IPS includes the four wells referenced in the upper 11 left of this slide and the diagram in the lower center 12 illustrates what the project is designed to achieve. 13 IPS is a gas condensate -- gas cycling project to 14 produce liquid condensates for sale. The full well 15 stream, about 200 million standard cubic feet per day, 16 will flow from Point Thomson unit 17 well, also 17 referred to as the west pad well, with separation being 18 done in the gas processing facilities. The majority of 19 produced gas, that which is not used for fuel, will be 20 injected back into the reservoir from two central pad 21 wells, PTU-15 and 16, to preserve the gas for future 22 development. The liquid condensate up to 10,000 23 barrels per day, will be transported through the Point 24 Thomson export pipeline and ultimately into the 25 TransAlaska Pipeline System. In addition to producing 12 1 condensate the IPS project is helping to establish key 2 infrastructure that we'll be able to leverage for the 3 gas expansion project. 4 Any questions at this time? 5 CHAIR FOERSTER: Commissioner Seamount, do you 6 have any questions? 7 COMMISSIONER SEAMOUNT: No. 8 CHAIR FOERSTER: No questions. 9 MR. BREINER: Okay. Moving to slide six I'll 10 describe the work that is the basis for this 11 application for pool rules and gas offtake. The Point 12 Thomson gas expansion project is being designed to 13 develop the Point Thomson reservoir which contains 14 about 8 trillion cubic feet of original gas in place 15 which represents over 1 billion barrels oil equivalent 16 barrels and roughly 25 percent of the known North Slope 17 gas resources. Point Thomson gas and its associated 18 condensate will be separated and dehydrated through the 19 gas expansion project facilities. Processed gas will 20 be transported through the Point Thomson transmission 21 line and I mentioned that earlier, that's something 22 being under the Alaska LNG project scope, for further 23 processing at the Alaska LNG gas treatment plant which 24 will be located near Prudhoe Bay. The condensate from 25 the gas expansion project will be transported through 13 1 the Point Thomson export pipeline installed with the 2 initial production system and delivered into the 3 TransAlaska Pipeline System. The Point Thomson gas 4 expansion project is targeting start up for 2025. The 5 prefront end engineering and design work is proceeding 6 with a facilities design basis of 920 million standard 7 cubic feet per day. We're requesting an allowable 8 offtake of 1,100 million standard cubic feet per day to 9 allow for flexibility and potential capacity above name 10 plate as well as to allow for future de -bottlenecking 11 during operations. Ultimate hydrocarbon recovery at 12 Point Thomson is insensitive at these offtake rates. 13 Now unless there are any questions I'll turn it 14 over to Sue Dougherty who will cover the geoscience 15 slides. 16 CHAIR FOERSTER: Do you have any questions? 17 COMMISSIONER SEAMOUNT: I don't at this time. 18 CHAIR FOERSTER: I have one. Is the plan to 19 operate the IPS until 2015? 20 MR. BREINER: You mean until 2025? 21 CHAIR FOERSTER: 2025. Excuse me. I'm sorry. 22 MR. BREINER: Yeah, there will have to be a 23 shutdown at some point prior to the start up, you know, 24 to tie in appropriately, but..... 25 CHAIR FOERSTER: But the plan is to operate it 14 1 until..... 2 MR. BREINER: .....the plan is to operate until 3 we have to shut it down to..... 4 CHAIR FOERSTER: Okay. 5 MR. BREINER: .....progress major gas sales. 6 CHAIR FOERSTER: And you said that this offtake 7 doesn't impact ultimate recovery. What sensitivities 8 did you run, did you run -- well, I'll guess you'll get 9 into that in a bit. 10 MR. BREINER: Yes. 11 CHAIR FOERSTER: Okay. 12 MR. BREINER: The reservoir engineer will cover 13 some of those items. 14 CHAIR FOERSTER: Okay. Well, I'll wait for 15 that then. 16 MR. BREINER: Okay. 17 SUSAN DOUGHERTY 18 previously sworn, called as a witness on behalf of 19 ExxonMobil Alaska Production, Inc., testified as 20 follows on: 21 DIRECT EXAMINATION 22 MS. DOUGHERTY: Okay. So if you want to go to 23 page 7 or slide seven. 24 CHAIR FOERSTER: You'll need to introduce -- 25 okay. 15 1 MS. DOUGHERTY: That's right. So I'm Susan 2 Dougherty, I'm a geologist representing ExxonMobil 3 Alaska Production, Inc. I'd like to be recognized as 4 a technical expert. 5 CHAIR FOERSTER: And you're a geology [sic]? 6 MS. DOUGHERTY: I'm a geologist, that's 7 correct. I received a bachelor of science in geology 8 from University of California Santa Barbara in 1994 and 9 then went on to get a master's of science at the 10 Department of Earth Science at Montana State in 11 Bozeman. That was 1997. Originally hired by Exxon in 12 the fall of 197, in fact, tomorrow's my eighteenth 13 anniversary. I've worked a wide range of projects both 14 internationally and domestically including two ex 15 patriot assignments. About half my career has been 16 exploration and about the other half is drilling 17 development wells and conducting field studies for the 18 production company. I previously testified as an 19 expert at the area injection order hearing that was 20 last July. 21 CHAIR FOERSTER: Commissioner Seamount, do you 22 have any questions? 23 COMMISSIONER SEAMOUNT: I have no questions and 24 no objections. University of California automatically 25 qualifies you as an expert witness. 16 1 CHAIR FOERSTER: And I have no questions and no 2 problems. We recognized you before and we recognize 3 you again. 4 MS. DOUGHERTY: Okay. So the next few pages 5 are devoted to a description of the subsurface at Point 6 Thomson. We'll begin with geology, they've granted me 7 four slides. And this basic reservoir description's 8 very similar to the area injection order, what we 9 presented earlier. 10 I'd like to start with the upper left-hand 11 corner with the map. It's a Thomson depth map with 12 contour interval of a hundred feet. It's zoomed in 13 around the core of the field. The highest point on 14 structure is 12,500 feet tvd subsea, that's the deep 15 red blob over there to the right. The color contours 16 represent where the Thomson sand is present and the 17 gray contours are where the Thomson has been eroded and 18 it's the Pre -Mississippian basement present. The small 19 little scale on the lower right-hand corner, that 20 represents one mile. We've got faults represented in 21 black and although we observe faults in seismic we 22 don't observe them offsetting -- completely offsetting 23 the reservoir. Exploration wells drilled in the late 24 170s, early 180s are in the small font so for instance 25 PTU-1, PTU-3 is an example. And then the ITS wells 17 0 • 1 that Keith had described earlier are in red and in the 2 bold font. The PTU-15 drilled in 2009, PTU-16 drilled 3 in 2010 and then we'll be drilling the PTU-17 well this 4 winter, I'm quite excited about that. In addition we 5 drilled a disposal well, that's the blue dot, the PTU-1 6 disposal well, that TD'd in the upper Brookian and 7 April is when it's done. And then in white we've got 8 the gas expansion wells and those are just notional 9 locations at the time. Below left is a schematic 10 running through A to A prime and basically runs through 11 the bottom hole location of the PTU-15. 12 As you know geologists always like to describe 13 the rocks from the bottom up so we'll start from the 14 bottom. The gray is the lower Pre -Mississippian 15 basement, it's not included as a reservoir, but it 16 underpins the bottom of our model. In blue is the 17 upper Pre -Miss and that is included in our model, we 18 model it as a fractured reservoir with very modest 19 properties and we included it because there are parts 20 of the upper Pre -Miss that are above the fluid contacts 21 and those are shown here in the red, the gas/oil 22 contact and the oil/water contact is supposed to be 23 blue, it looks green here. The upper Pre -Miss is 24 unconformably overlain by the Thomson sand, that's 25 represented in yellow. And the shales comprising 1 claystone and siltstone are the Hue/HRZ shale and the 2 canning formation provide the seal. 3 And then I'll run through the bullet items on 4 the right. Primary resource is the gas cap in the 5 lower cretaceous Thomson sand. Porosity range is 5 to 6 34 percent, permeability .01 to 10,000 millidarcy and 7 we'll show you a pore perm plot on the next page. The 8 hydrocarbon accumulation is about a 500 foot gas column 9 with a thin, 37 foot heavy oil rim ranging from 10 to 10 18 degree API gravity. Through well tests and DSTs and 11 the exploration program we measure a H2S of 430 parts 12 per million and a CO2 of about 4 and a half percent. 13 And that condensate gas ratio, CGR, ranges from 50 to 14 65 stock tank barrels per million standard cubic feet. 15 Important this is a abnormally pressured reservoir so 16 for reference 10,100 at negative 12,700 tvd subsea. 17 We've drilled 22 wells in and around the unit, 18 16 of those penetrate to the Thomson. We've recovered 19 1,776 feet of Thomson conventional core, of course 20 geologists love that, and we've identified an upper and 21 a lower Thomson subunits partly from the core and also 22 using the logs. And you can see the PTU-3 well is an 23 example of that upper and lower Thomson. We have full 24 coverage over the unit 3D seismic and it's been 25 recently reprocessed in 2014. 19 9 • 1 Okay. As I understand you like to ask 2 questions toward the end so I'll just go ahead and go 3 to the next page if that's all right. 4 CHAIR FOERSTER: I'm starting to make my list 5 of questions. 6 MS. DOUGHERTY: Okay. I'm ready. All right. 7 Page eight addresses the reservoir quality. So sorry, 8 Keith, I'm going to jump around a little bit. 9 MR. BREINER: That's all right. 10 MS. DOUGHERTY: I'll start with the first 11 bullet. This is a classic reservoir comprising 12 conglomerates, sandstones and siltstones. And you'll 13 see on the left photo micrographs of some of these 14 rocks. The conglomerate's the orange and the red and 15 then we have some sandstone, silty sandstones, and then 16 some cemented conglomerate (indiscernible). These are 17 posted on a porosity permeability plot, very typical, 18 I'll just describe for the people in the back who maybe 19 can't see this, but X axis ranges from 0 to 40 percent 20 porosity and the permeability is on the Y axis, the 21 lowest number there is .001 and the last number that 22 you can read there is 10,000 millidarcy or 10 darcy. 23 For visual reference 1 darcy basically separates the 24 red dots from the orange dots and also note that we 25 have a couple of dozen points that are above 10 darcys 20 0 • 1 so these aren't just one off points, there's actually a 2 cluster of data that's above 10 darcy. 3 Going back to the bullet items we have six 4 petrofacies defined based on grain size, sorting and 5 ductal grain content. I call those photo micrographs 6 the family portrait so you notice that the siltstone is 7 not in the family portrait, it's not very photogenic, 8 it's two fine grained so that's why only five of them 9 are shown. As an example of the difference between the 10 conglomerate -- (indiscernible) conglomerate and the 11 open framework conglomerate is primarily sorting. The 12 difference between the clean sandstone and the siltly 13 sandstone is primarily ductal grain content, et cetera. 14 These petrofacies are color coded, they form logical 15 groupings in poroperm space and each petrofacies 16 defines its own poroperm trend and we use that in the 17 geologic model. We don't apply a net cutoff (ph) and 18 so instead we populate the model with the petrofacies 19 and then apply the appropriate porosity range and 20 permeability transform. 21 So we move to the bullets again where we 22 believe this is deposited in a fan delta setting so 23 that's alluvial fan deposits, reworked in a shallow 24 marine setting and we have a small schematic there 25 taken from McPherson, et al., 1987. This analog 21 0 • 1 translates to the environmental deposition map which is 2 in the lower right-hand corner and just kind of note 3 the scale by there is three miles. We envision that 4 the source of the (indiscernible) for the fan material 5 is to the northeast where the bough (ph) arch is today 6 and only erosional remnants of most of that alluvial 7 fan remain. The sediment was shed in a southwest 8 direction with the proximal facies of the foreshore and 9 upper shore face represented there in the yellow and 10 red and bright orange colors and the lower shore face 11 and offshore is in the peachy colored green. The open 12 framework conglomerate shown in the red dots with 13 exceptional reservoir quality so I'm addressing the 14 last bullet there has only been identified in the 15 recently drilled PTU-15 well and therefore we need to 16 adjust the predrill model to incorporate this new 17 petrofacies. This adjustment however was minor because 18 we found this new petrofacies in the context of the 19 proximal setting. So the PTU-15 TD'd up in this 20 direction in that proximal facies and that's where we 21 found the state petrofacies that we expect to be in a 22 proximal environment. Had we found it in the PTU-16 23 down here it would have been harder to explain, we 24 would have had to make a bigger edit so this was 25 actually in line with what the model was predicting. 22 1 CHAIR FOERSTER: You just answered one of my 2 questions. 3 MS. DOUGHERTY: Yep. However because we've 4 only seen this petrofacies in one well we are 5 distributing it sparingly in the model until we see 6 more of it in future wells. Before leaving this one 7 I'd just like to point out that the model shows 8 continuous facies bounds from the northwest down to the 9 southeast. While we think of fan material as being 10 point source the preserved material is reworked 11 sediments in a shallow marine setting and so we 12 currently envision this to be a very continuous 13 reservoir across the unit. 14 Okay. We'll go on to page nine. And this is 15 describing the fluid contacts. So we estimate the 16 fluid contacts using DST, drill stem tests, and MDT 17 tests. MDT is a vendor acronym for a modular dynamic 18 test at the downhole formation, a pressure fluid and 19 sampling tool. The gas/oil contact is estimated at 20 negative 12,975 tvd subsea and the oil/water contact at 21 negative 13,012 tvd subsea. We do expect these 22 contacts to be the same across the field, we don't see 23 strong evidence of compartments by facies or by 24 faulting as we kind of described earlier. Other 25 supporting evidence is shown on the right with the MDT 23 0 • 1 data from the PTU-15 and PTU-16. On the X axis we've 2 got pressure and those divisions are 10 psi's and on 3 the Y axis we have tvd subsea and depth with about 50 4 foot divisions. The bottom hole locations for these 5 two wells is 3.3 miles apart. The orange circles are 6 pressure measurements identified as gas from the PTU- 7 15. The red diamonds are pressure readings also 8 identified gas in the PTU-16. This well penetrated 9 deeper, that's why these points show up deeper. The 10 green square is a pressure reading identified as oil in 11 the PTU-16. There was a second oil sample measured, 12 but the pressure reading was invalid so we don't show 13 it on this pressure depth plot, but there were actually 14 two data points that identified oil. There are a 15 couple things that we can observe from this pressure 16 depth plot. One is that the gas/oil contact is now 17 better constrained by two points shown on the graph so 18 the lowest gas point identified was 12,973 and the 19 shallowest oil at 12,979. Second we also observe a gas 20 gradient, that gradient there is .15 psi per foot, very 21 common gas gradient. And third we see the pressure 22 gradients for the two wells are very well aligned with 23 each other suggesting they are in the same pressure 24 compartment and also the gradient is consistent from 25 upper to lower Thomson within the well, within that 24 1 stratigraphic unit from upper to lower. 2 And that's all I have for this slide so we'll 3 go on to page 10 and this is gas in place. So we 4 currently estimate the gas -- original gas in place to 5 be about 8 tcf. We estimate this volume using a 3D GSA 6 model which allows us to utilize those petrofacies and 7 the poroperm transforms in a fairly detailed manner. 8 The volume can basically be divided into three 9 categories, most of that gas, 87 percent is in that 10 Thomson sand gas cap. We use the depth maps, the 11 isacore (ph) is derived from the prestack depth 12 migrated seismic and obviously tied to the wells. The 13 porosity and the hydrocarbon saturation are based on 14 those petrofacies distribution and that comes from the 15 core description as well as that depositional model. 16 We do have a small amount of gas, about 5 percent, 17 that's in the Pre -Mississippian fractured basement. As 18 I mentioned these are modest properties, we do -- we 19 just pop in -- populate them uniform across the unit, 20 about 1 percent porosity and 78 millidarcys of vertical 21 permeability meant to mimic a fractured reservoir. And 22 then we have about 8 percent solution gas coming from 23 well to well in the gas cap and from the oil rim. And 24 those parameters are guided by the gas/oil ratio from 25 the well tests and DSTs. 25 1 In the upper right-hand corner we've got the 2 hydrocarbon pore volume map which I use just to show 3 the distribution of where the hydrocarbons are 4 concentrated. The warm colors are where the column 5 height and porosities are favorable, the cool colors 6 are where the column height's very thin and good 7 porosity or good facies are absent. Again we show 8 those IPS wells in red, the 15, the 16 and the 17. And 9 then we've distributed the gas expansion wells, the 10 white wells, to capture -- really to focus on that -- 11 where the hydrocarbon pore volume is greatest. 12 So that's the end of my material for 13 geoscience. 14 CHAIR FOERSTER: Thank you. 15 MS. DOUGHERTY: Asking questions? 16 CHAIR FOERSTER: Yeah, of course. Commissioner 17 Seamount -- and I want to thank you. Last week we had 18 a hearing on Prudhoe Bay and Commissioner Seamount was 19 difficult to live with because there was no geology for 20 him to play with and so thank you. 21 MS. DOUGHERTY: Unaccountable. 22 COMMISSIONER SEAMOUNT: Actually I think I -- 23 I'm going to ask less questions today than I did last 24 week even though there was no geology. 25 Well, thank you, Ms. Dougherty. I'm -- I have 26 1 a few questions. If we go back to slide number 7, 2 maybe I wasn't listening like I heard. Those contours 3 on that structure map, what are they -- what are 4 they..... 5 MS. DOUGHERTY: That's a depth map, top -- 6 depth map of the top Thomson. 7 COMMISSIONER SEAMOUNT: Top Thomson. Okay. So 8 when you talk about a gas/oil contact at about minus 9 13,000 feet we can just find minus 13,000 on this map 10 and that would be the aerial extent of the gas? 11 MS. DOUGHERTY: Yeah, this map is really 12 focused on the core of the field, where that 13 hydrocarbon pore line is. We did that specifically 14 just to -- because that's where most of the hydrocarbon 15 is and that's where the gas expansion wells will be, 16 but you're right, the contacts are just on the edge. 17 COMMISSIONER SEAMOUNT: Okay. So the map 18 doesn't show the total aerial extent of the reservoir; 19 is that correct? 20 MS. DOUGHERTY: That's correct. 21 COMMISSIONER SEAMOUNT: And as Chair Foerster 22 was talking about maybe it extends into ANWR? 23 MS. DOUGHERTY: Actually, no, we did not map 24 the reservoir into ANWR. 25 COMMISSIONER SEAMOUNT: That's unfortunate 27 1 because I would love to have a spacing exception from 2 you guys so that you could drill on that corner of 3 ANWR. 4 CHAIR FOERSTER: This isn't signaling, but we 5 would both be amenable to approving that. 6 COMMISSIONER SEAMOUNT: I'm not saying we would 7 approve it, but I would like to see it. 8 CHAIR FOERSTER: We'd be amenable to..... 9 COMMISSIONER SEAMOUNT: I mean..... 10 MS. DOUGHERTY: Part of the map extends to 11 where our 3D seismic is. 12 COMMISSIONER SEAMOUNT: I remember one time 13 Governor Murkowski asked me how close could we get to 14 ANWR if we drilled offshore of ANWR and I said well, 15 you just take a barge -- you just run it right up to 16 below high tide mark and we'll talk about a spacing 17 exception. 18 So if we look at the cross section the sand 19 sits right on top of the Pre -Mississippian basement, 20 what's the lithology of the basement? 21 MS. DOUGHERTY: So the -- it's metasedimentary 22 rocks so phyllites, quartzites and in parts of the 23 field are some dolomites. 24 COMMISSIONER SEAMOUNT: Are they the source of 25 the Thomson sand? ." • 9 1 MS. DOUGHERTY: No. The source for the 2 hydrocarbon is coming from the Hue/HRZ shale, also from 3 the -- now I've just lost the name..... 4 COMMISSIONER SEAMOUNT: That's okay. 5 MS. DOUGHERTY: Yeah, it's..... 6 COMMISSIONER SEAMOUNT: I was talking about the 7 lithologic source. 8 MS. DOUGHERTY: Oh, I'm sorry. So -- of the 9 sediment? 10 COMMISSIONER SEAMOUNT: Yeah, the sediment. 11 MS. DOUGHERTY: It's specifically for the 12 conglomerates, yes, the dolomite class and phyllite and 13 quartzite class in the conglomerates. 14 COMMISSIONER SEAMOUNT: Okay. Is there any 15 carbonate in the Thomson sand? 16 MS. DOUGHERTY: Not as we think of carbonate or 17 carbonate class. 18 COMMISSIONER SEAMOUNT: Okay. 19 MS. DOUGHERTY: So it's really a -- it's a 20 trydal (ph) reservoir with carbonate class in it. 21 COMMISSIONER SEAMOUNT: Do you have any idea of 22 -- I mean, from your 3D seismic what the range of 23 offset on the faults are, you say it's less than enough 24 to compartmentalize, but..... 25 MS. DOUGHERTY: Right. 29 1 COMMISSIONER SEAMOUNT: .....I mean..... 2 MS. DOUGHERTY: So the isacore for the Thomson 3 range is, you know, as you see it is eroded off so it 4 goes from zero, doesn't really get any bigger than 300 5 feet so I think the average is around 200 feet. And so 6 the maximum loss out of the faults I think has been 7 150. 8 COMMISSIONER SEAMOUNT: Okay. Okay. Let's go 9 to slide number 8. You show your -- the model of the 10 sand on the lower right-hand side. Are you saying that 11 this was a -- again I may not be listening very well, 12 but are you saying that this was an island with fan -- 13 alluvial fans coming off of it or was there a highland 14 that (indiscernible - simultaneous speech)..... 15 MS. DOUGHERTY: There was a highland. And the 16 source of the sediment we -- I had described as coming 17 from the bough arch, but the bough arch wasn't present 18 at the time of the Thomson. So the source of the 19 alluvial fan sediments was really coming we believe 20 from the back side of that dinkun grobin (ph) that you 21 -- that has been actually described in that USGS paper 22 that covers ANWR. So there's this dinkun grobin that's 23 off to the north, but the down -- it's down to the 24 north, but that's uplifted (indiscernible) flank and 25 we're shedding sediment off the back of that. It's 30 • 1 just right now it's where the bough arch is so you -- 2 it's erode -- mostly eroded. 3 COMMISSIONER SEAMOUNT: It's eroded. Okay. 4 MS. DOUGHERTY: But really it's telling us the 5 direction of that sediment is a rapid facies drop from 6 that northeast to the southwest. 7 COMMISSIONER SEAMOUNT: Okay. Now historically 8 out of curiosity how was this field discovered, did it 9 have -- take a number of wells to find it or did you 10 see this sand on seismic or..... 11 MS. DOUGHERTY: Well, that predates me. 12 COMMISSIONER SEAMOUNT: Yeah, it predates me. 13 MS. DOUGHERTY: However I do know that many of 14 those early exploration wells were looking for the oil, 15 they were chasing the oil rim looking for a thicker oil 16 leg and then finally just kind of went up dip and ended 17 up into the gas cap. 18 COMMISSIONER SEAMOUNT: Okay. So you were 19 talking serendipity then, more than we have seismic, we 20 can see it, we're going to go for that lump of sand? 21 MS. DOUGHERTY: Right. And the current seismic 22 that I'm using is 1989 acquired so I don't know what 23 kind of seismic they had, actually I -- that just 24 predates me. 25 COMMISSIONER SEAMOUNT: Okay. 31 • 0 1 MS. DOUGHERTY: Yeah. 2 COMMISSIONER SEAMOUNT: Thank you. That's all 3 I have. 4 CHAIR FOERSTER: I'm not a geologist so my 5 questions will be less learned than Commissioner 6 Seamount's. You talk about disposing into the upper 7 Brookian, from previous discussion I'm recalling that 8 there might have been some Brookian oil production 9 opportunities; is that true? 10 MS. DOUGHERTY: Not in the upper Brookian. So 11 the potential in the Brookian is limited to the lower 12 Brookian. That's that canning formation -- we call it 13 the canning formation. There have been some DSTs that 14 have recovered some oil and gas in that lower Brookian. 15 Oh, and it also makes up the seal. So the lower 16 Brookian is a very shaley unit and we envision it very 17 similar to Badami being in size (ph) cannon with a lot 18 of sand bypass. So occasionally you get a little 19 pocket of sand. So it's very discontinuous and, you 20 know, we're keeping an eye on it, but..... 21 CHAIR FOERSTER: So it has different production 22 challenges than the point -- than the Thomson sand 23 does? 24 MS. DOUGHERTY: very -- very different, right. 25 CHAIR FOERSTER: But it's shallower? 32 0 r: 1 MS. DOUGHERTY: It is above the Thomson 2 reservoir, right. 3 CHAIR FOERSTER: It's something that would be a 4 recompletion possibility? 5 MS. DOUGHERTY: Later in life, right. 6 CHAIR FOERSTER: Later in life. Okay. And do 7 you expect that it's going to be more oily or gassy or 8 do you not know enough to know? 9 MS. DOUGHERTY: It should be more oily. The 10 oil -- API gravity is I think 20 to 30 and it varies in 11 pressure, sometimes it's normal pressure, sometimes 12 it's in that pressure ramp so the deeper ones are a 13 higher pressure, but nothing close to what the Thomson 14 is. So it would be a very different pressure regime. 15 CHAIR FOERSTER: Okay. So you might not want 16 to wait too late in life because the TransAlaska 17 Pipeline has a lifetime. 18 So another question I had, you're very solid on 19 a 37 foot oil rim and I'm wondering if that confidence 20 in 37 feet has been gained with the drilling of the 21 latest wells because before these latest wells were 22 drilled I've heard conversations of anything from 50 to 23 150 foot thick oil rim so could you kind of 24 characterize the knowledge, you know, the transition of 25 the knowledge on the oil rim for me? 33 1 MS. DOUGHERTY: So the oil rim of course is 2 defined by gas/oil contact above and oil/water contact 3 below. This is a -- contacts are a bit difficult I 4 have to admit. This is a thin reservoir over a thick 5 gas cap so a lot of the wells are gas (indiscernible), 6 you don't see the fluid contact, you just see gas 7 (indiscernible). So in the down dip position where 8 we've got -- I think there's eight wells in the fluid 9 contact, five of those wells are in silty facies. So 10 again can't really use the logs to identify those fluid 11 contacts. So we rely heavily on those DSTs and DSTs 12 cover a range, right, there's a top and a bottom. So 13 prior to drilling the PTU-15, 16, we were using the 14 PTU-1 well that had an 87 foot DST in a well that made 15 both gas and oil. So we put the gas/oil contact 16 somewhere in the middle there. After we drilled the 16 17 and got those MDT results they're really better tightly 18 constrained by that gas/oil contact that dropped it 19 down 30 feet and it was -- it's in the range of that 87 20 foot DST, but obviously it's a tighter, better 21 constrained number. So that is that 12.9.75 and we 22 feel pretty good about them. The oil/water contact is 23 based off of a Staines River well, that's stayed the 24 same since the exploration program, that has really not 25 moved. And again that is a DST range, the DST made 34 1 both oil and water, but it's a 37 foot interval -- 57. 2 Sorry, 57 foot interval so there is some range in 3 there, but we put it at 12 -- sorry, 13.0.12. And 4 that's what defines our oil rim. 5 CHAIR FOERSTER: Okay. So your gas/oil contact 6 you feel pretty certain with, your oil/water contact 7 might have a little play? 8 MS. DOUGHERTY: Has a little bit of play, but 9 we made oil down to the -- a depth at the bottom of 10 that DST. 11 CHAIR FOERSTER: But so what -- how -- if it 12 has play would it get bigger or smaller or either 13 or..... 14 MS. DOUGHERTY: Right. So the Bates (ph) on 15 that DST, the maximum we could have it be is 57 feet. 16 CHAIR FOERSTER: Okay. So it's somewhere 17 between 37 and..... 18 MS. DOUGHERTY: And 57. 19 CHAIR FOERSTER: .....57. 20 MS. DOUGHERTY: But if you use that 57 it 21 doesn't quite explain that DST result because you did 22 make water in that so it would have had to cone up. 23 CHAIR FOERSTER: Okay. So if you use the 57 24 instead of the 37 how much of an impact on your oil in 25 place would it have? 35 1 MS. DOUGHERTY: Oh, I don't know off -- I don't 2 know that number off the top of my head. 3 CHAIR FOERSTER: Okay. 4 MS. DOUGHERTY: That compares -- that compares 5 with our predrill 15, 16 of -- you know, you take 30 6 feet up from the -- so we -- I have that number, I just 7 don't have it with me right now. 8 CHAIR FOERSTER: Okay. So I have this nasty 9 habit of asking questions that people say ooh, I don't 10 know, but I'll get back to you. So if somebody would 11 promise to keep a list of the questions I ask that I 12 get the ooh answer to..... 13 MS. DOUGHERTY: Okay. 14 CHAIR FOERSTER: .....we'll -- at the end of 15 the day we'll leave the record open for as long as 16 you..... 17 MS. DOUGHERTY: Okay. 18 CHAIR FOERSTER: .....think you need to..... 19 MS. DOUGHERTY: Okay. 20 CHAIR FOERSTER: .....to answer those 21 questions. And I'm not going to write down those 22 questions, but I'm going to count on you guys to do 23 that. Okay. All right. And so you were describing 24 that the driller of the 15 and 16 caused some changes 25 in your model and you said they weren't big, could you W 1 kind of characterize the model before and the model 2 after? 3 MS. DOUGHERTY: Yeah. So we tend to think of 4 the -- we tend to compare the predrill model, the early 5 model was really developed in 2001, 2002. It was a 6 much bigger model, had a lot of cells, really extended 7 far beyond the unit. And was -- because of that was 8 simple -- was sandstone conglomerate -- so it's 9 siltstone, sand and conglomerate, but it was still a 10 fan delta, basically it was still describing a fan 11 delta, it was describing sediment shed in all 12 directions. We've changed that now, we've tightened up 13 the model, that allows us to add more cells. We've 14 added more petrofacies so that we can describe that gas 15 in place better. So it's a better -- it's a -- more 16 refinement, more cells in the reservoir that we're 17 interested in. It does tend to show a lot of sediment 18 going down the southwest rather than shed in all 19 directions, but that northern part is off the unit so 20 it doesn't -- that's not a big impact. And that's the 21 biggest change although obviously we've incorporated 22 the gas/oil contact. We've added more detail on the 23 saturation height functions based on those petrofacies 24 so it's really more adding detail than it is making a 25 -- but that's a big change, right. 37 0 • 1 CHAIR FOERSTER: So the biggest change in the 2 models is that you refined it to a smaller area so that 3 you could put more data in? 4 MS. DOUGHERTY: More detail. 5 CHAIR FOERSTER: More detail. But you -- did 6 you -- to what degree did you make changes in the 7 description of the model? 8 MS. DOUGHERTY: As I said it was a fan delta 9 before, it's still a fan delta, it's still shedding in 10 the same direction. we didn't (indiscernible - it simultaneous speech)..... 12 CHAIR FOERSTER: (Indiscernible - simultaneous 13 speech) permeability -- new permeability data, new 14 porosity data, didn't change much? 15 MS. DOUGHERTY: I don't know what the 16 (indiscernible) transforms were before, but since there 17 were only three petrofacies instead now we've got these 18 six petrofacies. 19 CHAIR FOERSTER: So you made -- you've 20 made..... 21 MS. DOUGHERTY: Again..... 22 CHAIR FOERSTER: .....substantive changes in 23 the model? 24 MS. DOUGHERTY: Yeah, and it's again more of a 25 refinement. C: • 1 CHAIR FOERSTER: And you've made -- you've 2 refined your oil/water and your gas..... 3 MS. DOUGHERTY: Oil/water and then corrected 4 the depth maps since we drilled those two new wells. 5 CHAIR FOERSTER: I mean, so drilling two new 6 wells has enhanced the..... 7 MS. DOUGHERTY: Absolutely. 8 CHAIR FOERSTER: .....quality of the data and 9 changed the data? 10 MS. DOUGHERTY: And identified the open 11 framework conglomerate, yes. 12 CHAIR FOERSTER: Right. 13 MS. DOUGHERTY: So..... 14 CHAIR FOERSTER: Okay. So if you drilled 15 additional wells do you think you're going to make more 16 changes to your model? 17 MS. DOUGHERTY: Yes. 18 CHAIR FOERSTER: Okay. That was just a throw 19 down question. But could you characterize the size of 20 the productive area of the Point Thomson unit in the 21 Thomson sand in -- you know, 20 miles long by five 22 miles wide, you know..... 23 MS. DOUGHERTY: Actually so it -- we have this 24 on slide 20. we describe the oil pool as being, I've 25 got that number, 80,000 -- almost 81,00 acres..... 39 0 • 1 CHAIR FOERSTER: Okay. 2 MS. DOUGHERTY: .....as defining that oil pool. 3 That's..... 4 CHAIR FOERSTER: So how does that compare to 5 the size of Prudhoe Bay? 6 MS. DOUGHERTY: I don't know. Sorry, I 7 don't..... 8 CHAIR FOERSTER: Qualitatively, half as big, a 9 third as big, does anybody in the room know? You can 10 use a lifeline or you can get back to me on it. 11 COMMISSIONER SEAMOUNT: It would be a lot 12 smaller. 13 CHAIR FOERSTER: It's a lot smaller, but -- 14 one -tenth, maybe? 15 MS. DOUGHERTY: In -- as in terms of area are 16 you talking about or -- or volumes? 17 CHAIR FOERSTER: Surface area. 18 MS. DOUGHERTY: Yeah, I -- I'm sorry, I don't 19 know. I'd have to compare it later and get back to 20 you. 21 CHAIR FOERSTER: Okay. 22 MS. DOUGHERTY: I'm sorry. 23 CHAIR FOERSTER: But where I'm going with this 24 is you've got 20 wells roughly drilled in this and 25 Prudhoe probably has what, a couple thousand, and every 9 • 1 time they drill a well it doesn't come in exactly as 2 they expected it to. So the point I'm making is with 3 20 wells in an area that's one -tenth the size of 4 Prudhoe Bay, Prudhoe Bay's got a thousand or so wells 5 and they make changes every time. This mod -- you're 6 going to be refining this model until it's dead, right? 7 MS. DOUGHERTY: That's right. And, you know, 8 the model has 1 and a half million cells in it, are 9 they all absolutely correct, probably not, but we use 10 that as a way to characterize where the hydrocarbons 11 are, where to drill so it's -- it's a model. 12 CHAIR FOERSTER: It's a model. 13 MS. DOUGHERTY: Yeah. 14 CHAIR FOERSTER: Right. And the only thing you 15 can say about models is it's probably like a price 16 forecast, it will be wrong. 17 All right. That's all the questions I have. 18 Do you have any other questions? 19 COMMISSIONER SEAMOUNT: Just one. What's the 20 sensitivity of the a tcf number, what's the range? 21 MS. DOUGHERTY: So we have done a -- you know, 22 all those elements that go into estimating gas in 23 place, the depth map, isacores, the porosity, 24 saturation high functions, we have looked at a low side 25 and a high side, we've done a probablistic monte carlo 41 0 • 1 (ph) type estimation of what that low side, P10, P90, 2 it is a symmetric distribution, the P50 very similar to 3 the P90. And our best estimate of a tcf lands on that -- 4 very close to that best -- that P50 mean number. As 5 far as what those ranges are we're -- we prefer to 6 cover that under a confidential session. 7 COMMISSIONER SEAMOUNT: Okay. Did you consider 8 a tcf order of magnitude then, it's within an order of 9 magnitude? 10 MS. DOUGHERTY: Within, yeah. 11 COMMISSIONER SEAMOUNT: It's not 80 bcf? 12 MS. DOUGHERTY: No. 13 COMMISSIONER SEAMOUNT: And it's not 20 tcf? 14 Okay. 15 CHAIR FOERSTER: Okay. Thank you. 16 MR. BREINER: Unless there's that pocket that 17 reaches into ANWR that we're just not..... 18 MS. DOUGHERTY: Okay. We'll turn it over to 19 George Eleftheriou. 20 MR. ELEFTHERIOU: Good morning. 21 CHAIR FOERSTER: Good morning. We'll try to 22 pronounce your name better today than we did last time. 23 24 MR. ELEFTHERIOU: Should I begin? 25 CHAIR FOERSTER: So you should introduce 42 i 0 1 yourself and who you represent, would you like to be 2 recognized as an expert in what area, what are your 3 credentials. 4 MR. ELEFTHERIOU: Okay. 5 CHAIR FOERSTER: Oh, we have to swear him in 6 first. Thank you very much. 7 (Oath administered) 8 MR. ELEFTHERIOU: Yes, I do. 9 CHAIR FOERSTER: All right. 10 GEORGE ELEFTHERIOU 11 called as a witness on behalf of ExxonMobil Alaska 12 Production, Inc., testified as follows on: 13 DIRECT EXAMINATION 14 MR. ELEFTHERIOU: Okay. My name is George 15 Eleftheriou and I would like to be recognized as an 16 expert witness in the field of reservoir engineering. 17 CHAIR FOERSTER: And you represent ExxonMobil. 18 MR. ELEFTHERIOU: I represent ExxonMobil. I 19 received a bachelor of science degree in chemical 20 engineering from the University of Texas in Austin in 21 2012. I performed..... 22 CHAIR FOERSTER: Very good. Say no more. Just 23 kidding. 24 MR. ELEFTHERIOU: I have a whole list of things 25 here I wanted to talk about. 43 0 • 1 CHAIR FOERSTER: Please proceed. 2 MR. ELEFTHERIOU: I performed reservoir 3 modeling and analysis for Point Thomson for three years 4 and I've also testified in front of this Commission at 5 the Point Thomson area injection order hearing earlier 6 this year. Today I intend to testify about the 7 depletion plan for the gas expansion project and the 8 forecast of the model and results as well as other 9 field studies that we've performed. 10 CHAIR FOERSTER: Do you have any questions? 11 COMMISSIONER SEAMOUNT: No questions, no 12 objections. 13 CHAIR FOERSTER: The same for me. You may 14 proceed, Mr. Eleftheriou. 15 MR. ELEFTHERIOU: Thank you. Okay. So we're 16 on slide 11. This slide describes an overview of the 17 Point Thomson gas expansion depletion plan. The 18 objective of the gas expansion project is to produce 19 both natural gas and condensate from the Thomson sand 20 reservoir. This will be achieved by drilling seven new 21 wells and utilizing the three existing wells from the 22 initial development. The wells will be directional 23 from three pads. The central and west pads are already 24 constructed and the eastern pad will be built as part 25 of the project. The design gas production rate from 9 • 1 the facility is 920 million standard cubic feet per day 2 of actual gas and with the production of that gas 3 associated condensate will also be produced with an 4 initial peak rate of 57,000 barrels per day. And we're 5 also evaluating the installation of booster compression 6 to increase the overall hydrocarbon recovery and extend 7 the plateau life of the field. The figure on the left- 8 hand side of this slide displays a forecasted 9 production profile from the gas expansion project. The 10 annualized average gas rate is shown in red and the 11 condensate rate in green, water in blue and fuel gas in 12 orange. This forecasted production profile is a 13 product of our simulation modeling which predicts that 14 the Point Thompson reservoir can sustain a plateau 15 duration of about 15 to 16 years and the proposed 16 project results in recovery of approximately 75 percent 17 of the gas over its 30 year life span. This 18 corresponds to approximately 6 trillion cubic feet of 19 hydrocarbon export gas and 200 million barrels of 20 associated condensate. 21 So we'll move on to slide 12. On this slide we 22 are displaying a map which shows the notional well 23 locations for the Point Thomson gas expansion wells 24 within the Point Thomson unit. The black markers on 25 the coastline represent the three pad locations in 45 1 which the wells will be drilled from. You can see that 2 the wells begin on the surface and are directionally 3 drilled to subsurface locations that are offshore. The 4 red markers indicate the three wells that are included 5 in the initial gas cycling development and the white 6 markers are the seven new wells that will be drilled as 7 part of the gas expansion project. Our current design 8 basis includes one well off the western pad, three new 9 wells from the central pad and three new wells from an 10 eastern pad which will be constructed as well. 11 That's all I have for now, I'll be back. 12 CHAIR FOERSTER: Do you have any questions for 13 Mr. Eleftheriou? 14 COMMISSIONER SEAMOUNT: I don't think I do. 15 I'll -- I might have some questions later. Oh, by this 16 plot on slide number 11 it looks like you're going to 17 start out condensate production at about what, 60,000 18 barrels a day? 19 MR. ELEFTHERIOU: Around 57 peak, yeah. 20 COMMISSIONER SEAMOUNT: Oh, yeah. It's right 21 there. Okay. All right. That's all I have for now. 22 CHAIR FOERSTER: Okay. 23 COMMISSIONER SEAMOUNT: Thank you. 24 CHAIR FOERSTER: I have a couple of questions. 25 What is the status of the old wells, you're talking 46 1 about drilling some new wells, what's the status of the 2 wells that are already there? 3 MR. ELEFTHERIOU: My understanding is that most 4 if not all of them have been permanently abandoned. 5 CHAIR FOERSTER: Okay. That's all I have for 6 right now. 7 COMMISSIONER SEAMOUNT: I see a..... 8 CHAIR FOERSTER: Oh. 9 COMMISSIONER SEAMOUNT: .....you have a 10 well 10 development. Is that total that you have planned or 11 are you going to drill more in the future? 12 MR. ELEFTHERIOU: Yes, sir. Our total right 13 now, our development plans 10 total wells. Seven of 14 those would be new, but we would be utilizing the three 15 wells from the initial development. 16 COMMISSIONER SEAMOUNT: And you think that's 17 right now enough to recover most of the hydrocarbons? 18 MR. ELEFTHERIOU: Yes, sir, we believe it's 19 sufficient. 20 COMMISSIONER SEAMOUNT: Okay. 21 CHAIR FOERSTER: So if the -- if the Thomson 22 sand is not compartmentalized and you've got 23 permeabilities up to 10 darcys why do you need 10 24 wells? 25 MR. ELEFTHERIOU: Good question. That's 47 • 0 1 something we continue to evaluate, but ultimately we 2 want to ensure that should any failures occur or 3 perhaps the Thomson sand is not exactly what we expect 4 it to be, that we have enough capacity within our 5 facilities and our system to be able to provide the 920 6 million cubic feet for as long as possible. 7 CHAIR FOERSTER: Okay. So are there just 8 limits on the size of the well? 9 MR. ELEFTHERIOU: For right now we are 10 continuing to evaluate that, but we are assuming right 11 now in our plan which Jeff MacEachern our drilling 12 engineer will cover in a minute, that we'll be using 13 the same well design for the PTU-17 well which will be 14 drilled this year. 15 CHAIR FOERSTER: Okay. Okay. I'll save my -- 16 those questions for him then. Thank you. 17 MR. ELEFTHERIOU: Thank you. Well, I'll hand 18 it over to Jeff then right now. 19 CHAIR FOERSTER: Some new blood comes up. So 20 please raise your right hand. 21 (Oath administered) 22 MR. MacEACHERN: I do. 23 JEFF MacEACHERN 24 called as a witness on behalf of ExxonMobil Alaska 25 Production, Inc., testified as follows on: 1 DIRECT EXAMINATION 2 CHAIR FOERSTER: All right. So give us your 3 name, who you represent, would you like to be 4 recognized as an expert, in what area, and then your 5 credentials. 6 MR. MacEACHERN: All right. Good morning. My 7 name is Jeff MacEachern, I'm a drilling completion 8 engineer representing ExxonMobil an request to be 9 recognized an expert in drilling completion 10 engineering. I graduated from the University of 11 Alberta in 2005 with a bachelor of science degree in 12 chemical engineering and have been working as an 13 engineer on drilling completions and workover design 14 and operations for the past 10 years. I'm a 15 professional engineer licensed in the province of 16 Alberta. I've been working on the gas expansion 17 project since January of 2015 and have heavily 18 leveraged the experience of the drill team planning and 19 executing the current campaign. The group that I'm 20 part of does drilling and completion development 21 planning for ExxonMobil globally. 22 CHAIR FOERSTER: All right. Do you have any 23 questions? 24 COMMISSIONER SEAMOUNT: No questions, no 25 objections. .E 0 • 1 CHAIR FOERSTER: So you've been working on 2 Point Thomson since earlier in this year? 3 MR. MacEACHERN: That's correct. 4 CHAIR FOERSTER: Okay. And before that you 5 were where? 6 MR. MacEACHERN: So the group that I'm in we do 7 development for new opportunities around the world. 8 CHAIR FOERSTER: Okay. So where are you 9 located? 10 MR. MacEACHERN: I'm based out of Houston. 11 CHAIR FOERSTER: So you're still in Houston? 12 MR. MacEACHERN: That's correct. 13 CHAIR FOERSTER: Okay. All right. I have no 14 questions and no concerns. We recognize you as an 15 expert in drilling engineering. 16 MR. MacEACHERN: Thank you. 17 CHAIR FOERSTER: Please proceed. And I know 18 that the previous witnesses have testified before so 19 they're aware, but just remember start with talking 20 from slide number blah or I'll interrupt you and that -- 21 nobody likes that. So go ahead. 22 MR. MacEACHERN: Thank you. Slide 13 shows a 23 drilling completions design for the gas expansion 24 wells. Eight new wells are included in the reference 25 case development, seven of which would be new high 50 0 • 1 pressured gas producing wells and one new class one 2 disposal well. These wells will be drilled from 3 onshore pads, two of which are being used in the 4 current PTU drilling campaign. The preliminary design 5 for producers are planned to be similar to the PTU-17 6 well. PTU-15 and PTU-16 wells would be used as gas 7 producers also. Wells would be designed to contain all 8 reservoir fluids in accordance with ExxonMobil design 9 requirements and AOGCC regulations. The schematic on 10 the left-hand side shows a preliminary well design. 11 And this concludes the drilling completions 12 section. 13 CHAIR FOERSTER: So do you have any questions? 14 COMMISSIONER.SEAMOUNT: Yes. Could you point 15 out on that schematic where that shallower oil zone 16 would be located? 17 MR. MacEACHERN: That would be behind the 18 intermediate casing. I assume you're referring to the 19 Brookian? 20 COMMISSIONER SEAMOUNT: Oh, yeah. Okay. I see 21 it. Above minus 10,800 feet? 22 MR. MacEACHERN: Yes. 23 COMMISSIONER SEAMOUNT: Okay. And it would be -- 24 of course there would be cement across it. Would 25 there be any technical problems with, you know, years 51 1 down the road back -- going back in and recompleting in 2 that zone with that -- with that design? 3 MR. MacEACHERN: Don't believe so. The liner 4 lock where you'd have two strings of casing and two 5 cemented sheets would be relatively short so there's 6 nothing in the design of it preclude opening of 7 the Brookian at a later date. 8 CHAIR FOERSTER: So the liner lock is below the 9 Brookian? 10 MR. MacEACHERN: So I don't the exact depth, 11 but the liner lock would be relatively shorts, it's 12 hundreds of feet not thousands of feet. 13 CHAIR FOERSTER: Okay. So do you have any 14 plans for any class two disposal wells or strictly 15 staying with class one? 16 MR. MacEACHERN: It would be a contingency 17 disposal well similar to the one that's already -- 18 that's already been drilled earlier this year. 19 CHAIR FOERSTER: So you're only going to have 20 class one well -- disposal wells? 21 MR. MacEACHERN: Yeah. 22 CHAIR FOERSTER: Okay. Okay. And what kind of 23 metallurgy are you using? 24 MR. MacEACHERN: So we have not done detailed 25 metallurgy or material selection at this stage, but we 52 1 would use similar -- expect to use similar materials 2 for the PTU-17 so that they would be rated for sour 3 service and to handle the H2S and the CO2. 4 CHAIR FOERSTER: Okay. Okay. I don't have any 5 additional questions at this time. And I forgot to 6 remind everybody, but once you're under oath you're 7 under oath for the remain -- for the duration of the 8 hearing. So if you go away and come back up you're 9 still under oath, if we recess and come back you're 10 still under oath. 11 COMMISSIONER SEAMOUNT: Well, let's take it for 12 the rest of your life. 13 CHAIR FOERSTER: Okay. Done. Your mother 14 would like that. Okay. Thank you. 15 MR. BREINER: All right. Thank you. And our 16 facilities expert, Jerad Naymich, is now going to come 17 up. 18 CHAIR FOERSTER: And you know the drill I 19 think. Okay. 20 (Oath administered) 21 MR. NAYMICH: I do. 22 CHAIR FOERSTER: Okay. 23 JERAD NAYMICH 24 called as a witness on behalf of ExxonMobil Alaska 25 Production, Inc., testified as follows on: 53 1 DIRECT EXAMINATION 2 MR. NAYMICH: My name is Jerad Naymich and I'm 3 a process engineer representing ExxonMobil. I would 4 like to be recognized as an expert witness in 5 facilities engineering. I graduated from the 6 University of Texas in 2007 with a bachelor's degree in 7 chemical engineering. I worked as a process engineer 8 on the IPS starting in 2008 and I'm currently working 9 as a process engineer on the gas expansion project 10 before you today. 11 CHAIR FOERSTER: Do you have any questions? 12 COMMISSIONER SEAMOUNT: I have no questions, it 13 just seems strange there's so many people from the 14 University of Texas and only one person from California 15 and California population is higher than Texas. 16 CHAIR FOERSTER: Well, I think -- I think what 17 happened is Exxon has combined quality and quantity. 18 COMMISSIONER SEAMOUNT: I have no objections to 19 Mr. Naymich being considered an expert witness, but I 20 do have objections to your statement. 21 CHAIR FOERSTER: Well, I have objections to 22 several of yours so we'll just let that ride. So I 23 asked Mr. Eleftheriou when he testified last time, but 24 he wasn't aware, do they still give the Hamilton Watch 25 Award to the outstanding chemical engineering graduate? 54 1 MR. NAYMICH: I'm not aware either. 2 CHAIR FOERSTER: Oh, it wasn't you then, huh? 3 He wasn't aware either. So I have no questions and we 4 have no objections with accepting you as an expert in 5 process engineering. You may proceed. 6 MR. NAYMICH: The next three slides, beginning 7 with slide 14, will provide a summary of new facilities 8 infrastructure installed by gas expansion, the 9 integration with the IPS project and will also give 10 context to how gas expansion differs from the IPS. As 11 Keith mentioned the basic concept of gas expansion is 12 to deliver gas to AKLNG project facilities and export 13 condensate to PTEP, Point Thomson export pipeline. Gas 14 will flow to the GTP via a 32 inch above ground 15 transmission line installed by Alaska LNG. Custody 16 transfer of this gas will occur on the central pad at 17 the gas expansion facilities export pipeline interface. 18 Condensate will flow through the IPS -- IPS installed 19 12 inch PTEP which is sized to handle up to 70,000 20 barrels a day. Custody transfer for the condensate 21 will occur at the IPS module 103 via an expanded export 22 meter before entering PTEP. More details around the 23 custody transfer will be provided in the future as the 24 design mature. Gas expansion facilities is designed to 25 export 920 million standard cubic feet per day of gas, 55 1 this includes CO2 and nitrogen and 57,000 barrels per 2 day of condensate. The gas expansion facilities are 3 capable of producing 920 million standard cubic feet 4 per day in winter and summer months as the facilities 5 are not impacted by the majority of ambient conditions 6 experienced on the Slope. Now the reason for this 7 insensitivity to ambient conditions is that the gas 8 expansion facilities are driven primarily by reservoir 9 pressure and do not rely on compression to move gas to 10 GTP. 11 Gas expansion is a three well pad development. 12 East and west well pads will have multiphase metering 13 for well management. Each pad will also have methanol 14 storage and injection facilities used for start up 15 only. New facilities for gas expansion total roughly 16 25,000 tons of modules. Each module has a 5,900 ton 17 maximum design limit. Gas processing equipment is 18 tagged dehydration and expander for conditioning. Tag 19 dehydrates sufficiently for expander operation as well 20 as transport through the PPTL. Condensate will be 21 stabilized for transport via PTEP and ultimately to 22 TAPS. New east and west gathering lines will be 23 required for gas expansion project as the IPS west pad 24 line does not have sufficient capacity for gas 25 expansion facilities. All piping on and off pad will 56 0 1 be rated for the anticipated levels of CO2 and H2S. In 2 terms of integration with the IPS project the strategy 3 is to use IPS facilities to the maximum extent 4 practical. GE will use IPS operations camp, camp 5 utilities, maintenance and storage buildings as well as 6 the four diesel storage tanks, the gasoline storage 7 tank and methanol storage tank on central pad. Gas 8 expansion will tie into IPS utility systems such as 9 power generation, heating and cooling system among 10 others. New utilities will be added as required for GE 11 operation and we will cover the integration with 12 infrastructure on the next slide. 13 For the illustrations on this page on slide 14 14 the top image is a 3D rendering with gas expansion 15 facilities shown in color, existing IPS facilities are 16 shown here in light brown. The red future location for 17 booster compression is being considered, but these 18 modules will not be installed as part of the initial 19 gas expansion project. The lower image is a plot plan 20 and the -- showing the IPS process modules in the 21 middle of the page. Camp and other buildings are on 22 the top right, drilling area is towards the top left 23 and the blue box here shows the gas expansion module 24 location. 25 Slide 15 provides a high level of field layout 57 9 0 1 and shows how gas expansion integrates with IPS 2 infrastructure as well as new infrastructure that will 3 be installed by gas expansion. 4 First will be a brief walk through of the 5 illustration. The field layout shows west pad in the 6 upper left corner, central pad in the upper middle, 7 east pad towards the right side of the illustration. 8 West pad and east pad connect back to the central pad 9 through gravel roads. Gathering lines shown as dotted 10 lines here on the page connect east and west pads to 11 the central pad. Air strip is shown towards the bottom 12 middle of the diagram. The condensate export pipeline 13 and the gas export pipeline, PTEP and PTTL 14 respectively, run from the central pad to the left side 15 of the diagram, ultimately to Badami and gas treatment 16 plant. IPS installed infrastructure is shown in black 17 on this diagram and most will be used for gas expansion 18 project. Items integrated with gas expansion include 19 the central pad and west pad, wells at central pad and 20 west pad, the condensate line to Badami, the air strip 21 and marine facilities at the central pad for barge 22 offloading. New gas expansion install infrastructure 23 is shown in green and include central pad expansion 24 which were the two illustrations on the previous page, 25 east pad and east pad road as well as the east and west 1 gathering lines. Also shown on this diagram is a blue 2 dotted line and that represents the new gas export line 3 installed by AKLNG. 4 Moving to slide 16. This is an overview of the 5 key differences between the IPS and gas expansion 6 facilities. IPS facilities were specifically designed 7 for high pressure separation to facilitate compression 8 for injection at 10,000 psi. Gas expansion however is 9 optimized for gas export at 1,060 psi. The different 10 purposes require different gas processing facilities. 11 Gas for export requires dehydration and conditioning 12 which is the removal of heavy hydrocarbons while 13 injection requires only compression. The table shows a 14 quick comparison of liquid export rates, gas handling 15 rates, water handling as well as facility inlet and 16 outlet pressures between the two projects. Gas 17 expansion is a much larger project and operates at a 18 lower pressure. They're the main differences between 19 the facilities. A simple (indiscernible) flow diagram 20 at the bottom shows that IPS and gas expansion are 21 similar as they both have inlet separation, condensate 22 stabilization and export liquids to PTEP. Gas treating 23 however is different. The IPS compresses for injection 24 while gas expansion dehydrates and conditions its gas 25 for export. Heavy hydrocarbons are removed and sent 59 1 back to separation train for further stabilization. 2 If there are no further questions I will allow 3 George to summarize the pool rules. 4 CHAIR FOERSTER: Oh, there'll be questions. 5 Commissioner Seamount, do you have any questions for 6 Mr. Naymich? 7 COMMISSIONER SEAMOUNT: Just one or two. On 8 slide number 16 you have gas handling for the -- water 9 handling for the IPS of 1,000 barrels a day. What do 10 you expect the start up water production to be? 11 MR. NAYMICH: Right now the significant portion 12 of our water, the 10,000 barrels a day, comes late in 13 life. We don't expect the 10,000 barrels a day coming 14 on soon. 15 COMMISSIONER SEAMOUNT: But the -- for the IPS, 16 1,000 barrels a day, that's not coming on right away, 17 is it? 18 MR. NAYMICH: Well, that's also facility 19 design. I don't think that's the anticipated rate. 20 COMMISSIONER SEAMOUNT: Right. Right. Okay. 21 How much water do you expect? 22 MR. NAYMICH: Oh, I -- I'm not aware of what 23 the profile suggests. 24 MR. ELEFTHERIOU: We could follow-up with you 25 on that. Z1 • 1 COMMISSIONER SEAMOUNT: Okay. Thank you. 2 That's all I have. 3 CHAIR FOERSTER: Okay. So that'll be another 4 question we'll get an answer to later. You mentioned 5 multiphase metering, is that going to be custody 6 transfer because..... 7 MR. NAYMICH: That would be more for well 8 management..... 9 CHAIR FOERSTER: For well management. Okay. 10 MR. NAYMICH: .....or for (indiscernible - 11 simultaneous speech) well management. 12 CHAIR FOERSTER: Okay. So what do you plan for 13 your custody transfer metering? 14 MR. NAYMICH: The details on custody transfer 15 metering we have not worked out yet between AKLNG and 16 between gas expansion. It will include the CO2 and it 17 will be a dry gas that we export. 18 CHAIR FOERSTER: Okay. So you're aware that 19 you need to..... 20 MR. NAYMICH: Yes. 21 CHAIR FOERSTER: Okay. I'll finish the ques -- 22 I saw the head sign, but you're aware that you need to 23 get approval from the AOGCC on your custody transfer 24 metering details? Yeah. We hate when someone doesn't 25 know that and comes out and goes it's already there, 61 0 0 1 give me approval when they should have known. 2 Okay. Compressors. You have no use for the 3 compressors during the gas production phase? 4 MR. NAYMICH: The intent for our concept is to 5 not run the injection compressors during gas expansion. 6 CHAIR FOERSTER: Well, right. You're not going 7 to inject, but do you have any other -- will you have 8 any other use for the compressors? 9 MR. NAYMICH: No, they will not fit the use. 10 We have a compressor with -- inside the facility and 11 they..... 12 CHAIR FOERSTER: I'm sorry, what? 13 MR. NAYMICH: We have a compressor inside the 14 gas expansion facility. And that would -- those 15 compressors would not fit that purpose. 16 CHAIR FOERSTER: So the sole purpose of the 17 compressors is for the IPS? 18 MR. NAYMICH: Correct. 19 CHAIR FOERSTER: Okay. They weren't cheap, 20 were they? 21 MR. NAYMICH: Sorry. 22 CHAIR FOERSTER: They're not cheap compressors, 23 are they? 24 MR. NAYMICH: They're not. 25 CHAIR FOERSTER: Okay. All right. I have no 62 1 other questions at this time. Thank you. 2 Just reintroduce yourself for the record. 3 MR. ELEFTHERIOU: Sure. This is George 4 Eleftheriou, reservoir engineer. 5 Okay. We are on slide 17 which is describing 6 the offtake requirement. So this slide is kind of 7 describing our approach to determine the annual average 8 offtake request of 1,100 million cubic feet per day. 9 So the facilities are designed to handle 920 million 10 cubic feet a day of export gas which include 11 hydrocarbon and non -hydrocarbon gas such as carbon 12 dioxide and nitrogen. In addition to this the 13 facilities will also require 8 million cubic feet per 14 day of fuel gas and that will increase to 28 million 15 cubic feet per day with the installation of booster 16 compression in the future. We're requesting an offtake 17 rate above the current design basis to produce more gas 18 if we experience higher operating up time and de- 19 bottlenecking of the facilities as we gain more 20 operating experience. A higher offtake rate will not 21 negatively affect the recovery of gas and condensate 22 from the reservoir. We have forecasted production 23 profiles with offtake rates ranging from 400 to 1,200 24 million cubic feet per day using simulation modeling 25 techniques and we have found no impact on ultimate M 1 recovery. Ultimately an increased export rate from 2 Point Thomson provides some acceleration of gas and 3 condensate production while maintaining overall 4 hydrocarbon recovery from the reservoir. 5 So I'm going to move on to another subject 6 after this, I don't know if we want to..... 7 CHAIR FOERSTER: I'll save my questions. 8 MR. ELEFTHERIOU: Okay. Sure. 9 CHAIR FOERSTER: Okay with you? 10 COMMISSIONER SEAMOUNT: Yeah. 11 CHAIR FOERSTER: Okay. 12 MR. ELEFTHERIOU: So the next several slides 13 will describe development considerations that were 14 assessed in the course of selecting the gas expansion 15 project as the best option. 16 Slide 18 addresses the oil rim that exists 17 beneath the Point Thomson gas cap. We've evaluated the 18 oil rim several times and come to the conclusion that 19 it is not a viable development. We estimate that the 20 oil rim is a thin, 37 foot hydrocarbon zone that 21 underlies the gas in the Thomson reservoir and contains 22 approximately 160 million barrels of oil in place. The 23 oil is dense and viscous which makes it challenging to 24 flow into a well. Our simulation studies have shown 25 that wells drilled into the oil rim very quickly begin 64 1 to produce gas and water. This affect is known as 2 coning and it occurs because the oil rim is thin and 3 the gas and water can preferentially flow into the well 4 due to their lower viscosities compared to the heavy 5 oil. The two figures on the bottom of this slide show 6 simulation results of gas and water coning behaviors on 7 a horizontal well after just 90 days of production. 8 This means that the oil recovery per well is very low 9 and many wells would have to be drilled in order to 10 recover a significant amount of the oil rim. This 11 would require expensive wells and additional processing 12 facilities which all contribute to our assessment 13 regarding the viability of the oil rim. 14 Okay. So on slide 19 we're addressing expanded 15 gas cycling which is another approach for the Thomson 16 sand that we've evaluated. Similar to the initial 17 development gas and condensate would be produced from 18 the reservoir, but the gas would be reinjected for 19 production at a later time. ExxonMobil has done 20 significant reservoir simulation and engineering design 21 work for this concept most recently in 2002. The major 22 challenges of large scale gas cycling at Point Thomson 23 are that the reservoir pressure is very high and 24 requires large, expensive compression to reinject the 25 gas and the overall amount of condensate that is ON 1 produced with the gas is not sufficient to make a 2 viable stand alone project. In evaluating this 3 approach a study was performed in 2006 that considered 4 a depletion mechanism of 230 gas condensate fields as 5 analogs to Point Thomson. The result of that study 6 indicated that no reservoirs cycle gas at pressures as 7 high as Point Thomson and the vast majority of the 8 fields were developed using primary depletion in the 9 form of gas sales. In addition recent simulation 10 studies have indicated that performing a gas cycling 11 project followed by a gas sales project would not 12 materially increase overall hydrocarbon recovery from 13 Point Thomson. If gas cycling were commenced it would 14 defer gas sales which may adversely impact the timing 15 of Alaska LNG which is currently the best opportunity 16 to produce gas and condensate from Point Thomson. 17 Ultimately production of the Point Thomson gas 18 reservoir by primary depletion in the form of gas sales 19 increases overall hydrocarbon recovery and is 20 consistent with industry practices for gas condensate 21 reservoirs. 22 So next two slides will be describing the pool 23 rules if we want to continue or..... 24 CHAIR FOERSTER: Please do. 25 MR. ELEFTHERIOU: Okay. So at this time I'd • 1 like to read in the proposed pool rules that we are 2 requesting. Rule one is a field and pool name. The 3 field is the Point Thomson field and the pool is 4 defined as the Thomson pool. Rule tool -- rule two, 5 sorry, definition of pool. The Thomson pool is defined 6 as the accumulation of hydrocarbons corresponding to 7 depths 16,126 feet to 16,377 feet measured depth or 8 negative 12,614 to negative 12,828 feet true vertical 9 depth subsea on the PTU-15 type log and continued 10 within the area described in table 14.0-1 in our 11 application. 12 Moving on to slide 21. Rule three, the gas/oil 13 ratio exemption. Wells producing from the Thomson pool 14 are exempt from the gas/oil ratio limits of 20 AAC 15 25.240(a). The regulation states that an oil well may 16 not be produced if the gas/oil ration of the well 17 exceeds the original solution gas ratio of the crude 18 within the producing pool by more than 100 percent. 20 19 AAC 25.240(c) provides authority for the Commission to 20 grant an exception to this limitation. Under the AOGCC 21 regulations PTU wells are considered aerial wells if 22 the GOR is less than 100,000 standard cubic feet per 23 stock tank barrel. The initial Point Thomson gas 24 expansion wells producing GORs will be less than 20,000 25 standard cubic feet per stock tank barrels. So our 67 1 proposed development plan contemplates exceeding the 2 initial GOR by 100 percent in about 10 years. So a 3 waiver from 20 AAC 25.240(a) is required. 4 CHAIR FOERSTER: So what you're saying here 5 basically is that by our definition these wells are oil 6 wells? 7 MR. ELEFTHERIOU: Yes, ma'am. 8 CHAIR FOERSTER: Okay. So I told the 9 Legislature that repeatedly so I'm glad to have one 10 witness from the Legislature hear somebody other than 11 me say that. Thank you. 12 MR. ELEFTHERIOU: Okay. Slide 22. Rule four 13 is the allowable gas offtake rate. The maximum 14 allowable annual average gas offtake rate from the 15 Thomson pool is 1,100 million standard cubic feet per 16 day. And finally rule five, administrative action. 17 Upon proper application or its own motion and unless 18 notice and public hearing are otherwise required the 19 Commission may administratively waive the requirements 20 of any rule stated herein or administratively amend 21 this order as long as the change does not promote waste 22 or jeopardize correlative rights and is based on sound 23 engineering and geoscience principles and will not 24 result in an increased risk of fluid movement into 25 freshwater. CJ • 1 Those are my slides for now. 2 CHAIR FOERSTER: All right. Do you have any 3 questions? 4 COMMISSIONER SEAMOUNT: Yes, I do. If we go 5 back to slide 19 you've got a number of good arguments 6 for not going with gas cycling, but why is it not 7 viable, in other words -- well, maybe there's two 8 questions here. why is it not viable and would gas 9 cycling give -- make a profit for Exxon if you went 10 that route just less of a profit than what you're 11 proposing today? 12 MR. ELEFTHERIOU: I'm not sure I can comment on 13 the specific economics involved, but gas cycling would 14 be very challenging from a facilities and additional 15 cost and wells needed in order to perform it and 16 ultimately our modeling suggests that the recovery of 17 hydrocarbons, the additional hydrocarbons from cycling, 18 would be not materially different from just using 19 primary depletion in the form of gas sales. So 20 spending additional cost to develop the facilities to 21 do cycling and deferring the gas sales would not for 22 basically a, you know, nonmaterial hydrocarbon benefit 23 is not preferential. 24 MR. BREINER: Yeah, to elaborate a little bit 25 on that. Our modeling suggests that if you cycled for ZE 1 10 years before you started major gas sales or if you 2 cycled for 20 years before you started major gas sales 3 the potential incremental recovery would be in the 4 order of 2 percent to 3 percent respectively for those 5 two cases. And that assumes no risking, no deductions 6 to those flow rates to reflect the substantially high 7 risk associated with expanded cycling. So if those 8 vaults were actually present, there was 9 compartmentalization in the reservoir that would be a 10 reduction from those 2 to 3 percent. So if you looked 11 at this in terms of, you know, what it looks like as a 12 project you'd spend substantially more money up -front, 13 basically require two projects, first an expanded cycle 14 -- three if you included IPS, and then you make that 15 substantial up -front investment, have two additional 16 project campaigns, all to have your oil equivalent 17 hydrocarbons potentially reach the level you would have 18 had if you'd started major gas sales around years 50 or 19 60, you know, from today. So it's a lot of money up- 20 front, you might get as much as 2 percent 30 years plus 21 into the future is the way it looks. 22 COMMISSIONER SEAMOUNT: And that -- that's by 23 adding risk to your..... 24 MR. BREINER: That's without adding risk. The 25 2 to 3 percent is assuming you have ideal cases for O 1 cycling, it's an homogenous reservoir and you don't get 2 premature breakthrough, channeling, 3 compartmentalization or any of those other risk. And 4 it also doesn't factor in the higher facilities risk of 5 trying to say can you really run something out there 6 for, you know, 40, 50 years to deplete -- to develop 7 the reservoir. And of course then you have the 8 potential jeopardy to Alaska LNG and it counting on the 9 gas from Point Thomson for that project. 10 COMMISSIONER SEAMOUNT: Yeah, we're not 11 mandated to consider that. Sorry, Senator Giessel. 12 But -- okay, I think I understand what you're saying. 13 That's all I have. 14 CHAIR FOERSTER: That's all you have. Okay. 15 COMMISSIONER SEAMOUNT: Oh, I did have one more 16 question. 17 CHAIR FOERSTER: Go for it. 18 COMMISSIONER SEAMOUNT: Sorry about that. 19 Fifteen years ago -- I've been on this job way too 20 long, but talking about the oil rim, the numbers that I 21 was given were huge compared to 160 million barrels 22 that we hear about today. Why did that number go down 23 so much, is it just because you determined that it was 24 thinner than you thought? 25 MR. ELEFTHERIOU: I can't really comment on the 71 0 • 1 previous basis, but I do know as we've acquired more 2 data and by drilling more wells and subsequent analysis 3 that 160 million barrels in place is representative of 4 our best technical estimate of the oil in place at this 5 time. 6 COMMISSIONER SEAMOUNT: Somebody told me a 7 billion barrels, but I'm not sure it was Exxon. It's 8 been a long time ago. 9 CHAIR FOERSTER: All right. Slide 17. You 10 said that higher gas production doesn't affect 11 recovery, but am I correct in saying that taking your 12 future slides and then your answers to Commissioner 13 Seamount that any gas production only has a 1 percent 14 impact, takes it from 3 percent down to 2 percent; is 15 that correct? 16 MR. ELEFTHERIOU: You're talking about ultimate 17 hydrocarbon recovery? 18 CHAIR FOERSTER: Gas -- oil recovery. Oil 19 recovery. 20 MR. ELEFTHERIOU: Oil recovery. I guess I'm 21 not really sure if I understand. 22 CHAIR FOERSTER: Let me ask the question more 23 clearly. When you were talking to slide 17 you said 24 that the wait sensitivity was minimal, that no matter 25 what the offtake was -- the gas offtake was it didn't 72 1 have a lot of impact on ultimate condensate recovery. 2 What if that offtake was zero, what is that impact on 3 condensate recovery? 4 MR. ELEFTHERIOU: Well, that would mean that 5 we're not taking gas out of the reservoir and we have 6 no project to produce the condensate beyond just the 7 IPS project right now. 8 CHAIR FOERSTER: Well, you know what I'm 9 talking about, I'm talking about taking, you know, the 10 text produce a condensate reservoir through cycling 11 until you got the condensate out and then go to gas. 12 What impact does that case have on ultimate recovery of 13 condensate? 14 MR. ELEFTHERIOU: Yes, ma'am. So that -- 15 that's referred to in our -- in the cycling studies 16 that we've done, the 10 or 20 years, and the overall 17 net impact is perhaps 2 to 3 percent overall. And that 18 is without any sort of risk or anything, we've assumed, 19 you know, best -- best possible scenario. 20 CHAIR FOERSTER: Okay. 2 to 3 percent. So the 21 -- what is the total estimated condensate recovery -- 22 so what is a vol -- what does 2 percent mean, does it 23 mean 10 barrels, 10,000 barrels, half a million 24 barrels, what is 2 percent? 25 MR. ELEFTHERIOU: 2 percent represents the 73 0 s 1 overall hydrocarbon, both gas and condensate. 2 CHAIR FOERSTER: In equivalent barrels what 3 does that represent in volume? 4 MR. ELEFTHERIOU: I'm not really sure if we're 5 prepared to discuss the specific volumes in..... 6 MR. BREINER: Well, we could -- if you want to 7 discuss more about cycling and how those recoveries 8 change we could do that in a confidential session at 9 the end. 10 CHAIR FOERSTER: Okay. We're going to get to a 11 point where we're going to ask why is that confidential 12 and you're going to have to give reasons. So you might 13 want to think real hard if you can tell me volumes 14 without going into confidential section and I'll let 15 you come back to that. 16 Okay. Slide 18. Just for the general public, 17 I mean, you talk -- I understood you when you're 18 talking about putting those expensive wells, horizontal 19 wells into a thin oil rim, but for -- if my mother were 20 alive and listening in would it be like putting a straw 21 into a container that had a layer of peanut butter 22 overlain by gas and underlain by water and then sucking 23 on that straw and hoping to get peanut butter for a 24 long time and then being disappointed to get gas and 25 water instead very quickly? 74 1 MR. ELEFTHERIOU: That's a fair statement. 2 CHAIR FOERSTER: Okay. Okay. Okay. And so 3 you already said and everybody's aware that these wells 4 would be very expensive. would you expect these 5 horizontal oil producers to pay out? 6 MR. ELEFTHERIOU: I would not expect that given 7 the cost and complexity assuming that you could drill 8 them. So..... 9 CHAIR FOERSTER: So if we were to make you 10 drill those wells they would be uneconomical, they 11 would be very expensive and you'd never get your money 12 back -- well, in a most likely scenario? 13 MR. ELEFTHERIOU: That -- I would think so..... 14 CHAIR FOERSTER: Okay. 15 MR. ELEFTHERIOU: .....yes, ma'am. 16 CHAIR FOERSTER: All right. Slide 19. All 17 these conclusions that you make on slide 19 are based 18 on your current model; is that correct? 19 MR. ELEFTHERIOU: And models of previous years 20 past. 21 CHAIR FOERSTER: So it's based on -- it's based 22 on modeling that was done given 20 wells? 23 MR. ELEFTHERIOU: Yes, ma'am. 24 CHAIR FOERSTER: As you drill additional wells 25 do you expect the model to change? 75 1 MR. ELEFTHERIOU: Yes, ma'am. 2 CHAIR FOERSTER: Okay. And -- well, do you 3 expect that the conclusions you draw might change as 4 the model changes? 5 MR. ELEFTHERIOU: I don't think so because the 6 primary inhibitor to gas cycling at Point Thomson is 7 the reservoir pressure and the condensate yield. The 8 reservoir pressure, you know, we have of course hoped 9 that that's fairly well constrained and new information 10 should not change that and the condensate yield is 11 really defined by the fluids which we've acquired and 12 produced up to the surface. And again we feel that 13 that's pretty well constrained and we don't anticipate 14 that to change. 15 CHAIR FOERSTER: Okay. So you expect you'd be 16 able to do a great history match based on what you've 17 got so far, you expect when you get into production 18 that this model's going to give you the production 19 profiles that you predict that it will, I mean, that 20 the field will match this model? 21 MR. ELEFTHERIOU: Probably not. 22 CHAIR FOERSTER: Okay. That was just a little 23 test of your honest there, I was going to have to have 24 you raise your hand again, but -- okay. So things will 25 change. And so do you think that the performance of 76 1 the IPS will cause adjustments in your model? 2 MR. ELEFTHERIOU: Yes, ma'am. 3 CHAIR FOERSTER: Okay. So in a perfect world 4 you find a condensate reservoir and you cycle and you 5 get the condensate out and then you blowdown the gas. 6 Why is that not the right thing to do here? 7 MR. ELEFTHERIOU: It's primarily based on the 8 reservoir qualities of Point Thomson and the specifics 9 regarding the pressure of the reservoir and the fluid 10 character -- characteristics which do not make it 11 amenable to gas cycling. 12 CHAIR FOERSTER: Okay. So I'm going to again 13 talk to my dead mother. So it costs a lot of money to 14 get a little bit of extra oil, is that pretty much what 15 you're trying to say here? 16 MR. ELEFTHERIOU: Yes, ma'am, that's a fair 17 statement. 18 MR. BREINER: And you get the extra oil a long 19 time in the future. 20 CHAIR FOERSTER: So it's a -- you get a little 21 bit of extra oil, but you get it a lot later..... 22 MR. BREINER: Right. 23 CHAIR FOERSTER: .....and you spend a whole lot 24 of money to get it and..... 25 MR. BREINER: Now. 77 1 CHAIR FOERSTER: You spend a lot of money today 2 to get a little bit 50 years from now. Okay. Exxon 3 doesn't like doing things like that? 4 MR. ELEFTHERIOU: No, ma'am. 5 CHAIR FOERSTER: Okay. I had one last question 6 for you. We -- the Commission has in the last year or 7 so based on events that have happened in fields like, 8 you know, operating conditions change, operators 9 change, things like that, we've gone to putting sunset 10 clauses into our conservation orders. Would putting a 11 sunset clause into the pool rules for the Point Thomson 12 reservoir be problematic for Exxon? 13 MR. BREINER: I'm actually going to say a few 14 words on that on the next slide, but the short answer 15 is yes. 16 CHAIR FOERSTER: Okay. And we would want to 17 understand that it may not impact our decision to do 18 so, we're pretty stuck to doing things that take care 19 of our statutes and regs more than your operating and 20 business situations, but we do need to hear those sorts 21 of things..... 22 MR. BREINER: And I'll describe them. 23 CHAIR FOERSTER: .....to take them into 24 consideration. MR. BREINER: Okay. And I'll 25 describe why we think..... 1 CHAIR FOERSTER: And also given that you're 2 making recommendations on pool rules based on your 3 production and modeling with 20 wells in a large area 4 we're likely to want to see some production before -- 5 you know, there's likely to be a sunset clause in here 6 that says after things that relate to the IPS 7 performance that there's likely to be a sunset clause 8 in there relating to that so you might want to be 9 prepared to explain what we should consider in making 10 that determination. 11 CHAIR FOERSTER: All right. Do you have any 12 other questions? 13 COMMISSIONER SEAMOUNT: No. 14 CHAIR FOERSTER: All right. Please proceed. 15 MR. BREINER: Okay. Our conclusions are listed 16 on slide 23. Number 1, the Point Thomson gas expansion 17 project plan to produce gas to AKLNG and condensate to 18 TAPS is in accordance with good engineering practices 19 consistent with developments for similar gas condensate 20 reservoirs around the world with this type of pressure 21 and it is the best plan for the Point Thomson unit. 22 Number 2, the requested offtake rate of 1,100 million 23 standard cubic feet per day annual average provides 24 flexibility for design and operations without impacting 25 ultimate hydrocarbon recovery. And three, the proposed 79 • • 1 pool rules reflect sound engineering and oil field 2 practice. 3 And I do have one final point to cover and it 4 is in respect to the sunset provision that you 5 mentioned. We do believe that such a term is not 6 necessary or appropriate for the Point Thomson pool 7 rules and we're requesting -- for the following 8 reasons. First we believe that the Commission has 9 existing authority to investigate, hold hearings and 10 modify order issued -- orders issued by the Commission. 11 The Commission regulation specifically address amending 12 pool rules. Second, a limit on the period of 13 authorized offtake would introduce a level of 14 uncertainty that would have a significant impact on the 15 Alaska LNG project. As we understand decisions, 16 contracts and investment for that project are measured 17 in the 25 to 30 year type time frames. And third the 18 pool rules we're requesting for Point Thomson are 19 relatively limited compared to many other pool rules 20 and should be more straightforward to track. For these 21 reasons we respectfully request the Commission not 22 include a sunset provision in the Point Thomson pool 23 rules. 24 And we understand your desire to see initial 25 production system results and we certainly understand :1 1 that there'll be some reporting requirements and some 2 expectations and if there were big surprises there 3 would be opportunities to reopen, but we think that in 4 terms of do we do major gas sales versus some other 5 development concept, the way we looked at things like 6 expanded cycling have made all the best assumptions 7 that we really don't see as we look at the -- what 8 we're going to learn. We're going to certainly learn 9 things about well deliverability, we're going to learn 10 things about the reservoir as we drill PTU-17 and as we 11 produce through IPS. So it's certainly providing big 12 benefits. But we really don't see anything that could 13 come out of that that would lead us to conclude that 14 cycling for example would be better than we tried to 15 portray it for a reference case. 16 CHAIR FOERSTER: Okay. Okay. 17 MR. BREINER: And that concludes our testimony 18 for today. 19 CHAIR FOERSTER: Okay. Do you have any 20 questions? 21 COMMISSIONER SEAMOUNT: So is there any kind of 22 surprise that you would make that would cause you to go 23 to gas cycling for -- that you learn from the IPS? 24 MR. ELEFTHERIOU: So I would say the best 25 possible scenario for gas cycling would be that you FS 1 find fluids with a higher condensate/gas ratio meaning 2 that the gas that we produce produces more condensate 3 which helps the viability of the project. However if 4 we were to see that in the new well that we drill it 5 would probably indicate that we have a compartment that 6 we had not observed before. And if you have 7 compartments in a gas field and you try to cycle your 8 cycling project is doomed because you're not connected 9 throughout the field and you can't expect that gas to 10 retain or to continue to retain the reservoir pressure 11 as you inject it. So..... 12 COMMISSIONER SEAMOUNT: Or would it be possible 13 that your -- that you didn't test the original wells 14 long enough to see exactly what the ratio was? 15 MR. ELEFTHERIOU: I think our condensate/gas 16 ratio is fairly well constrained. We did 24 hour well 17 tests on PTU-15 and PTU-16 which was more than 18 sufficient time to gather clean fluids to have to do, 19 you know, PTU quality analysis on. Ultimately that 20 analysis was actually fairly consistent with the 21 analysis that we had had in the past with the 22 exploration well drill (indiscernible) tests. 23 COMMISSIONER SEAMOUNT: Okay. Thank you. 24 CHAIR FOERSTER: You asked my question. But 25 could you characterize the range of uncertainty of good 1 PVT analysis, I mean, you do PVT analysis and it says 2 your condensate yield's going to be blah and then you 3 go (indiscernible) onto production and it differs from 4 blah by what? 5 MR. ELEFTHERIOU: We characterize about 10 to 6 15 percent. 7 CHAIR FOERSTER: Okay. And what percent would 8 it require for cycling to be the way to go? 9 MR. ELEFTHERIOU: Like 50 plus percent, I mean, 10 we're talking a lot of the fields that cycle 11 condensate -- cycle gas for condensate are in the 70, 12 80, 90, hundreds of barrels per million..... 13 CHAIR FOERSTER: Okay. 14 MR. ELEFTHERIOU: .....which is far outside the 15 range of what we expect to see at Point Thomson. 16 CHAIR FOERSTER: Okay. I have one last little 17 housekeeping question. Go back to slide 17. And this 18 is just me being a little bit anal. You know, you say 19 MSCF and MM, do you guys use M's and double M's 20 interchangeably or was that a type? 21 MR. ELEFTHERIOU: It might be a typo, but we 22 tried to use MM to stand for million. 23 CHAIR FOERSTER: Okay. So it was -- yeah. 24 Those single M's were supposed to be double M's? 25 MR. ELEFTHERIOU: Where are we looking on the 83 1 slide? 2 CHAIR FOERSTER: On the title where you use one 3 M. 4 MR. ELEFTHERIOU: That is a typo. 5 CHAIR FOERSTER: That's a typo. 6 MR. BREINER: That is a typo. 7 MR. ELEFTHERIOU: Thank you for that 8 clarification. 9 CHAIR FOERSTER: Okay. So there's two typ -- 10 there's the title and then the subtitle, you got..... 11 MR. ELEFTHERIOU: Yes, ma'am. 12 CHAIR FOERSTER: Okay. All right. I think 13 what we'll do now is we'll take a recess and our 14 technical staff will tell us the questions we weren't 15 smart enough to ask and we got a question from the 16 audience and we've got a question from the audience 17 that we'll consider and it is 10:38 right now, we'll 18 take a recess until what do you think, 11:00 o'clock? 19 MR. ELEFTHERIOU: Sure. 20 CHAIR FOERSTER: Okay. We'll reconvene at 21 11:00 o'clock. 22 (Off record) 23 (On record) 24 CHAIR FOERSTER: We're back on the record. So 25 the Commission has no more additional questions that we 1 need answered. We did get some -- two requests from 2 the public for questions. And first is a set of 3 questions that came from someone from the Division of 4 Oil and Gas at DNR, all those questions are -- have 5 been answered with our technical staff as part of the 6 Point Thomson study. However we encourage the DNR 7 person to pursue the answers to these questions with 8 Exxon on their own time. There was one additional 9 question that came from a staffer for one of our state 10 Legislators and although this question addresses 11 matters that are outside our jurisdiction we will ask 12 it just as a courtesy to that Legislator. If Alaska -- 13 if AKLNG does not go to feed what impact would that 14 have on your modeling and how would you get your gas to 15 market if AKLNG is not built. So you can answer that 16 question online or you can seek out the individual who 17 asked it and answer it for him offline, it's your 18 preference, but you have to do one or the other. And 19 if the guy in the room wants to identify himself with 20 the float wave -- maybe he's not even here. Okay. 21 Then I imagine he left hoping that question would be 22 asked and part of the record so please give it a go. 23 MR. BREINER: I think we prefer not -- I mean, 24 we're working towards a major gas sales project and 25 that is our development option we're proceeding with. M. 0 • 1 CHAIR FOERSTER: Okay. 2 MR. BREINER: So I don't know I have an 3 alternative that I would be in a position to throw out 4 at this time. We'd certainly evaluate the options or 5 the concepts available. 6 CHAIR FOERSTER: Okay. We didn't need that 7 question answered for our deliberations, it was just a 8 courtesy to the gentleman who asked it. 9 So there are a couple of questions that are 10 outstanding. How many -- what we'll do is we'll leave 11 the record open for a few days to allow you to provide 12 the answers to those questions. How long would you 13 like, 10 days? 14 MR. ELEFTHERIOU: I think a week would probably 15 be enough, I believe. 16 CHAIR FOERSTER: Okay. Well, then we'll do 17 that. We'll leave the record open until a week from 18 today which is Tuesday and you can provide those in 19 writing to the Commission and they will be made part -- 20 your answers will be made part of the public record. 21 MR. ELEFTHERIOU: And, Commissioner Foerster, 22 to your comment before the break around what was the 23 proximate impact that 2 to 3 percent, what did that 24 reflect, that is in the -- that is roughly 24 to 36 25 million barrels -- oil equivalent barrels that we're 9 1 talking about with that 2 to 3 percent. 2 CHAIR FOERSTER: Okay. Thank you. At this 3 point I'll reiterate the invitation to anyone else in 4 the audience who would like to testify. If there is 5 anyone who wishes to testify please stand up. 6 (No comments) 7 CHAIR FOERSTER: Seeing nobody standing we're 8 going to call it a day and this hearing is adjourned. 9 (Recessed) 10 (END OF PROCEEDINGS) 9 1 C E R T I F I C A T E 2 UNITED STATES OF AMERICA ) 3 )ss 4 STATE OF ALASKA ) 5 6 I, Salena A. Hile, Notary Public in and for the 7 state of Alaska, residing in Anchorage in said state, 8 do hereby certify that the foregoing matter: Docket 9 No. CO 15-08 was transcribed to the best of our 10 ability; Pages 01 through 88 11 IN WITNESS WHEREOF I have hereunto set my hand 12 and affixed my seal this 8th day of September 2015. 13 14 15 Salena A. Hile 16 Notary Public, State of Alaska 17 My Commission Expires: 09/16/2018 • STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION Public Hearing Docket Number CO-15-008 Point Thomson Unit September 1, 2015 at 9:00am NAME AFFILIATION TESTIFY (Please Print) (Yes or No) CA n/AR 5 k�3 �fgy/�lGke-1 m (c tfA 5- L. m A `Actlow Ck I a P k0j N-0 If— A ye; '/� �1✓i c t�-f fl-L L !� �1.,. � Qc,." Co P _ � 0 Qkic�t, • • Continuation Page NAME AFFILIATION TESTIFY (Please Print) (Yes or No) 1 i N mot, (*ru v ►�' - Iv 1711-) �J 41 0 • Continuation Page NAME AFFILIATION TESTIFY ( lease Print) ii I L (Yes Jor No) (v ` t-F'ta s l / u Point Thomson Unit Pool Rules Public Hearing ExxonMobil Alaska Production Inc. September 1,, 2015 POINT THOMSON GAS EXPANSION PROJECT r'! E SEP 0 1 2015 AOGCC • Introduction Purpose • Establish pool rules including approval of gas offtake rate from Thomson Reservoir, Point Thomson Unit Testimony Outline • AKLNG Project • Point Thomson Field History • Gas Expansion Project Overview • Geology and Reservoir • Drilling and Completion • Facilities and Operations • Proposed Pool Rules POINT THOMSON GAS EXPANSION PROJECT 0 0 Alaska Gas Treatment Plant (GTP) • 3.3 BCFD peak export rate • Three trains • CO2 removed for injection at PBU Liquefaction Facility • Natural gas is cooled to -260 degrees F • 3 trains dehydrate, and liquefy gas to produce up to 20 million tons of LNG each year LNG Storage & Marine Terminal • LNG storage tanks • Two jetties for LNG carriers Ron GRSLINE .r OfOROPI Nt (ONP An integrated liquefied natural gas export project that would provide access to gas for Alaskans COLDFOOT :I t LIVENGOODel .x; FAIRBANKS 1 , LTA x Y " "JUNCTION 1 Point Thomson Transmission Line (PTTL) • —60 miles, 32" diameter above ground Prudhoe Bay Transmission Line (PBTL) • —1 mile, 60" diameter above ground Gas Pipeline • 800+ mile large diameter below ground gas pipeline • 6-10 compressor stations • Up to 5 in -state off -take points • Source: AK LNG Artists renditions of LNG and GTP insCanada Point Thomson Unit Location LIBERTY .4 1 �I 0 5 10 Wss POINT THOMSON GAS EXPANSION PROJECT Bene%arlSea J AWM Ef(onMobil PTU GAS EXPANSION PROJECT POOL RULES APPLICATION MAY2015 FIGURE t.0-9 CI E 0 Initial Production System Overview • Drill and complete four wells - 1 production well; PTU-17 - 2 injection wells; PTU-15 and PTU-16 - 1 disposal well; PTU-DW1 Wastewater �/�0: (PTU-DW1 -"+ ` •' ' Drsposd't Well ` Ui: (PTU-15) (COMWP&M i Gas Injection Compressor (PTU-16) POINT THOMSON GAS EXPANSION PROJECT • Install production facilities - Produce 200 MMSCFD of gas and up to 10 MBD condensate; cycle -200 MMSCFD of gas • Establish key infrastructure (PTU-17) Point Thomson Export Pipeline :7 • PTU Gas Expansion Project Overview • Install facilities to produce gas via PTU Gas Expansion Project - Approximately 8 TCF Original Gas in Place - 25% of known North Slope gas reserves POINT THOMSON GAS EXPANSION PROJECT • • Deliver gas to proposed Alaska LNG Project • Send condensate through existing common carrier pipelines to Trans -Alaska Pipeline System • Startup anticipated in 2025 • Gas off -take rate approval facilitates proceeding to FEED stage - Design capacity of 920 MMSCFD peak gas rate - Requested offtake rate of 1,100 MMSCFD o Provides flexibility for design and operations o Does not impact ultimate recovery Geoscience PTU_1 -'oi ,\ O PTU-16 = I WellI�— aesionWells (noti,,.oi%Aa-, POINT THOMSON GAS EXPANSION PROJECT • Primary resource: gas cap in the Lower Cretaceous Thomson Sand: - Porosity 5-34%, Permeability 0.01-10,000mD • Hydrocarbon accumulation: -500' gas column with. thin 37' heavy oil rim (10-180 API) • H2S 4-30 ppm, CO2 -y4.5%, CGR -50-65 STB/MMSCF • Abnormally pressured (-10,100 psi @-12,700' TVDSS ) • 22 wells in region, 16 penetrate Thomson Formation • 1,776' of Thomson conventional core collected • Upper and Lower Thomson sub -units defined by • core and logs • Full 3D seismic coverage, reprocessed in 2014 R11 PTU-3 Hue/HRZShaIe 7 Upper Thomson ------------ Lower Thomson Pre -Mississippian c Basement Geoscience Open Framework Conalomerate Bi-modal Conglomerate �7�_`�j ppp,r` cH 'i- •i -T ".1 Clean Sandstone � � r _��;� � � _ lam.♦ � E� "'.,� r ,,;,�ti � a Y i 1(R)W • •• — 1mm 3 1000 100 1 •. s 1 'T% U 0.1 � tj• 0,01 0,001 Silty Sandstone POINT THOMSON GAS EXPANSION PROJECT • Clastic reservoir comprising conglomerates, sandstone, and siltstones • Six petrofacies defined based on grain size, sorting, and ductile grain content • Porosity/permeability transforms for each petrofacies • Deposited in a fan delta setting (alluvial fan deposits reworked in shallow marine setting) Exceptional reservoir parameters measured - Open Framework� e S'i L�'i�' ram"" �`C''►' ! =r: Conglomerates, penetrated only in 0,00 0.05 0.10 0.15 0,20 0.25 0.30 0.35 0.40 Core Porosity Cemented Cong. is breccla searr.a.e After McPherson at al., 1987 LTA Geoscience POINT THOMSON GAS EXPANSION PROJECT PTU-15 and PTU-16 MDT • Fluid Contacts established using DST & MDT tests Pressure v. Depth and well logs Gas Oil Contact: -12, 975' tvdss AZ700 • 0 - Oil Water Contact:-13,012' tvdss 12.750 __ _____ _..-_-_. .___.__._ _ .f • Field -wide contact suggested by: ;o -1ZW0 _-- __ ..--_.---.. ♦ _-._ __ . PTU-16 MOT Pressure - Continuity of subaqueous part of fan delta 4VD •PTU-16MDT Pressure gas C i deposits ■ PTU 16 MDT Pressure oil r - Faults do not completely offset reservoir Q s PTU-15 and PTU-16 MDT results 12.9e0 Gas at - ,2.950 -- 12,973' tvdss GOC gat-12,975' TVDSS • --- --------------.---------------- 13,000 Oil at - 12,979' tvdss .13.050 _. __.-....._. __ _ _....... 10,100 10.110 10,120 10.130 10.140 10,150 10.160 10.170 Pressure (psis) Gas in Place Original Gas in Place estimated -8 TCF POINT THOMSON GAS EXPANSION PROJECT Hydrocarbon Pore Volume - Thomson Reservoir Ak �0_ Q 160 IPS Wells ' r 140 120 _. MO aI Q Gas Expansion Wells (notional) 60 40 *.r 1. —87% in Thomson Sand Gas Cap °� r.. - Depth and isochore derived from pre -stack depth migrated seismic and well control - Porosity and hydrocarbon saturation are based on petrofacies distribution (core and depositional model) 2. 5% in Pre -Mississippian fractured basement Uniform properties (1 % porosity, 78 mD vertical permeability) 3. 8% as solution gas from relict oil in gas cap and oil rim GOR from well tests & DSTs 0 Depletion Plan Reference Case Production Profile (includes booster compression) 900 800 700 d M 600 j M Soo 400 LL 300 200 140 120 100 80 60 40 °' 100 20 M a 0 5 10 15 20 25 30 Year Sales Gas Rate - Fuel Gas Rate Sales Condensate Rate Water Rate Production Profile Build-up • Facility peak design capacity: 920 MMSCFD • With AK LNG considerations: 865 MMSCFD • With 94.5% uptime adjustment: 820 MMSCFD POINT THOMSON GAS EXPANSION PROJECT Key Assumptions: • 10 well development (7 new producers + 3 s Initial Development wells) from 3 pads to • Facility peak design capacity of 920 MMSCFD (annualized average rate of 820 MMSCFD) M 3 • 57 KBD initial peak condensate rate -o c r • Includes booster compression in year 15 to increase gas and condensate recovery near the end of plateau life • 30 year Project life Model Predictions: • Simulation modeling predicts 15-16 year plateau period with booster compression • 75% of gas in place recovered after 30 years Production Profile Outputs Export HC Gas: -6 TCF Export Condensate: "'200 MBO is POINT THOMSON PTU Notional Well Locations GAS EXPANSION PROJECT �.. -_. Beaufort Sr,z » rt /] ) i • i r M 1, l u POINT T obi UNIT. u „ „ r i a' a' ). » m n � n a [ x » � m Isi a � a s. 1i C m )t a ,• I i l ! PTU-17 PTU-15 _ _ I n x l s » x I x (2016) x a 5t a n j x x� n 1 x a x Liu No 10N n PTU-DV T10N q 9N 13 a t J1 t S a 1 j! PTU-16 4 �I �", �7 r ro t':. 1 n ry , i � n >e � 11 1i r. l • j i » „ ,3 dl. s .Ti _ 13 3 1� i ha fi § 17 I tb li M -_ /s 19 3 tr i » { ti 1• t3 7iry.y '`f 1/ 1 M fi y1i {�- 1• f f1 e! I » m 21 a a M 1t m ., 1Y I11{ 1 1 ARCTIC NATIONAL i x I WILDLIFE REFUGE Y N Si r, x 1 x 1, v $ yl I Si x 11 p 4 )s (j ! "!6 r• � T9N Note; T9N' s T$N < Number and location of Gas Expansion It T8N watts are tentative and subsea to change 1 6 i • i." t A , T f s 1 3 - 4 • as development progresses 2 r Location of 2nd disposal wew not shown i - , a i • m n t3 + • • - MonMobil ' • Surface Well Location t, PTU Initial Production System Wells i E A ( rt rs j ,. ,r ;a 1b � A _ 1f +s DRILLING PROGRAM - u PTU Gas Expansion Wells --- m m - PTU GAS EXPANSION PROJECT ' Well Borehole .. — � _��_ Miles '�• x rig' M JULY20t5 • Producing Well Designs PTU GE Preliminary Well Design Insulated Conductor Permafrost to—1,800' Surface Casing; 13-3/8" —4,500' TVD 12-1/4" x 13-1/2" Hole 7-5/8" Liner top / PBR Intermediate Casing; 10-3/ —10,800' TVD 9-1/4" Hole Production Liner; 7-5/8" —13,200' TVD POINT THOMSON GAS EXPANSION PROJECT • Reference case includes 8 new wells —Seven high pressure gas producers —One disposal well • Wells drilled from 3 onshore pads • Preliminary design similar to PTU-17 • PTU-15 and PTU-16 wells used as gas producers • Final well designs will incorporate PTU drilling results and comply with ExxonMobil Standards & AOGCC Regulations r� PTU GE Project Overview PTU Gas Expansion Project (PTU GE Project) Concept • Deliver -gas to AK LNG (thru new 32" AK LNG transmission line) • Export condensate via existing 12" pipeline PTU GE Project Facilities Expansion • PTU Gas Expansion Preliminary Design Basis: - Design Capacity: 920 MMSCFD, 57 MBD - East and West Pad, McOH storage/injection and well metering - Expand Central Pad for new facilities (-25k tons total modules) - 5900 ton module maximum design limit - TEG dehydration and Expander technology for gas conditioning - Condensate stabilization - New gathering lines from East and West pads IPS Integration • Use IPS camp, camp utilities, maintenance and diesel modules • Integrate with IPS utilities, install new as required • Use IPS infrastructure, PTU-15 16 and 17 and disposal well Note: Pre -FEED Design Basis, subject to change as project definition increases POINT THOMSON GAS EXPANSION PROJECT ion C U PTUGE Project Field Layout IPS Installed Infrastructure • Central Pad and facilities/camp • Wells at West and Central pads • Condensate pipeline (PTEP) • Airstrip • Marine facilities; coastal barging and sealift WEST WELL PAD (EXISTING) WEST GATHERING LINE [BLACK] (EXISTING,TO BE DECOMMISSIONED) WEST GATHERING LINE [GREEN] CENTRAL P POINT THOMSON EXPORT PIPELINE (PTEP) [BLACK] (EXISTING) POINT THOMSON TRANSMISSION LINE (PTTL) [BLUE] M WEST WELL PAD ._ _ . �,; ACCESS ROAD (EXISTING) MINE SITE CENTRAL PAD (ABANDONED) ROAD (EXISTING) EAST WELL PAD C1 PAD �% (El€ISTfNG) EAST WELL PAD t j ACCESS ROAD AIRSTRIP (EXISTING) POINT THOMSON GAS EXPANSION PROJECT Gas Expansion Scope • Expand Central Pad • New East Pad and Road • New East and West Gathering Lines • New wells at Central, West and East pads • PTU gas transmission line (AKLNG Scope) AD CENTRAL PAD o 1500 V% 45,,7 ao-ao FT EXPANSION (EXISTING) EAST GATHERING LINE [GREEN] LEGEND PROPOSED GAS EXPANSION GRAVEL INFRASTRUCTURE Note: Pre -FEED Design Basis, subject to change as project definition increases 1 — — L C7 PTUGE Project and IPS Comparison Liquid HandlinE Gas HandlinE Produced Water HandlinE Facility Inlet Pressure Gas ProcessinE Facility Outlet Pressure IPS Project IPS POINT THOMSON GAS EXPANSION PROJECT Gas Expansion MBD 10 57 M MSCFD 200 920 MBD 1,000 10,000 psi 2,700 1,400 - Compression Dehydration + Conditioning psi 10,000 1,060 Compression Gas Injection From Inlet Wells separation Condensate Recovery 12" PTEP j & Stabilization Gas Expansion __7 7 Gas Dehydration Conditioning Export i t From Inlet Wells Separation Note: Pre -FEED Design Basis, subject to change as project definition increases Condensate Recovery & Stabilization �3 12" PTEP 0 POINT THOMSON 1,100 M SC F D Offtake Request GAS EXPANSION PROJECT 1,100 MSCFD Build-up • Design Capacity: 920 MMSCFD Export (includes HC and non-HC gas) • Fuel Gas: 8 MMSCFD base case, 28 MMSCFD with booster compression • Higher uptime potential • Additional flexibility for operation and debottlenecking Subsurface Impact • Simulation studies tested gas offtake rate from 400 — 1,200 MMSCFD • Gas and condensate recovery for Gas Expansion depletion strategy insensitive to offtake rate — Increased export rate accelerates gas and condensate production while maintaining ultimate recovery from the reservoir POINT THOMSON Development Considerations- Oil Rim GAS EXPANSION PROJECT • Approximately 160 million barrels original oil in place ® Oil Rim development not viable due to technical challenges and costs - Thin, -37 foot hydrocarbon column with heavy oil (100 to 180 API) - Simulation studies predict small oil recovery per well due to immediate and severe breakthrough of gas and water • POINT THOMSON Development Considerations - Gas Cycling GAS EXPANSION PROJECT • Expanded/full field gas cycling not a preferable alternative to major gas sales - Significant work in early 2000s; concluded not viable - World-wide study: reservoir characteristics not amenable to gas cycling - Additional facilities would be costly and complex • Current analysis indicates minimal potential increase in total hydrocarbon recovery from expanded cycling followed by gas sales versus gas sales alone - Additional condensate offset by reduced gas recovery - Reservoir issues could negate any potential benefits • Expanded cycling would significantly defer PTU gas sales - Could adversely affect AKLNG Project decision timing and viability - Could reduce ultimate hydrocarbon recovery from PTU while any potential increase would be obtained many years in the future 0 0 Proposed Pool Rules Rule 1: Field and Pool Name The field is the Point Thomson Field and the Pool is defined as the Thomson Pool Rule 2: Definition of Pool The Thomson Pool is defined as the accumulation of hydrocarbons corresponding to depths 16,126' to 16,377' measured depth (MD) (- 12,614' to-12,828' True Vertical Depth Subsea or TVDSS) on the PTU-15 type log and contained within the area described in Table 14.0-1 POINT THOMSON GAS EXPANSION PROJECT m m , . ReseFiuti &-a POINT THOMSON UNIT, PTU-17a, 'PTU-16 " 'O •." (2016) 10N v T70 T9N ..PTU-16, �. {�' r- I ARCTIC NATIONAL WILDLIFE REFUGE F T9N T9N TBN T8N PMYMer BM1 bceUM of Gee Expa06nn = € wdb ere tentsbve eM suWett to tt,ange - .—...._ - .... ., 3tlevtlopnenl{xo¢esse a „ w E*onMobil j Wells P• PTU Initial Production System .. ,. ,. m . m z .� PTU GAS EXPANSION PROJECT L, PTU Gas Expansion Wells — — +— m 'm 1 PROPOSED THOMSON POOL Proposed Thomson Pod �o JULY 2015 FIGURE ID-2 Note: • Unit acreage = 93,291 • Pool acreage = 80,987 • POINT THOMSON Proposed Pool Rules (continued) GAS EXPANSION PROJECT Rule 3: Gas -Oil Ratio Exemption Wells producing from the Thomson Pool are exempt from the gas -oil ratio limits of 20 AAC 25.240 (a) 0 Explanation: 20 AAC 25.240 (a) states: An oil well may not be produced if the gas -oil ratio of the well exceeds the original solution gas -oil ratio of the crude within the producing pool by more than 100 percent; 20 AAC 25.240 (c) provides authority for Commission to grant an exception to this limitation Under AOGCC regulations, PTU wells are considered oil wells if their GOR is less than 100,000 scf/stb; initial PTUGE producing GORs will be less than 20,000 scf/stb The proposed development plan contemplates exceeding the initial GOR by 100 , percent in about 10 years so a waiver from 20 AAC 25.240(a) is required POINT THOMSON Proposed Pool Rules (continued) GAS EXPANSION PROJECT Rule 4: Allowable Gas Offtake Rate The maximum allowable annual average gas offtake rate from the Thomson Pool is 1,100 million standard cubic feet per day (MSCFD) Rule 5: 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 • • Conclusions POINT THOMSON GAS EXPANSION PROJECT 1. Simultaneously producing gas to AKLNG and condensate to TAPS is: - in accordance with good engineering practices - consistent with world wide practices for development of similar gas condensate reservoirs, and - the most prudent development plan for PTU 2. Requested offtake rate of 1,100 MMSCFD provides flexibility for design and operations and does not impact ultimate recovery 3. Proposed pool rules reflect sound engineering and oilfield practice Questions POINT THOMSON GAS EXPANSION PROJECT • s REVISED Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Re: Docket Number: CO-15-08 Point Thomson Unit Proposed Pool Rules ExxonMobil Alaska Production Inc., by letter dated July 16, 2015, requests the Alaska Oil and Gas Conservation Commission (AOGCC) issue an order under 20 AAC 25.520, which establishes pool rules governing development of the proposed Thomson Oil Pool in the Point Thomson Unit. The AOGCC previously scheduled a public hearing on this application for September 1, 2015 at 9:00 a.m. at 333 West 71h Avenue. By this revised noticed, the site of the public hearing is changed to 716 West 4th Avenue, Anchorage, Alaska 99501. Written comments regarding this application may be submitted to the AOGCC, at 333 West 7th Avenue, Anchorage, Alaska 99501. Comments must be received no later than the conclusion of the September 1, 2015 hearing. If you would like to attend the above Public Hearing but are unable to do so in person, the call in number is 1-844-586-9085 or you can watch live at akl.tv. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact the AOGCC's Special Assistant, Jody Colombie, at 793-1221, no later than August 20, 2015. Cathy P. F erster Chair, Commissioner STATE OF ALASKA ADVERTISING ORDER NOTICE TO PUBLISHER SUBMIT INVOICE SHOWING ADVERTISING ORDER NO., CERTIFIED AFFIDAVIT OF PUBLICATION WITH ATTACHED COPY OFADVERTSMENT. ADVERTISING ORDER NUMBER AO-I6-005 FROM: Alaska Oil and Gas Conservation Commission AGENCY CONTACT: Jody Colombie/Samantha Carlisle DATE OF A.O. 07/23/15 AGENCY PHONE: 1(907) 793-1221 333 West 7th Avenue Anchorage, Alaska 99501 DATES ADVERTISEMENT REQUIRED: COMPANY CONTACT NAME: PHONE NUMBER: ASAP FAX NUMBER: (907)276-7542 TO PUBLISHER: Alaska Dispatch News SPECIAL INSTRUCTIONS: PO Box 149001 Anchorage, Alaska 99514 f]'I'E OF AD1rER'1'ISEiY1EN'T: LEGAL DISPLAY CLASSIFIED OTHER (Specify below) DESCRIPTION PRICE CO-15-08 Initials of who prepared AO: Alaska Non -Taxable 92-60M Su$1.. ISYoid...................... .:O:RDEIt:Tit7.,; CERTIFIEI:I A:F:F DAVTI'OF;:;: rtiatiieAiioritiuitii:a,TTAciI:Eq coPYbi?: ... EIiFtS1NENT ro: >......:::... ............... .. Department of Administration Division of AOGCC 333 West 7th Avenue Anchorage, Alaska 99501 Page I of 1 Tota1 of All Pa es S REF Type Number Amount Date Comments I PvN ADN84501 2 Ao AO-16-005 3 4 FIN AMOUNT SY CC PGM LGR ACCT FY DIST LIQ 1 16 02140100 73451 16 2 3 4 Purchasing A t o 44.le: t Authority's i �.ture Telephone Number t. A.O. # an eivirng agency name must appear on all invoices and documents lating to this purchase. 2. The state 's registered for tax free transactions under Chapter 32, IRS code. Re istration number 92-73-0006 K. Items are for the exclusive use of the state and not for resale. D ............................................. ................... iisheazed ivisioiti Fiscal :Receiviii : >......::: >:::::.. ... . :... ..::::: . ..... Division:Fiscal/Atigirial:A© es:;::Pn....... (..... ............ ........ S.................................... . Form:02-901 Revised: 7/23/2015 270227 0001368913 $ 194.24 • RECIVEL) AUG 0 3 201a AFFIDAVIT OF PUBLICATION AOGCC STATE OF ALASKA THIRD JUDICIAL DISTRICT Leesa Little being first duly sworn on oath deposes and says that he/she is a representative of the Alaska Dispatch News, a daily newspaper. That said newspaper has been approved by the Third Judicial Court, Anchorage, Alaska, and it now and has been published in the English language continually as a daily newspaper in Anchorage, Alaska, and it is now and during all said time was printed in an office maintained at the aforesaid place of publication of said newspaper. That the annexed is a copy of an advertisement as it was published in regular issues (and not in supplemental form) of said newspaper on July 24, 2015 and that such newspaper was regularly distributed to its subscribers during all of said period. That the full amount of the fee charged for the foregoing publication is not in excess of the rate charged private individuals. Signed:_ Subscribed and sworn to before me this 24th day of July, 2015 Notary Public in and for The State of Alaska. Third Division Anchorage, Alaska MY COMMISSION EXPIRES ,0'v doC7 Revised Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Docket Number: CO-15-08 Point Thomson Unit Proposed Pool Rules ExxonMobil Alaska Production Inc., by letter dated July 16, 2015, requests the Alaska Oil and Gas Conservation Commission (AOGCQ issue an order under 20 AAC 25.520, which establishes pool rules governing development of the proposed Thomson Oil Pool in the Point Thomson Unit. The AOGCC previously scheduled a public hearing on this application for September 1, 2015 at 9:00 a.m. at 333 West 7th Avenue. By this revised noticed, the site of the public hearing is changed to 716 West 4th Avenue, Anchorage, Alaska 99501. Written comments regarding this application may be submitted to the AOGCC, at 333 West 7th Avenue, Anchorage, Alaska 99501. Comments must be received no later than the conclusion of the September 1, 2015 hearing. If you would like to attend the above Public Hearing but are unable to do so in person, the call in number is 1-844-586-9085 or you can watch live at akl.tv. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact the AOGCC's Special Assistant, Jody Colombie, at 793-1221, no later than August 20, 2015. Cathy P. Foerster Chair, Commissioner AO-16-005 Published: July 24, 20A5 I Notary Public BRITNEY L. THOMPSON State of Alaska My Commission Expires Feb 23, 2019 Singh, Angela K (DOA) From: Colombie, Jody 1 (DOA) Sent: Thursday, July 23, 2015 2:32 PM To: Ballantine, Tab A (LAW); 'Salena'; Delbridge, Rena E (LAS); glyle@guessrudd.com; AKDCWellIntegrityCoordinator, Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew VanderJack, Anna Raff; Barbara F Fullmer, bbritch; Becca Hulme; bbohrer@ap.org; Bob Shavelson; Brian Havelock, Bruce Webb; Burdick, John D (DNR); Carrie Wong; Cliff Posey; Colleen Miller; Crandall, Krissell; D Lawrence; Dave Harbour; David Boelens; David Duffy, David House; David McCaleb; David Steingreaber; David Tetta; Davide Simeone; ddonkel@cfl.rr.com; Dean Gallegos; Delbridge, Rena E (LAS); DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Frank Molli; Gary Oskolkosf, George Pollock; ghammons; Gordon Pospisil; Greg Duggin; Gregg Nady; gspfoff, Jacki Rose; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Williams, Jennifer L (LAW); Jerry Hodgden; Jerry McCutcheon; Solnick, Jessica D (LAW); Jim Watt; Jim White; Joe Lastufka; news@radiokenai.com; John Adams; Easton, John R (DNR); Jon Goltz; Juanita Lovett; Judy Stanek; Houle, Julie (DNR); Julie Little; Kari Moriarty, Kazeem Adegbola; Keith Wiles; Kelly Sperback; Gregersen, Laura S (DNR); Leslie Smith; Lisa Parker; Louisiana Cutler; Luke Keller; Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Kremer, Marguerite C (DNR); Mary Cocklan-Vendl; Michael Calkins; Michael Duncan; Michael Moora; Mike Bill; mike@kbbi.org; Mikel Schultz; MJ Loveland; mkm7200; Morones, Mark P (DNR); Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nick W. Glover, Nikki Martin; NSK Problem Well Supv; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Renan Yanish; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Sternicki, Oliver R, Moothart, Steve R (DNR); Suzanne Gibson; sheffield@aoga.org; Tania Ramos; Ted Kramer; Davidson, Temple (DNR); Terence Dalton; Teresa Imm; Terry Templeman; Thor Cutler; Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater, Anne Hillman; Bajsarowicz, Caroline J; Brian Gross; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Don Shaw; Donna Vukich; Eric Lidji; Erik Opstad; Gary Orr, Smith, Graham O (PCO); Greg Mattson; Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Holly Pearen; Hyun, James J (DNR); Jason Bergerson; jill.a.mcleod@conocophillips.com; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Kenneth Luckey; King, Kathleen J (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Matt Gill; Franger, James M (DNR); Morgan, Kirk A (DNR); Pat Galvin; Bettis, Patricia K (DOA); Pete Dickinson; Peter Contreras; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Sarah Baker, Peterson, Shaun (DNR); Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); Todd, Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster, William Hutto; William Van Dyke; Ballantine, Tab A (LAW); Bender, Makana K (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Crisp, John H (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Herrera, Matthew F (DOA); Hill, Johnnie W (DOA); Hunt, Jennifer L (DOA); Jackson, Jasper C (DOA); Jones, Jeffery B (DOA); Kair, Michael N (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, To: Angela K (DOA); Wallace, Chris D (DOA) Subject: Revised Public Notices Attachments: Revised Notice of Public Hearing, CO-15-08.pdf Revised Notice of Hearing, Dockets AIO-15-32, AIO-15-33, CO-15-09.pdf Please disregard the Public Notices that I sent earlier, the website information was incorrect. I apologize for any inconvenience this may have caused you. 0 • James Gibbs P.O. Box 1597 Soldotna, AK 99669 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 Jack Hakkila Bernie Karl P.O. Box 190083 M Recycling Inc. Anrhnrnaa AK QQrlQ P.O. Box 58055 • • Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Re: Docket Number: CO-15-08 Point Thomson Unit Proposed Pool Rules ExxonMobil Alaska Production Inc., by letter dated July 16, 2015, requests the Alaska Oil and Gas Conservation Commission (AOGCC) issue an order under 20 AAC 25.520, which establishes pool rules governing development of the proposed Thomson Oil Pool in the Point Thomson Unit. The AOGCC has scheduled a public hearing on this application for September 1, 2015 at 9:00 a.m. at 333 West 71h Avenue, Anchorage, Alaska 99501. Written comments regarding this application may be submitted to the AOGCC, at 333 West 71h Avenue, Anchorage, Alaska 99501. Comments must be received no later than the conclusion of the September 1, 2015 hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact the AOGCC's Special Assistant, Jody Colombie, at 793-1221, no later than August 20, 2015. /444-1�— Cathy P Foerster Chair, Commissioner STATE OF ALASKA ADVERTISING ORDER NOTICE TO PUBLISHER SUBMIT INVOICE SHOWING ADVERTISING ORDER NO., CERFIFIED AFFIDAVIT OF PUBLICATION WUH ATTACHED COPY OF ADVERT$MENT. ADVERTISING ORDERNUMBER 1 AO- l 6-00 1 1 FROM: Alaska Oil and Gas Conservation Commission AGENCY CONTACT: Jody Colombie/Samantha Carlisle DATE OF A.O. 07/20/15 AGENCY PHONE: 1(907) 793-1221 333 West7th Avenue Anchorage, Alaska 99501 DATES ADVERTISEMENT REQUIRED: COMPANY CONTACT NAME: PHONE NUMBER: ASAP FAX NUMBER: (907)276-7542 TO PUBLISHER: Alaska Dispatch News SPECIAL INSTRUCTIONS: PO Box 149001 Anchorage, Alaska 99514 Tl'Y1 OF AllVE12'ITSEAIEN'r; LEGAL DISPLAY CLASSIFIED OTHER (Specify below) DESCRIPTION PRICE co-l5-ox Initials of who prepared AO: Alaska Non -Taxable 92-60011 $U0 ITIi!1Y X s Q vpvQADVER7Isir?G ' ;:O;RDEIt:jVO.,;CFR IFIEI>A.....�VYCU rtis .......... i. ATW. En;coP . .. AD4Ett7tSMtNT: YO::::::::::::::::: •. Department of Administration Division of AOGCC 333 West 7th Avenue Anchora e, Alaska 99501 Pa e 1 of 1 Total of All Pages S REF Type ............ Number Amount Date Comments I PvN ADN84501 2 Ao AO-16-001 4 FIN AMOUNT SY CC PGM LGR ACCT FY DIST I,IQ 1 16 02140100 73451 16 2 3 4 5 Purcha ng A tho Title: / h Authority's Agnature Telephone Number 1. A.0.#ArjlI receiving agency name must appear on all invoices and do a relating to this purchase. 2. The stW is registered for tax free transactions under Chapter 32, IRS co Registration number 92-73-0006 K. Items are for the exclusive use of the state and not for resale. A ISTITBT�Q1� i:::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::: ➢ivisioii Fiscal%Dri":a1:.1©>::Cu iesc: Piililisher:.faged :➢ivisioa Fiscal ateceiviii ::< ........< ::>::::::::::::::::::::.:.::.::::.>: : ..................P..............(.....)s..............,........5.......................................... Form:02-901 Revised: 7/20/2015 270227 • 0001368711 $ 169.34 RECEIVED JUL 3 0 2015 AMCC AFFIDAVIT OF PUBLICATION STATE OF ALASKA THIRD JUDICIAL DISTRICT Leesa Little being first duly sworn on oath deposes and says that he/she is a representative of the Alaska Dispatch News, a daily newspaper. That said newspaper has been approved by the Third Judicial Court, Anchorage, Alaska, and it now and has been published in the English language continually as a daily newspaper in Anchorage, Alaska, and it is now and during all said time was printed in an office maintained at the aforesaid place of publication of said newspaper. That the annexed is a copy of an advertisement as it was published in regular issues (and not in supplemental form) of said newspaper on July 21, 2015 and that such newspaper was regularly distributed to its subscribers during all of said period. That the full amount of the fee charged for the foregoing publication is not in excess of the rate charged private individuals. Subscribed and sworn to before me this 21st day of Jul rr 2015 Notary Public in and for The State of Alaska. Third Division Anchorage, Alaska MY COMMISSION EXPIRES 1193 / ao i� Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Re: Docket Number: CO-15-08 Point Thomson Unit Proposed Pool Rules ExxonMobil Alaska Production Inc., by letter dated July 16, 2015, requests the Alaska Oil and Gas Conservation commission (AOGCC) issue an order under 20 AAC 25.520, which establishes pool rules governing development of the proposed Thomson Oil Pool in the Point Thomson Unit. The AOGCC has scheduled a public hearing on this application for September 1, 2015 at 9:00 a.m. at 333 West 7th Avenue, Anchorage, Alaska 99501. Written comments regarding this application may be submitted to the must beareceiv dest 7th no later than the condusionsof the Sep1. tembe 1, 2015 hearing. if, because be needed to comment oroattend thf a di sability, special hearing, contact tmodations p he AOGCC's Special Assistant, Jody Colombie, at 793-1221, no later than August 20, 2015. Cathy P. Foerster Chair, commissioner AO-16-001 Published: July 21, 2015 BRITN ,tary PoDli-v" State aTHOMPSON My Commt isston fxp yes Feb ?3, 201g • Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Monday, July 20, 2015 10:24 AM To: Ballantine, Tab A (LAW); 'Salena'; 'Nathan Hile (nwhcmatrix@hotmail.com)'; Nordstrom, Christina D(christina.d.nordstrom@exxonmob il.com); 'Bender, Makana K (DOA) (makana.bender@alaska.gov)'; 'Bettis, Patricia K (DOA) (patricia.bettis@alaska.gov)'; 'Brooks, Phoebe L (DOA) (phoebe.brooks@alaska.gov)'; Carlisle, Samantha J (DOA); 'Colombie, Jody J (DOA) Oody.colombie@alaska.gov)'; 'Davies, Stephen F (DOA) (steve.davies@alaska.gov)'; Eaton, Loraine E (DOA); 'Foerster, Catherine P (DOA) (cathy.foerster@alaska.gov)'; 'Frystacky, Michal (michal.frystacky@alaska.gov)'; 'Guhl, Meredith (DOA sponsored) (meredith.guhl@alaska.gov)'; 'Hunt, Jennifer L (DOA)'; 'Jackson, Jasper C (DOA)'; Kair, Michael N (DOA); Loepp, Victoria T (DOA); 'Mumm, Joseph (DOA sponsored) Ooseph.mumm@alaska.gov)'; 'Paladijczuk, Tracie L (DOA) (tracie.paladijczuk@alaska.gov)'; 'Pasqual, Maria (DOA) (maria.pasqual@alaska.gov)'; 'Regg, James B (DOA) Oim.regg@alaska.gov)'; 'Roby, David S (DOA) (dave.roby@alaska.gov)'; 'Schwartz, Guy L (DOA) (guy.schwartz@alaska.gov)'; 'Seamount, Dan T (DOA) (dan.seamount@alaska.gov)'; Singh, Angela K (DOA); 'Wallace, Chris D (DOA) (chris.wallace@alaska.gov)'; 'AKDCWellIntegrityCoordinator'; 'Alex Demarban'; 'Alexander Bridge'; 'Allen Huckabay'; 'Andrew VanderJack'; 'Anna Raff'; 'Barbara F Fullmer'; 'bbritch'; 'Becca Hulme'; 'Becky Bohrer'; 'Bob Shavelson'; 'Brian Havelock'; 'Bruce Webb'; Burdick, John D (DNR); 'Carrie Wong'; 'Cliff Posey'; 'Colleen Miller'; 'Crandall, Krissell'; 'D Lawrence'; 'Dave Harbour'; 'David Boelens'; 'David Duffy'; 'David House'; 'David McCaleb'; 'David Steingreaber'; 'David Tetta'; 'Davide Simeone'; 'ddonkel@cfl.rr.com'; 'Dean Gallegos'; Delbridge, Rena E (LAS); DNROG Units (DNR sponsored); 'Donna Ambruz'; 'Ed Jones'; 'Elowe, Kristin'; 'Evans, John R (LDZX)'; 'Frank Molli'; 'Gary Oskolkosf'; 'George Pollock'; 'ghammons'; 'Gordon Pospisil'; 'Greg Duggin'; 'Gregg Nady'; 'gspfoff'; 'Jacki Rose'; 'Jdarlington Oarlington@gmail.com)'; 'Jeanne McPherren'; 'Jennifer Williams'; 'Jerry Hodgden'; 'Jerry McCutcheon'; 'Jessica Solnick'; 'Jim Watt'; 'Jim White'; 'Joe Lastufka'; 'Joe Nicks'; 'John Adams'; 'John Easton'; 'Jon Goltz'; 'Juanita Lovett'; 'Judy Stanek'; 'Julie Houle'; 'Julie Little'; 'Karl Moriarty'; 'Kazeem Adegbola'; 'Keith Wiles'; 'Kelly Sperback'; 'Laura Silliphant (laura.gregersen@alaska.gov)'; 'Leslie Smith'; 'Lisa Parker'; 'Louisiana Cutler'; 'Luke Keller'; 'Marc Kovak'; 'Mark Dalton'; 'Mark Hanley (mark.hanley@anadarko.com)'; 'Mark Landt'; 'Mark Wedman'; 'Marquerite kremer (meg.kremer@alaska.gov)'; 'Mary Cocklan-Vendl'; 'Michael Calkins'; 'Michael Duncan'; 'Michael Moora'; 'Mike Bill'; 'Mike Mason'; 'Mike) Schultz'; 'MJ Loveland'; 'mkm7200'; Morones, Mark P (DNR); Munisteri, Islin W M (DNR); 'nelson'; 'Nichole Saunders'; 'Nick W. Glover'; 'Nikki Martin'; 'NSK Problem Well Supv'; Patty Alfaro; 'Paul Craig'; Paul Decker (paul.decker@alaska.gov); 'Paul Mazzolini'; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; 'Renan Yanish'; 'Robert Brelsford'; 'Ryan Tunseth'; Sara Leverette; 'Scott Griffith'; Shannon Donnelly; Sharmaine Copeland; 'Sharon Yarawsky'; Shellenbaum, Diane P (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; 'Stephanie Klemmer'; Sternicki, Oliver R; Steve Moothart (steve.moothart@alaska.gov); 'Suzanne Gibson'; Tamera Sheffield; 'Tania Ramos'; 'Ted Kramer'; Temple Davidson; Terence Dalton; Teresa Imm; 'Terry Templeman'; Thor Cutler, 'Tim Mayers'; Todd Durkee; trmjrl; 'Tyler Senden'; Vicki Irwin; Vinnie Catalano; 'Aaron Gluzman'; 'Aaron Sorrell'; Ajibola Adeyeye; Alan Dennis; Andrew Cater; Anne Hillman; Bajsarowicz, Caroline 1; Brian Gross; 'Bruce Williams'; Bruno, Jeff J (DNR); Casey Sullivan; Don Shaw; 'Donna Vukich'; Eric Lidji; Erik Opstad; 'Gary Orr'; 'Graham Smith'; 'Greg Mattson'; Hak Dickenson; Heusser, Heather A (DNR); Holly Pearen; James Hyun; 'Jason Bergerson'; 'Jill McLeod'; 'Jim Magill'; Joe Longo; John Martineck; Josh Kindred; Kenneth Luckey; King, Kathleen J (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); To: Marc Kuck; Marcia Hobson; 'Marie Steele'; Matt Armstrong; 'Matt Gill'; 'Mike Franger'; Morgan, Kirk A (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Richard Garrard; Richmond, Diane M; Robert Province; 'Ryan Daniel'; 'Sandra Lemke'; Sarah Baker; Shaun Peterson; 'Susan Pollard'; Talib Syed; Tina Grovier (tmgrovier@stoel.com); Todd, Richard J (LAW); Tostevin, Breck C (LAW); 'Wayne Wooster'; 'William Hutto'; 'William Van Dyke' Subject: USE THIS ONE RE: Public Hearing (Proposed Pool Rules Point Thomson Unit) Attachments: Notice of Public Hearing, CO-15-08.pdf PLEASE USE THIS PUBLIC NOTICE instead of the one I sent a few minutes again! 0 0 James Gibbs Jack Hakkila Bernie Karl P.O. Box 1597 P.O. Box 190083 K&K Recycling Inc. Soldotna, AK 99669 Anchorage, AK 99519 P.O. Box 58055 Fairbanks, AK 99711 Gordon Severson Penny Vadla George Vaught, Jr. 3201 Westmar Cir. 399 W. Riverview Ave. P.O. Box 13557 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Cory Quarles Richard Wagner Darwin Waldsmith Alaska Production Manager P.O. Box 60868 P.O. Box 39309 ExxonMobil Production Company Fairbanks, AK 99706 Ninilchik, AK 99639 P.O. Box 196601 Anchorage, AK 99519-6601 2C-)1S Angela K. Singh 0 0 ExxonMobil Production company P. Q. Box 196601 Anchorage, Alaska 99519-6601 907-561-5331 Telephone 906-564-3677 Facsimile July 16, 2015 Cathy P. Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501-3572 RE: Point Thomson Unit Pool Rules Application Dear Commissioner Foerster: Cory E. Quarles Alaska Production Mar: - E-zzonMobil Production: RECEIVED JUL 16 2015 ExxonMobil Alaska Production Inc. (ExxonMobil) as operator and on behalf of the Point Thomson Unit (PTU) Working Interest Owners (WIOs) hereby submits to the Alaska Oil and Gas Conservation Commission (Commission) the attached application for pool rules for the proposed Thomson Oil Pool. The requested gas offtake rate of 1,100 million standard cubic feet per day annual average is premised on a major gas sales development plan that will produce gas for delivery to facilities of the Alaska LNG Project and produce liquid condensate for delivery to the Trans -Alaska Pipeline System. The PTU WIOs believe the described development plan is prudent and will develop the Thomson reservoir hydrocarbon resources consistent with good oilfield practices and sound engineering in compliance with AOGCC statutes and regulations. The application is being submitted at this time so the necessary approval will be in place to support the Alaska LNG Project and PTU engineering schedules. Approval of the gas offtake rate will provide a firm basis for the design work and to commit to the substantial associated engineering costs. Please note that a portion of the application is requested to be held confidential pursuant to AS 31.05.035(d), 20 AAC 25.537(b), and AS 45.50.910 et seq. The confidential portion is enclosed in a separate envelope and marked as such. The PTU WIOs appreciate the time and effort of the Commissioners and staff and respectfully request that a hearing be scheduled between August 31 and September 15. Our goal is to have a decision on the pool rules application by October 30, 2015. Please contact Keith Breiner at 832-624-3763 or via email at"keith.e.breinereexxonmobil.com" if you have any questions. Sincerely, �` -- CEQ L, Attachments cc: PTU Working Interest Owners A Division or Exxon Mobil Corporation Pool Rules Application Point Thomson Unit July 15, 2015 • Table of Contents Pool Rules Application Point Thomson Unit PTU Pool Rules Application 10 INTRODUCTION 1 2.0 GEOSCIENCE AND RESERVOIR DESCRIPTION 4 2.1 DESCRIPTION 6 2.2 DEPOSITIONAL SETTING 6 2.3 STRUCTURAL SETTING 13 2.4 FLUID CONTACTS 15 2.5 POROSITY PERMEABILITY TRANSFORM 16 3Q GAS IN PLACE 17 3.1 GROSS ROCK VOLUME 17 3.2 POROSITY (BY FACIES) 17 3.3 SATURATION 20 3.4 FORMATION VOLUME FACTORS 22 3.5 RESULTS 22 4.0 DESCRIPTION OF RESERVOIR MODEL 23 5.0 RESERVOIR DEVELOPMENT PLAN 25 5.1 REFERENCE CASE DEVELOPMENT PLAN 5.2 POSSIBLE COMPRESSION FACILITIES 25 25 bQ WELLS 26 6.1 IPS WELLS 26 6.2 GAS EXPANSION WELLS 26 6.3 WELL SPACING 26 SURFACE FACILITIES 27 7.1 EXISTING INFRASTRUCTURE / INITIAL PRODUCTION SYSTEM 27 7.2 GAS EXPANSION 27 O.Q MODEL RESULTS 28 8.1 REFERENCE CASE DEPLETION PLAN 28 8.2 OFFTAKE RATE SENSITIVITIES 30 PRODUCTION MEASUREMENT AND PRODUCTION ALLOCATION 30 9.1 PTU EXPORT CONDENSATE MEASUREMENT 30 9.2 PTU EXPORT GAS MEASUREMENT 30 9.3 PTU WELL ALLOCATION 30 9.4 AOGCC APPROVAL OF CUSTODY TRANSFER MEASUREMENT AND WELL ALLOCATION 31 0 s PTU Pool Rules Application 10.0 GAS OIL RATIO 31 11.0 RESERVOIR SURVEILLANCE AND MONITORING 31 12.0 OTHER DEVELOPMENT CONSIDERATIONS 31 12.1 OIL RIM 12.2 GAS CYCLING 12.3 PTU GAS TO PRUDHOE BAY UNIT 31 32 34 13.0 CONCLUSION 35 14.0 PROPOSED POOL RULES 35 APPENDICES - CONFIDENTIAL ATTACHMENT 1 1.0 CONFIDENTIAL WELL AND RESERVOIR INFORMATION 1 2.0 EXPANDED GAS CYCLING CONFIDENTIAL MATERIALS 4 PTU Pool Rules Application 1.0 Introduction This application for Pool Rules is submitted to the Alaska Oil and Gas Conservation Commission (Commission) in accordance with 20 AAC 25.520 to establish pool rules for development of the Thomson reservoir, including approval of gas offtake rates. The application is submitted by ExxonMobil Alaska Production Inc. (ExxonMobil) as operator on behalf of the Point Thomson Unit (PTU) Working Interest Owners (WIOs). Figure 1.0-1 shows the general PTU vicinity and Figure 1.0-2 shows the PTU boundaries and proposed Thomson Pool' superimposed on a section -township -range grid. The corresponding legal description is provided in proposed Rule 2, Table 14.0-1. The PTU WIOs will apply for a Participating Area to the Alaska Department of Natural Resources (DNR) as provided in DNR regulatory requirements. Figure 1.0-1 Point Thomson Unit General Vicinity 'While AOGCC regulations do not define an oil pool or gas pool, Point Thomson wells would be classified as oil wells. ExxonMobil would consider the Thomson reservoir to be a gas condensate reservoir or pool, but recognizes the AOGCC regulatory structure that could classify the Thomson reservoir as an Oil Pool. - 1 - • 0 PTU Pool Rules Application W s e e a m m m m Beaufort Sea POINT THOMSC�N UNIT, „ ,o zo z, zz za z. 1s PTU-17z, ;PTU-15 1 (2016) 1 17 �=s�ae z. eez.es�zaIsxr Irian B , Is x z, zz m >r x 3, m zz , ,o , 10N T10 TM PTU-16� s s > a . ,z , a s ,o „ ,z , a a ,z , t —j- 11 n za z< ARCTIC NATIONAL e z zo w . WILDLIFE REFUGE T9N T9N i T8N ' a : a a z , e s a A T8N a Note: Number and location of Gas Expansion J " wells are tentative and subject to change as development progresses. ,z r e o m n v v a /ia E*(onMobil @ • PTU Initial Production System Wells „ „ „ „ !. „ " � X'•11•' /s r.. PTU GAS EXPANSION PROJECT • PTU Gas Expansion Wells -- I n m PROPOSED THOMSON POOL Proposed Thomson Pool 0 u s ° �� °' • z? za zs ee--- n MI oo . ze - -z JULV 2015 FIGURE 1.0-2 Figure 1.0-2 Proposed Thomson Pool This application is premised on a major gas sales (MGS) development plan that will produce gas from the Thomson reservoir, extract condensate from the gas and deliver the gas into a gas transmission line and other facilities of an Alaska LNG project. This development plan is consistent with good oil field engineering practices. The participants in the Alaska LNG (AKLNG) Project have been progressing plans for that project. Based upon the schedule provided to the Alaska legislature in January 2015, the AKLNG Project participants plan to decide whether to proceed to the next stage of that project, Front -End Engineering & Design (FEED), by 2Q 2016. FEED for the AKLNG Project will require a significant commitment of resources, and a key consideration for the project participants will be that sufficient gas supplies will be available to support the project. The PTU WIOs are submitting the pool rules application at this time so the necessary approval will be in place by October 15, 2015, to support the AKLNG Project and PTU Gas Expansion (GE) Project engineering schedules. Approval of an allowable gas offtake rate is needed to commit -2- 0 • PTU Pool Rules Application to the substantial PTU engineering costs required to progress this effort and to have a firm basis to design the PTU wells and facilities. Gas recovery from the Thomson reservoir in an MGS scenario shows little to no sensitivity to the gas offtake rates, and based upon the technical definition work that has been performed, the WIOs request an allowable annual average offtake rate of 1,100 million standard cubic feet per day (MMSCFD). This rate will provide flexibility in design and operations of the PTU facilities and wells that will be used to deliver gas to the gas treatment plant being designed for the AKLNG Project and to account for seasonal variations. During normal operations, it is envisioned that the gas offtake rate from PTU will be approximately 920 MMSCFD at peak winter rates and approximately 820 MMSCFD on an annual average basis. As discussed in this application, ultimate hydrocarbon recovery from the Thomson reservoir for an MGS, such as the AKLNG Project, would be essentially the same as would be obtained from a combination of gas cycling and gas sales, and the timing of hydrocarbon recovery will occur much sooner under an MGS scenario. This application addresses specific requirements associated with approval of gas offtake. As engineering design and field construction progress, additional pool rules may be sought if necessary to address other aspects of field development. Background The PTU was formed in 1977 and is operated by ExxonMobil. The approximate working interests of the W10s are: Exxon Mobil Corporation 62.24% BP Exploration (Alaska) Inc. 32.04% ConocoPhillips Alaska, Inc. 4.96% 21 other owners with a total combined working interest of less than 1%2 The State of Alaska is the landowner and the royalty interest owner of the PTU leases. The Thomson reservoir was discovered in 1977 with the Point Thomson Unit No. 1 (PTU_1) well. The reservoir is a high-pressure gas condensate reservoir containing a thin oil column that underlies state lands onshore and state waters offshore. Following discovery, additional wells were drilled to confirm and delineate the field and initiate development. To date, a total of 22 Z Assignment of working interest by three owners is awaiting approval by DNR, which would reduce the number of working interest owners. -3- PTU Pool Rules Application wells in the PTU area have been drilled of which 18 have penetrated the Thomson reservoir or equivalent subsurface level. Since discovery, it has been recognized that the PTU gas field could best be developed through a North Slope gas sales project, but that it would require a number of years to develop the transportation and other infrastructure needed to bring the gas to market. Full field gas cycling has been considered, most recently in the early 2000s, but was not found to be viable. The WIOs approved the Initial Production System (IPS) to initiate commercial development of the field and to provide the foundation for further development. The IPS will: 1) bring natural gas and condensate to the surface from the Thomson reservoir, 2) recover liquid condensate, and 3) re -inject the residual gas back into the reservoir. The condensate will be transported through the recently constructed Point Thomson Export Pipeline (PTEP) for delivery to the existing Badami, Endicott and Trans -Alaska Pipeline System common carrier pipelines. The IPS Project includes drilling wells, installing and operating infield pipelines and processing facilities, and installing support infrastructure including the PTEP. In its full production mode in 2016, the IPS will have one producing well (PTU_17) and two gas injection wells (PTU_15 and PTU_16). Gas will be produced at the rate of approximately 200 MMSCFD and routed to the Central Processing Facility (CPF) where up to 10 thousand barrels per day (MBD) of condensate will be extracted from the gas. Some of the gas will be used as fuel for the processing facilities. The remainder of the gas will be injected back into the Thomson reservoir to help maintain reservoir pressure and conserve the gas for future development. The IPS will provide information about the effectiveness of gas condensate production and reservoir connectivity to assist in subsequent development plans. The wells and most of the IPS infrastructure were developed in a manner to support future gas production from the field. 2.0 Geoscience and Reservoir Description The Thomson reservoir corresponds to depths 16,126' to 16,377' measured depth (MD) (-12,614' to-12,828 True Vertical Depth Subsea or TVDSS) on the PTU_15 type log which is a well drilled high on structure (Figure 2.0-1). This reservoir has about a five hundred foot thick gas cap and a thin, thirty-seven foot thick oil rim. Over part of the pool area, hydrocarbons (gas) lie directly on rock. In part of the field, the reservoir rock is fractured pre -Mississippian basement (Figure 2.0-2). The entire area is considered to be in pressure communication. -4- 0 • PTU Pool Rules Application PTU 15 [SSTVD] GR 0 GAPI 3001 SSTVD I NI DRES RHOB PHIT 11652 5onarosnc ,R 125W Ism 5 PIWrIs NPHI * CPOR 0.50 O.Dc SRE` Gas 10% Pot r r 12600 12703 12800 ,ezae A t6343 s Hue/HRZ Shale N -12 614' n — z + `, Upper Thomson Lower Thomson -12 828' TV! 199f10 tfi4fit 3 Pre -Mississippian Ancomont Track 1: Gamma ray and VShale Tract 2: Deep, medkim, and shallow resistivity (0.2 — 2000 ohm m) Trade 3: Density (Rhob,1.65-2.65a/em3) and Neutron Porosity (0-0.60) Tract a: Total Porosity with core porosity points (0.0.50) Figure 2.0-1: The Thomson sand interval in the PTU-15 well, shown with the overlying Hue/HRZ Shale and Canning Fm and the underlying pre -Mississippian basement. This well is high on structure, will be an injector well during IPS, and a producer during Gas Expansion PTU-15 A '7 /DSS )SS Figure 2.0-2: Schematic cross section, oriented approximately in a dip orientation, showing the Thomson Sand overlying Upper pre -Mississippian basement and overlain by the Hue/HRZ Shale. Two regional unconformities are represented by red dashed lines -5- PTU Pool Rules Application 2.1 Description Generally, the hydrocarbon accumulation is defined by a gently dipping anticlinal closure with a stratigraphic barrier to the southwest part of the field. The gas cap is confined by the overlying Hue/HRZ Shale and the Canning Formation. The crest of the reservoir is approximately-12,400' TVDSS and extends to about-14,500' TVDSS in the Unit area. Reservoir pressure is about 10,100 psi at-12,700' TVDSS, the approximate midpoint of the gas cap. Average reservoir temperature is 220-2307. Twenty-two wells have been drilled in and near the Unit, including the recently drilled Class I disposal well. Eighteen wells penetrated the Thomson level. Sixteen of the eighteen wells encountered Thomson reservoir, and the Thomson is eroded in two wells. Four wells penetrated only the shallower sands in the Brookian section and provide valuable information for velocity modeling in the overburden. Further description of the distribution of Thomson reservoir across the Unit can be found in Section 2.3: Structural Setting. Over 1,750 feet of Thomson whole core has been obtained from twelve wells. The primary seismic dataset is a 3D cube acquired in 1989, which covers approximately 85% of the Unit area. This survey was reprocessed in 2013-2014 in order to improve imaging throughout the section (permafrost through basement). 2.2 Depositional Setting The Thomson reservoir is a clastic reservoir deposited on a regionally extensive, Lower Cretaceous unconformity. The Thomson reservoir is interpreted to be a fan delta which prograded primarily in a southwest direction from a northwest — southeast trending paleo-high (Barrow Arch, Figure 2.2-1). Proximal Thomson reservoir, near the erosional limit, consists of poorly sorted alluvial fan breccias and subaqueous conglomerates which grade to the southwest into well -sorted clean sandstones. Distal reservoir comprises silty sandstones and siltstones. A conceptual stratigraphic trap lies along the south/southwest margin of the reservoir that is formed by an increase in shale content, decrease in porosity and permeability, and lack of hydrocarbons. The detrital composition is very similar to the pre -Mississippian lithology of dolomite, argillite, quartzite, and phyllite. Generally, coarser grained lithologies are dominated by carbonate lithics, and greater concentration of quartz and ductile grains are present in the distal portions. The Thomson reservoir is divided into Upper and Lower sub -units based on stacking patterns observed in core description and log character. The Lower Thomson exhibits a prograding character which is overlain by an overall, backstepping and retrogradational Upper Thomson (Figure 2.2-2). ll 0 • PTU Pool Rules Application SyoRF.c `1 oRes E` �f RO_f 0� S FO OrpsSIyOq— f Figure 2.2-1: Schematic of fan delta environment for Point Thomson -7- t >iv Pa� Weu X "I',,',',,, M a al- 0 PTU Pool Rules Application A r'nl_16 S lS,_1RD " -- — 7--- Ah U' Non roe offstwre tranutionill j Distal tower Shorefue ® Proximal tower Shoreface - Upper Shaeface f oreihore .foreshore wwoX wed . Alto" f an C A Present Day Structure PTU-01 i PTU•15 A' Conventional Core �1 Open Frame Conglomerate Bimodal Conglomerate Clean Sand Silly Sand Cemented Breccia S tstone Cemented Conglomerate Transgression _of W STNS- t UPpet�om Basal Cemented Zone Figure 2.2-2: Top: view of Upper Thomson environments of deposition. Bottom: cross section through A -A' showing depositional environments with petrofacies described in core Thomson Reservoir Petrofacies: Six petrofacies are identified in core based primarily on grain size and modified where appropriate by degree of cementation, sorting, and ductile grain content (Figure 2.2-3). These six petrofacies also form logical groupings in a porosity and permeability plot. Conglomerates are divided into three petrofacies based on sorting and degree of cementation. Open Framework Conglomerate (PF-1), as the name implies, has framework clasts with very little sand or silt -sized particles as matrix. This Open Framework Conglomerate, to date only found 9 • PTU Pool Rules Application in the PTU_15 well, leads to excellent reservoir quality with porosity values up to 28% and permeability ranging from hundreds of millidarcy (mD) to tens of Darcies (D) (permeability measurements described in this section are ambient permeability relative to air). In contrast, the Bi-Modal Conglomerate (PF2) has a wide range of grain sizes, from boulder and pebble clasts to sand and silt size particles acting as matrix. Bi-modal Conglomerates still exhibit good reservoir quality, with average porosity —14% and permeability ranging from —1 mD to less than 10 D. Cemented Conglomerate & Breccia (PF5) have a similar grain size distribution as Bi-Modal Conglomerates, but a high degree of cementation (>10% calcium carbonate), making them poor quality reservoir rocks (less than 8% average porosity and 0.1 mD). PF-2 Bi-modal Conglomerate PTU-15. 16288.7 ft MD Poorly sorted conglomerate Increasing presence of fines obstructing pore space. r•r.-3 a & D Cemented Cong. &�4Breccia a � o AK-G2. 15741.3ft ,10-,cement PF-1 Open Framework Conglomerate PTU-15. 16309,8 It MD Moderately well sorted. elf pore space not obstructed by the presence of fine to very fine grain sand. 100", 4 o n� S 1'J.'.. l � locr trn 0 1 E t➢ , ,Mjt�'pc�J■1y, ••••1'•Y.T Y•• PF, U • +'•'`t�'1:• PF2 ... W PF, PFi 701 •. PF6 0 Al 000 0.05 0 10 015 0.20 0.25 030 0.35 0" Core Porosity PF-3 High Quality Sandstone PTU-15,16208.2ft Low ductile grain content. Primarily found in the northern wells. PF-4 Poor Quality Sandstone rf �� Y y J6�t PTU-4,14973.2ft High ductile grain content. Primarily found in the southern portion of the field. Figure 2.2-3: Petrofacies observed at Point Thomson: core porosity and permeability for six petrofacies, and photomicrographs or whole core photo are shown for five petrofacies (Siltstone petrofacies not pictured). There are two sandstone petrofacies: Clean Sand (PF-3) and Silty Sand (PF-4). Clean Sand petrofacies generally has <10% ductile grain content, and is of very good quality with an average porosity of 24% and permeability in the range of hundreds of mD to less than 10 D. The Silty Sand petrofacies contain > 15% ductile fragments, and are poorer quality reservoir M 0 • PTU Pool Rules Application (average porosity 12%, permeability less than 10 mD). Siltstone is the sixth petrofacies (PF-6), and, similar to Cemented Conglomerate & Breccia, makes very poor quality reservoir (permeability less than 1 mD). A marine setting is indicated by trace fossils including Helminthopsis, Terebellina, Diplocriterian, and Asterosoma; these are observed in fine-grained sandstones and siltstones. Thomson Reservoir Depositional Environment: In general, there is an overall trend of coarse -grained to fine-grained rocks from NE to SW. Cemented conglomerates and breccias are found in Alaska Island #1 (AK ISL_1), Alaska State F-1 (AK_F1), and Alaska State G-2 (AK_G2), and are interpreted to be remnant alluvial fan deposits of the most updip portion of the fan delta system. Another distribution of cemented conglomerate and breccia is found at the base of the Lower Thomson, centered around the PTU_1 and spread in a NW -SE elongate form (Figure 2.2-4); the areal distribution of this deposit is aided by seismic mapping as a phase reversal on the base Thomson (trough converts to a peak where cemented conglomerate is present). These cemented facies are interpreted to be an early, severely eroded alluvial fan that was transgressed by the main section of Thomson reservoir. The less cemented conglomerates and clean sandstones also form an elongate strip in the middle portion of the field (e.g. PTU_1, PTU_3, and PTU_16, Staines River State #1 [STNS_11), and the silty sandstones and siltstones are found along the southwest fringe (PTU_4, West Staines State #1(WSTN_1) and #2 (WSTN_2). 11"111 PTU Pool Rules Application �oeroo aeaoo awao uz000 aa0000 aae000 ase000 a6a000 afz000 aeoaao aea000 assaao saaaoo smoa Thick—s [el ON ql f al(_Ft p AI[ Al C L U 93 I3 • vru,� 'U� n- - / p aa Ak, - t pp$ srr{ie 1 8 �l SOUR 3 0 �� q auB000 416000 424W0 432ppp 440pp0 44000 44000 a6a0W 2 4l2ppp 4eaoo0 a✓Spppp a9woo 1:f6M00 SW000 51 PTU-1 Uppfomson Lower Thomson _ Lower Upper pre-Mlssissipplan A A' Figure 2.2-4: Isochore map of the Basal Cemented Zone. The depositional setting of the Thomson reservoir is interpreted as a fan delta system: alluvial fan sediment gravity flows have prograded into subaqueous environment where material has been re -worked in an environment dominated by marine shoreface processes (Figure 2.2-1). Evidence for this setting includes: (1) overall poor sorting and high clast angularity, (2) presence of large grain sizes, including localized boulders, (3) presence of cohesive debris flow facies and (4) the presence of a narrow belt of conglomerates near the source terrain with rapid facies transition down -dip. A modern analog which exhibits the same petrofacies assemblages and distribution is the Rose Creek fan at Walker Lake, Nevada (Figure 2.2-5, Blair and McPherson, 20083). 3 Blair, T. C., and McPherson, J. G., 2008, Quaternary sedimentology of the Rose Creek fan delta, Walker Lake, Nevada, USA, and implications to fan - delta facies models, Sedimentology, v. 55, p 579 - 615. - 11 - 0 • PTU Pool Rules Application AAnalog- Rose Creek Fan Delta, Walker Lake Nevada n,� ;l B ol`� o c a )i 1 Alluvial Fan � Good quality reservoir- Thomson gnaVog Fan Delta (exposed by lake level drop) 'tm. fa su hypothetical wind direction (after. Blair and McPherson, 2008) Figure 2.2-5 : A: Aerial photo of Rose Creek fan and exposed fan delta . B: schematic of Rose Creek fan with Thomson Sand EODs superimposed. With the exception of the Cemented Conglomerates & Breccias, reservoir rocks for the Thomson reservoir are interpreted to be re -worked alluvial fan deposits in a deltaic, marine environment. The Open Framework Conglomerates are interpreted to be the result of rigorously re -worked foreshore deposits, a process which winnows away the interstitial fine sand component. In the analog from Walker Lake, seasonal winds focused energy in specific areas of the foreshore; a similar scenario is envisioned for the Thomson reservoir. These Open Framework conglomerates are interbedded with bi-modal conglomerates and clean sandstones, which are interpreted to be part of the same foreshore environment. The upper shoreface depositional environment is defined by a dominance of bi-modal conglomerate, clean -12- • 0 PTU Pool Rules Application sandstone, and minor siltstone. The proximal to distal portion of the lower shoreface is defined by minor conglomerate and clean sandstone updip to mostly sand to silty sand downdip. A "transitional zone" is defined by mostly silty sand and siltstone, and the offshore environment is dominated by siltstone; both of these environments are also characterized by marine trace fossils. Pre -Mississippian Basement Description: Few data are available which describe the reservoir quality and the distribution of reservoir for the basement. Basement lithology, as indicated by cuttings and available core, comprise dominantly dolomite, quartzite and phyllite. Drill stem tests recovering gas in the AK_F1 and AK_ISL_1 wells, and gas and water recovery in the Alaska State A-1 (AK —Al) well suggest that some permeability exists in the basement, possibly in a fracture or karsted system. Due to the limited amount of data, the upper pre -Mississippian zone has been treated with uniform properties. Minimal reservoir properties have been assigned to an upper layer of basement rocks: 1% porosity, horizontal permeability of 1 mD, and a vertical permeability of 78 mD. Higher vertical permeability is a function of fractured basement. 2.3 Structural Setting The top Thomson depth map is derived from seismic interpretation on a 3D time volume, converted to depth using a velocity model, and tied to picks in wells. Minor faults are observed in seismic, but they do not completely offset the Thomson reservoir; several do not even penetrate the top Thomson surface. Based on pre -reprocessed seismic (2001 processing), the average throw across faults is 65' to 95', and maximum throw values (near the fault mid -point) are 100-200'. The reprocessed seismic (2014) has slightly higher frequency content; therefore the presence, location, and throw of faults in the geologic model were re-examined. The number and location of faults was found to be very similar. Throw values were found to be lower in the reprocessed seismic, but the geologic model was not reconstructed (significant effort required to redesign and limited value added). The regional Paleocene unconformity ("PA50") has severely eroded the HRZ/Hue Shale and Thomson reservoir near the crest of the structure (Figure 2.0-2). Although three wells have penetrated the Thomson to the north of the limit (AK_F1, AK_ISL_1, AK_G2), these sand accumulations are interpreted to be erosional remnants; they are either not connected with the main part of the reservoir or the sand is below the hydrocarbon contact. Time to depth conversion is challenging at Point Thomson due to the position of the field straddling the coastline, the presence of permafrost and sea ice, and probable anisotropic behavior in the lower Brookian strata. The velocity model was updated in 2011, after drilling the PTU_15 and PTU_16 wells, and includes five strata intervals (Figure 2.3-1). The model -13- 9 • PTU Pool Rules Application begins at the OG75 surface, which is a gentle northeast -dipping horizon relatively easily mapped in seismic and shallow enough to be tied to all wells in the unit. Hanging the velocity model from the OG75 surface also reduces uncertainty by eliminating velocity variations in the permafrost. For the next two intervals, OG75-EO25 and E025-PA50, a Vok function was used which estimates the velocity with increasing depth. For the last two thinner intervals, PA50-top Thomson, and for the Thomson interval (top to base Thomson), a simpler average interval velocity was used. One of the key improvements in the 2011 velocity model is recognizing the importance of the E025 surface, which represents a major Eocene unconformity. The E025 has 2,000' relief across the Unit, and below this surface, abnormal pressure begins to build, affecting the velocity structure. PAM Sonic and Marken LAYER 1 OG75 .......••. LAYER 2 E025 LAYER 3 PAW- LAYER 4 Top Thomson LAYER 5 Base Thomson Figure 2.3-1: 2011 velocity model layers: Surface to OG75, OG75-EO25, E025-PA50, PA50-Top Thomson, and Top Thomson — Base Thomson -14- • 011 2.4 Fluid Contacts PTU Pool Rules Application The Oil -Water contact is estimated at-13,012' TVDSS and is based upon confidential well tests and log data. The contacts are discussed below, but further information is contained in the confidential exhibit. Gas -Oil and Oil -Water fluid contacts (GOC and OWC) are estimated using a combination of drill stem tests (DSTs) from the exploration program, modular dynamic tests (MDTs), fluid samples from the recently drilled PTU_15 and PTU_16 wells, and, to a limited extent, well logs. Petrophysical logs in most Thomson reservoir penetrations can only provide supporting data toward defining the contact because only half of these wells cover the contact range and most are in poor reservoir quality (silty or silty -sandstone petrofacies). The GOC is estimated to be-12,975 TVDSS. The GOC was identified in the PTU 15 and PTU 16 wells with MDT fluid samples and fluid identification sensors which analyzed gas at-12,973' TVDSS and oil at-12,979' TVDSS (Figure 2.4-1). The fluid samples identified in PTU_16 revealed a GOC 30' deeper than previously estimated, which reduced the oil rim thickness from 67' to 37'. In parts of the field, at the crest, gas -filled Thomson reservoir overlies basement rock. -15- 0 0 PTU Pool Rules Application ►TU•Is &W ►TU-ts RIOT ►n VS. D"M -V,we-►1V•tS MOT►rSapgS •►TU•tS YDT ►i1r•aaer q►Tt!•iS MDT ►naa►r '. r t ♦ ♦ W.MlAcd *$gas by LVO55 i ♦ Wenntwd at of t'y go ♦ �TVD S .. ♦ i �•Mb MMOt O.li.fr lVOff ♦ q � b♦ntMM n a! 6y pf Noss ♦r.ow q .t s.s .. TWU Figure 2.4-1: Results from the MDT pressure tests from the PTU-15 and PTU-16 , and fluid sample results from the PTU-16. The two fluid contacts are assumed to be constant across the field. This assumption is based on lack of compelling evidence for compartments and supported by the continuity in pressure v. depth profile both within and between the PTU-15 and PTU-16 wells (Figure 2.4-1). 2.5 Porosity Permeability transform Porosity v. permeability transforms were derived for each of the six petrofacies in the Thomson reservoir based on routine core analysis on core plugs (Figure 2.2-3). Most core plugs are from whole core; PTU_16 data were derived from sidewall cores. The permeability property in the geologic model is air permeability; relative permeability is estimated in the reservoir simulation model. Permeability values in the upper pre-Mississsippian basement are not strictly tied to porosity; as mentioned above, upper pre -Mississippian basement vertical permeability is 78 mD and horizontal permeability is assigned 1 mD. -16- PTU Pool Rules Application 3.0 Gas In Place Gas in place was computed using a 3D geocellular model constructed in Petrel software. The model contains five zones defined by six horizons: Upper Thomson, Lower Thomson, Basal Conglomerate, Upper pre -Mississippian, and Lower pre -Mississippian. Cell size is 400' x 400' with a 200 NE trend. Layer thickness in the Thomson intervals is five feet, and thickness in the pre -Mississippian intervals is distributed fractionally with finer layers near the top and thicker layers near the base (average thickness is —80'). The model includes 15 faults, but, as mentioned in Section 2.3, they do not significantly offset the Thomson reservoir. Modeling workflow begins with defining the structural framework, populating the model with petrofacies guided by the depositional environments, estimating porosity and permeability by petrofacies, then calculating saturation using saturation height functions and the fluid contacts. 3.1 Gross Rock Volume Gross rock volume is derived from the top and base surfaces of the Thomson reservoir and from the hydrocarbon contacts. The top and base Thomson surfaces are derived from seismic mapping in a 3D cube using the 2011 velocity model and tied to well data. These depth surfaces include the erosional limit of the Thomson and are input into the geologic model. 3.2 Porosity (by facies) Porosity is modeled through a process that begins with mapping environments of deposition (EOD) (described in Section 2.2). Petrofacies targets are assigned within each EOD and populated using proximal to distal trends (Figure 3.2-1). For example, the upper shoreface environment (USF) has a mix of Open Framework Conglomerate (2%), Bi-modal Conglomerate (75%), Clean Sandstone (20%), and minor Silty Sandstone (3%), but the Open Framework Conglomerate is distributed in the updip portion of the USF environment and Silty Sandstone percentage increases downdip. Each cell in the Thomson reservoir is assigned a petrofacies based on the petrofacies targets and trends. The porosity value is then selected from a range of porosities for that petrofacies. Histograms of porosity for each of the petrofacies is shown in Figure 3.2-2 and for all petrofacies in the Thomson reservoir in Figure 3.2-3. -17- 0 0 PTU Pool Rules Application LithotaciesDescorpiption EOD ecba bilt� Ved framework conglomeratic% nrt a i 5%PF1 Nla rly conglomerate FS w/ minor sand 85%PF2 10%PF3 LL a 2% PF 1 Mainly conglomerate 75%PF2 usF with increasing sand 20%PF3 m 3% PF4 LL v C f0 20% PF2 65% PF3 Pro - W 15%PF4 Mixed clean sand 6 LsF conglomerate 5%PF2 5% PF3 80"'. PF4 10"'. PHDistal 35% PF4 LL4 Dirty sand &silt \ 15"e PH � \ 69fi PF4 Silt OFS 95"o PF6 Figure 3.2-1: Petrofacies percentage targets for each EOD with proximal to distal trends -18- x 4 l 9 len Framework Conglom Silty Sandstone 4 2 rg nn �! II Bi-Modal Conglomerate • PTU Pool Rules Application Clean Sandstone ented Breccia + Conglomerate I Siltstone 3 MPWT_4'.L3 OPHIT find 3 Figure 3.2-2: Histogram of porosity for Thomson Sand cells in the model for each of the petrofacies. X-axis for all graphs is from 0 — 33%; Y- axis is % of cells in model and the values are variable. % 2 4 6 8 10 12 14 16 18 ZO 22 24 26 28 >tl 32 8 III. NP TRr,.13 Figure 3.2-3: Histogram for all petrofacies in the Thomson Sand, throughout the geologic model -19- 0 s PTU Pool Rules Application The average porosity for the Upper and Lower Thomson shows the general trend of very good porosity in the proximal position with a decreasing trend to the southwest (Figure 3.2-4). The thin rim of low porosity at the extreme updip edge is the cemented conglomerate and breccias that make up the alluvial fan environment. The double row of high porosity (red, orange, and yellow color bands) represents the distribution of good -quality open framework conglomerates and the clean sand petrofacies. This porosity distribution is the basis for the saturation models and the permeability transforms used in the reservoir simulation. 0 Porosity - total PHIT_Final_3 [U] 0.22 0.20 0.18 0.18 C 0.14 0.12 0.10 0.08 0.08 0.04 0.02 0.00 Figure 3.2-4: Average porosity from the geologic model. A= Upper Thomson, B= Lower Thomson (without basal cemented zone), C= Combined Upper and Lower Thomson 3.3 Saturation Hydrocarbon saturation is derived from the formula: (% Water Saturation) + (% Oil Saturation) + (% Gas Saturation) = 100% -20- PTU Pool Rules Application Water saturation is calculated for each of the six petrofacies, utilizing the various porosity - permeability relationships exhibited in the core data (Figure 2.2-3) and the saturation height functions. The saturation height function uses the J Function method to correlate capillary pressure data, assuming that all capillary pressure data for a given rock type can be represented by a dimensionless J curve. In the geologic model, therefore, water saturation calculation for each cell uses: • the porosity value based on the petrofacies assigned to the cell • permeability from a porosity -permeability transform for that facies • the capillary pressure, based on height above the free water level • interfacial tension • J-curve constants for the petrofacies, established from Thomson core The resulting water saturation v. J curve graph shows relative saturation models for the six petrofacies (Figure 3.3-1); the silty sandstone and siltstone facies use the same J-curve parameters. Water Saturation Relict Oil Saturation en Frame—ACongl odalConglomeratendstone O PF& Siky Sand and SlkoOPF7:CementdCongland L—PF 3000 b 00000 200 0 O 000 O O u 0 p 100.0 0000.... G O.. _. 00 0 0t 0) 0.a OA O.a 06 0.1 0. 0.9 1 U 02 04 06 U U 901 - 04 Saturabm Ivly) Figure 3.3-1: Left: J-curve functions for the six petrofacies (Sw v J function) Right: oil saturation v. height above the GOC using Dean Stark measurements i The J curve equations are helpful to calculate saturations for different rock types in a geologic model, especially when the rock types are defined using porosity -permeability relationships. The J curve approach is also important when lower -quality rocks are included as reservoir (e.g., siltstone). Listed below are approximate average water saturations in the gas cap for the six -21- CJ PTU Pool Rules Application petrofacies. These average saturations, in addition to the calculation above, also reflect the petrofacies distribution in the geologic model and their height above the OWC. • Open Framework Conglomerate (PF1): 5% • Clean sands (PF3): 15% • Bimodal conglomerate (PF2): 25% • Silty sand and Siltstone (PF4, PF6): 70% • Cemented Conglomerate and Breccia (PF 5a,b): 90% A "relict" oil saturation exists in the gas cap due to multiple heavy oil migrations through the reservoir in the geologic past. Oil saturations from Dean Stark measurements (using only wells drilled with water -based mud) were plotted by height above the GOC to develop a saturation height curve for relict oil in the gas cap (Figure 3.3-1). These data are not categorized by petrofacies so only one saturation height function is used throughout the gas cap. The relict oil saturation increases towards the gas -oil contact. Average oil saturation in the gas cap is approximately 10%. Gas saturation is the remainder of the simple saturation equation stated above. 3.4 Formation Volume Factors Formation volume factors represent the volumetric difference between the fluids in the reservoir and at the surface, and are used to convert volumes between "standard cubic feet" and "reservoir cubic feet." The volume factor used for gas volumetric calculations is 0.0029 rcf/scf (gas expansion factor 344 scf/rcf). Formation volume factors are calculated from the gas PVT characterization generated from fluid data collected from PTU_15, PTU_16, and STNS_1. These formation volume factors vary with composition and pressure, and the single values provided are volume -weighted to the fluids as they exist in the reservoir such that a volumetric calculation would result in the correct gas -in -place values. 3.5 Results The geologic model generates a volume using the 3D geocellular grid populated with properties for porosity, permeability, saturation, and formation volume factors as described above. Original gas in place (OGIP) for the Point Thomson Unit is approximately 8 TCF. This volume is stored mostly in the Thomson reservoir (but includes minor volume in the pre -Mississippian basement) and comprises free gas in the gas cap, solution gas from relict oil in the gas cap, and solution gas from the oil rim. Gas cap volumes have been rigorously analyzed with Monte Carlo analyses, calibrated with deterministic geologic models. -22- PTU Pool Rules Application 4.0 Description of Reservoir Model The Point Thomson reservoir simulation model utilizes finite -element simulation software developed by ExxonMobil to predict the subsurface physics, well behavior, and surface facilities integration with the field. The simulation model is based on the most current geologic interpretation and incorporates the six petrofacies seen in core (Open -Framework Conglomerates, Bimodal Conglomerates, Sandstones, Silty Sandstones, Siltstones, Cemented Breccia) and the pre -Mississippian basement. Each petrofacies is assigned unique properties for initialization: permeability, porosity, capillary pressure data, relative permeability data, and irreducible water saturations. The model is initialized using a gravity equilibrium algorithm that predicts gravity -stable fluid contacts and transition zones throughout the field. The model uses a 19-component Peng- Robinson density shifted equation of state that incorporates PVT analyses performed on the high -quality well test fluid samples from PTU_15 and PTU_16, and relict oil analysis from the STNS_1. The composition of the reservoir fluids is specified as a function of depth in the model to account for the fluid contacts, transition zones, and gas composition variance due to gravity segregation. An average composition of the gas and relict oil in the middle of the gas column is displayed in Table 4.0-1. In addition to the components and pseudo -components listed in the table, the Point Thomson gas contains as much as 30 ppm hydrogen sulfide (H2S) encountered during the PTU_16 well test. H2S is not included in the fluid characterization due to its immaterial impact on the fluid flow behavior in the reservoir. -23- CJ PTU Pool Rules Application TABLE 4.0-1 Average Composition of Gas and Relict Oil (asterisks indicate pseudo components) Phs Vapor Liquid Comp Mole Frac C1 84.88% 66.68% C2 3.85% 3.83% C3 1.66% 1.85% IC4 0.34% 0.40% NC4 0.52% 0.65% IC5 0.29% 0.38% NC5 0.33% 0.46% C6* 0.35% 0.59% C7* 0.42% 0.80% C8* 0.44% 0.96% C9* 0.31% 0.75% C12* 0.95% 3.03% C17* 0.65% 3.48% C27* 0.39% 3.97% C42* 0.12% 3.43% C65* 0.01% 2.35% C86+* 0.00% 2.23% N2* 0.93% 0.60% CO2* 3.56% 3.59% The reservoir simulator also incorporates wellbore hydraulics and surface facilities constraints. For each well, the simulator calculates the pressure required to lift gas, condensate, and water to the surface to determine the wellhead pressures. Based on the first stage separator pressure, the simulator can determine how much each well must be choked back to allow for a stable gas plateau rate from the overall facility. The sum of the gas, condensate, and water produced from each well determines the total facility rates. The simulator can optimize the individual chokes to prioritize or de -prioritize production from any given well (e.g., increase production from wells with higher condensate rates, decrease production from wells with high water rates). This allows for realistic simulation model prediction to mimic operating conditions throughout the life of the field. -24- 0 • PTU Pool Rules Application 5.0 Reservoir Development Plan 5.1 Reference Case Development Plan Development of the Thomson reservoir through a Point Thomson GE Project will be implemented with approximately seven new directional gas producing wells drilled through the Thomson reservoir from three onshore pad locations. The two IPS gas injectors (PTU _15 and PTU_16) will be converted to producers and the IPS producing well (PTU_17) will remain in production for a total of approximately ten producing wells (Figure 1.0-2). The reference development plan includes one additional well at West Pad, three additional wells at the Central Pad and three new wells at East Pad. The number of wells may change as optimization studies are completed and reservoir information and new well data are acquired. The PTU GE Project will produce natural gas, liquid condensate, and formation water. The nominal peak gas export rate from the field will be approximately 920 MMSCFD, with an annualized average export rate of approximately 820 MMSCFD. The condensate -gas -ratio (CGR) is a function of separation pressure. For the PTU GE Project, the initial CGR is anticipated to be approximately 60-65 stock tank barrels (STB) per million standard cubic feet (MMSCF), with an initial annual average condensate rate of approximately 50 thousand stock tank barrels per day (MSTBD). As gas and condensate are produced from the reservoir, the pressure in the reservoir will decline. This decline in the reservoir pressure will result in a decreasing condensate yield over time because some liquids will condense from the gas as the pressure is reduced and will remain in the reservoir. The proposed offtake rate balances production volumes, plateau life, and timing of potential boost compression, while providing sufficient gas for the AKLNG Project major gas sales opportunity. As described later in the application, condensate and gas recovery modeling show little to no sensitivity to gas offtake rates. To account for seasonal variations and provide flexibility in design and operations, the WIOs are requesting an allowable gas offtake rate of 1,100 MMSCFD. All gas volumes discussed in this application include carbon dioxide (CO2) and nitrogen (N2). 5.2 Possible Compression Facilities The wells will be allowed to flow until reservoir pressure can no longer deliver gas at plateau rates at the facility inlet conditions, at which point the field will go into decline. Current planning includes installation of compression facilities to lower the facility inlet pressure to extend gas and condensate plateau rates and potentially improve gas and condensate recoveries. A decision on whether to install compression facilities will be made after startup of the PTU GE Project. -25- 0 0 6.0 Wells 6.1 IPS Wells PTU Pool Rules Application The development of the Point Thomson IPS Project will be implemented with three directional wells drilled through the Thomson reservoir from two onshore pad locations. One of the wells will be a gas producer, and the other two wells will be gas injectors. The gas injector wells (PTU_15 and PTU _16) were drilled, cased, tested, and temporarily suspended at the Central Pad during 2009 and 2010. The PTU_17 producing well will be drilled from the West Pad in 2015-2016. The PTU_15 well may temporarily be in producing service to allow startup of the CPF while the PTU_17 well is being drilled. All three IPS wells will be completed using a Cased Hole Gravel Pack (frac pack) design to provide sand control for the high production rate wells. The injection wells are designed to ultimately be in gas production service. The IPS injection wells are capable of being converted to production service without requiring any downhole well work. A Class I disposal well (PTU_DW1) has been drilled from the Central Pad for drilling waste, produced water, and other waste liquids. 6.2 Gas Expansion Wells The reference development plan includes drilling approximately seven directional gas producing wells through the Thomson reservoir from three onshore pad locations. The two IPS gas injectors (PTU_15 and PTU _16) will be converted to producers and the IPS producing well (PTU_17) will remain in production service for a total of approximately 10 producing wells. The new wells in the reference development plan include one additional well at the West Pad, three additional wells at the Central Pad, and three wells at a new East Pad. All new wells are currently planned to be completed with similar frac pack designs to the three IPS wells. Studies are being conducted on open hole gravel pack completions that may improve well performance and reduce well count. Specific well designs will be addressed in drilling permit applications, which will be submitted to the Commission closer to the planned start of the drilling program. An additional Class I waste disposal well is also planned to be drilled from the Central Pad to serve as a backup disposal well. 6.3 Well Spacing The Thomson Pool will be developed on an irregular well spacing pattern as a function of reservoir architecture and reservoir quality. Wells at PTU are anticipated to comply with the well spacing requirements of 20 AAC 25.055, and no exceptions are requested. IK:2 PTU Pool Rules Application 7.0 Surface Facilities 71 Existing Infrastructure / Initial Production System The Point Thomson IPS infrastructure includes the Central Pad, the West Pad and the air strip, all connected by infield gravel roads, and marine facilities for sealift and seasonal barging. The Central Pad will contain the IPS CPF, two injection wells as described above, and a Class I waste disposal well. The Central Pad also has an operations center and associated buildings and space for drilling laydown/operations. The Central Pad was constructed to provide space for drilling additional wells. The West Pad will have the PTU_17 well and chemical injection facilities required for start-up. The West Pad was also designed and constructed to provide space for drilling additional wells. A gathering line connecting the West Pad to the Central Pad and a condensate export line to Badami have been installed on vertical support members (VSM). 7.2 Gas Expansion The reference development plan currently consists of installing new processing facilities, new gathering lines and drilling new wells, all of which will be integrated with existing IPS facilities, wells and infrastructure as necessary. The Central Pad gravel footprint will be expanded to accommodate new processing facilities, and an East Pad and connecting road will be constructed. At the Central Pad, new facilities for liquid/vapor separation, gas dehydration, gas conditioning, condensate stabilization, and produced water injection will be installed. In addition, a new utility module will be installed. These facilities will expand and/or replace existing IPS facilities at the CPF. The IPS Service Pier and Sealift Bulkhead at the Central Pad will support the GE Project. New mooring dolphins will likely need to be installed to support GE Project module offloading activities. Other new infrastructure associated with module offloading may also be required. The GE Project facilities are being designed to yield peak rates of approximately 60 MBD of associated condensate and approximately 920 MMSCFD of exported gas. At the CPF, a single process separation train will be coupled with two 50% tri-ethylene glycol (TEG) dehydration units and two 50% Low Temperature Separation Units (Expander and re -compressor units). The inlet separator will operate at approximately 1400 pounds per square inch gauge (psig), and the recovered liquids will be flashed by two additional lower pressure separators before being stabilized and cooled for export. -27- PTU Pool Rules Application The GE Project facilities are planned for co -location on the Central Pad with the IPS facilities, and operation of the IPS processing facilities will be discontinued prior to the GE Project startup. Power for the GE Project facilities will be provided by the IPS power generation, which includes normal operations, power for essential loads when the CPF is shutdown, and standby power. The IPS utilities module will be supplemented with a new utilities module as part of the GE Project. The stabilized condensate will be exported in the existing common carrier Point Thomson Export Pipeline to the common carrier pipeline system at Badami. A gas transmission pipeline to carry PTU gas to a central gas treating plant (GTP) in the Prudhoe Bay area is included within the AKLNG Project scope. As discussed in Section 5.2, compression facilities are being considered to extend the plateau rate and potentially improve hydrocarbon recovery. If installed, these facilities will be needed later in field life and will not be part of the initial PTU GE Project. 8.0 Model Results 8.1 Reference Case Depletion Plan The reference case depletion plan includes an annual average rate of approximately 820 MMSCFD that the simulation model predicts can be sustained for approximately 14 years at the current GE facility design inlet pressure. Approximately 65% of the total gas recovered occurs during the 14 year plateau period prior to booster compression installation. After the plateau period, the gas rate will decline because the reservoir no longer has enough energy (pressure) to lift the gas, condensate, and water to the surface at the inlet facility conditions. Therefore, the well rates decline and the overall facility export rates also decline. To extend the plateau period and potentially improve hydrocarbon recovery, installation of booster compression is being evaluated. Current modeling suggests that the addition of booster compression could extend the plateau life by 1-2 years. The predicted flow streams from the simulation model are shown in Figure 8.1-1 below. This figure displays annualized average gas, condensate, and water production for 30 years of gas sales and includes booster compression installation, which occurs around year 14. W-31 PTU Pool Rules Application 0000 Pt. Thomson Gas Expansion Production Profile 60.0 SM.0 700.0 n �1 600.0 sao.o nroo 3ao.o 200.0 100.0 0.0 Figure 8.1-1 Point Thomson GE Project Reference Case Production Profile (includes booster compression) The behavior of the Point Thomson reservoir during gas production is consistent with the description of a homogeneous gas reservoir. The pressure transient created by the displacement of gas moves through the reservoir, migrating more quickly through the high - permeability conglomerates and sandstones in the crest of the structure and slowing as it progresses through the poorer -quality sandstones and siltstones. While there are 15 mapped faults in the reservoir, none of them are expected to fully offset the Thomson reservoir and therefore gas is expected to be able to migrate through them. The simulation model predicts that reservoir pressure will decline by approximately 9,000 psi over 30 years of gas production, and this depletion of reservoir pressure - and therefore gas volumes - occurs relatively uniformly across the reservoir. In a retrograde gas condensate field, as the reservoir pressure is decreased - via the removal of gas volumes — liquid hydrocarbon will begin to condense out of the gaseous phase in the reservoir. At Point Thomson, much of this condensate is thought to be immobile once it condenses onto the reservoir rock. This means that it will most likely not be produced back as a liquid phase, and condensate produced at the surface is attributed to the condensate remaining in the gas phase. This is directly predicted in the simulation model flow streams as a decrease in condensate rate over time, even with the gas rate remaining constant during the plateau period. When the gas rate begins to decline, the condensate rate is impacted by both the decreasing condensate yield from the gas and the overall declining gas rate. -29- C� PTU Pool Rules Application In some fields, condensate remaining in the reservoir rock can impede gas flow through the reservoir. However, at Point Thomson the simulation model does not predict significant "condensate banking" due to the relatively high permeability of the reservoir and relatively low liquid dropout. 8.2 Offtake Rate Sensitivities A sensitivity study was performed using the simulation model to test the impact of different offtake rates on condensate and gas recovery from Point Thomson. Production rates ranging from 400 MMSCFD to 1200 MMSCFD were tested. In every case, it was observed that the gas offtake rate had no measurable impact on gas or condensate recovery so long as the field was allowed to produce to the same abandonment pressure in the reservoir — beyond the 30 year design life in lower offtake rate cases. In other words, if the Point Thomson field were produced at lower rates, the same amount of recoverable gas and condensate would be produced as at higher rates, but over a considerably longer period of time. At an offtake rate of 400 MMSCFD, it could take over 40 years to produce the same amount of gas and condensate the field could produce at 1100 MMSCFD in 30 years. This validates the current planned offtake rate request of 1100 MMSCFD as it balances facility design considerations, well count, and overall plateau duration and recoverable volumes within a reasonable field and facilities life. 9.0 Production Measurement and Production Allocation 9.1 PTU Export Condensate Measurement The existing PTU IPS condensate custody transfer meter will be expanded to accommodate the increased condensate volume from the GE Project. This is expected to use a Coriolis meter similar to the currently approved IPS meter. 9.2 PTU Export Gas Measurement A gas export custody transfer meter will be installed at the Central Pad. The export gas will contain CO2 and other byproducts that will be removed at the AKLNG Project GTP at Prudhoe Bay. Inlet and outlet flow will also be metered at the GTP. 9.3 PTU Well Allocation The current plan for allocating production to the PTU producing wells includes in -line multiphase meters on each well. In addition to providing a basis for well allocations, these meters will also provide for continuous measurement on a well by well basis. !sails PTU Pool Rules Application 9.4 AOGCC Approval of Custody Transfer Measurement and Well Allocation All custody transfer measurement and production allocation equipment and procedures will comply with applicable AOGCC regulations. GTP gas specifications have not been developed and other aspects of GE Project metering and production allocation have not been determined or finalized. Future requests will be made to the Commission for review and approval of custody transfer measurement and production allocation equipment and procedures in accordance with 20 AAC 25.228 and 20 AAC 25.230. 10.0 Gas Oil Ratio As inferred by Section 8.0 and Figure 8.0-1, gas oil ratios (GORs) will increase over time due to condensate rates declining faster than gas rates. This is inherent in the development plan for the Thomson gas condensate reservoir and does not indicate any inefficiency in the production mechanism. Since it is impractical to maintain GORs at or close to the original GOR, ExxonMobil requests a waiver from the requirements of 20 AAC 25.240 (a), as provided in 20 AAC 25.240 (c), which would limit production if the GOR increased by 100% of the original GOR). 11.0 Reservoir Surveillance and Monitoring ExxonMobil understands the need for reservoir surveillance and monitoring and will develop an appropriate program. Prior to startup of the PTU GE Project, ExxonMobil will provide its proposed reservoir surveillance and monitoring plan to the Commission. 12.0 Other Development Considerations In seeking to identify a viable development path, the PTU WIOs have evaluated or considered other potential development scenarios for the Thomson reservoir. Some of these have been reviewed with the Commission previously. A brief discussion is provided here for reference. 12.1 Oil Rim The oil rim (containing approximately 160 million barrels original oil in place as characterized by the geologic model discussed previously) is located between the gas cap and the underlying aquifer. The thickness of the oil rim, at about 37 feet, was established from MDT fluid identifications in the PTU_16 (described in Section 2.4). Most of its thickness is in the oil -water transition zone, in which both oil and water are partially mobile. The reservoir fluid is heavy oil, -31- • PTU Pool Rules Application approximately 10'to 18' API gravity, and the viscosity is approximately 2 centipoise (cP) at reservoir conditions. For a thin oil rim, horizontal wells are usually drilled to develop the resource. However, study results for a Thomson reservoir oil rim horizontal well development indicate that initially heavy oil from the oil rim would be recovered, followed by high rates of gas and water within weeks or months of initial production. After the onset of gas and water production, heavy oil production from the oil rim would be minimal and overall recovery very low. The oil rim wells would produce at high water cuts and high gas oil ratios. Other challenges affecting the viability of oil rim development are drilling long reach horizontal wells into the high and abnormally pressured Thomson reservoir and installation of separate facilities required to process heavy oil and separate large amounts of produced water. Consequently, due to these challenges and low anticipated production, production from the oil rim is not considered viable. 12.2 Gas Cycling Since discovery of the Thomson reservoir, it has been recognized that the reservoir could best be developed through a North Slope gas sales project, but that it would require a number of years to develop the transportation and other infrastructure needed to bring the gas to market. In the meantime, the WIOs pursued studies to identify a viable development option. A full field gas cycling project was intensively evaluated in the early 2000s. After considerable analysis, including significant subsurface technical evaluation, facilities and well engineering design and cost estimating, and regulatory permitting, the WIOs determined such a cycling project was not viable. Major impediments were the limited amount of condensate that could be recovered, the high cost of the facilities and wells, and the significant risks associated with a gas cycling development. Key among these risks included separating gas and condensate at approximately 3,000 psi, injecting gas at greater than 10,000 psi, and reservoir connectivity or gas channeling leading to poor sweep, gas breakthrough, and lower condensate recovery. While some of these considerations might also exist for a gas sales development scenario, they are more easily addressed for a gas sales development than a gas cycling development. As part of efforts to understand how the Thomson reservoir might be developed, ExxonMobil conducted an extensive study of 230 other gas condensate reservoirs. The results of that study did not find any reservoir with similar producing characteristics to PTU that was developed through a gas cycling approach. Reservoir injection pressures were one of the key differentiating factors. No other gas cycling project operated at pressures as high as those -32- 1] • PTU Pool Rules Application required for Point Thomson. Other gas cycling projects were at lower pressures and typically had higher gas condensate yields. Comparison ot'World-Wide Gas —Condensate Reservoirs I Blowdown Method _ i LJ Start of Cycling Method NPoint Thomson Unit i I 1 • 'There arc no retrograde gas- condensate reservoir cycling projects similar to Point'1'homson (-10,2(H) psi), although there are a few oil and gas reservoirs in the world that are in production at a higher pressure For comparison, Prudhoe Bay gas is at —35(X) PSI, although this is not a condensate reservoir Figure 12.1-1 Comparison of Cycling in World -Wide Gas Condensate Reservoirs The work to evaluate a full field gas cycling project for the Thomson reservoir that was previously undertaken by the PTU WIOs and resulting conclusions regarding viability was thorough. However, the WIOs also have assessed whether an expanded gas cycling project that utilizes wells and facilities designed for a gas sales project to the maximum extent practical, thereby minimizing incremental capital required for gas cycling, might provide sufficient additional recovery to improve potential viability. The results of this assessment are consistent with earlier work and have led the PTU WIOs to conclude that MGS is a preferable development plan to expanded cycling. Moreover, the PTU WIOs do not consider it prudent to pursue work that could adversely impact timing and viability of the AKLNG Project. For this assessment, it was assumed that expanded cycling would occur for 10 to 20 years, followed by gas sales, which would result in gas volumes and revenues not starting for a corresponding period of 10 to 20 years. Hydrocarbon recovery, on an oil equivalent barrel -33- PTU Pool Rules Application basis, would essentially be the same for gas cycling followed by gas sales as for a gas sales project, e.g., incremental condensate volumes are largely offset by additional fuel gas consumption contributing to reduced gas recoveries. While the IPS production operations will provide useful information about the reservoir, no scenarios have been identified in which this information would materially improve the current outlook for viability of expanded gas cycling. For instance, IPS operations could reveal high permeability streaks that lead to channeling/premature breakthrough of injected gas, or compartmentalization; either finding would impact cycling efficiency and reduce cycling recovery. The only potential factor that might appear to improve benefits from cycling would be if the condensate to gas ratio was higher than expected. However, the condensate to gas ratio has remained consistent in the gas samples collected from the numerous wells drilled at PTU. Significant deviation in the condensate -gas ratio discovered in new development wells may indicate that the reservoir is compartmentalized, which would be detrimental to an expanded gas cycling project. 12.3 PTU Gas to Prudhoe Bay Unit Another potential PTU development option would be to produce and deliver PTU gas to the Prudhoe Bay Unit (PBU) for injection into its primary reservoir. The current PTU GE Project subsurface and facilities engineering and regulatory/permitting work would largely be applicable to this option. This would reduce the duplication of manpower and costs if two distinct projects were pursued and potentially could allow such a project to progress on a similar time line. Based upon the current AKLNG Project and PTU GE Project schedules, however, the maximum acceleration in PTU startup under this option would be approximately one to two years. The gas transmission line between PTU and PBU, which is currently part of the AKLNG Project scope, would need to be accelerated (and potentially moved to PTU GE Project scope) to be used for a PTU to PBU option. Given the additional commercial, engineering and regulatory effort that would be required by the PTU WIOs, PBU WIOs, the AKLNG Project participants and the State of Alaska to pursue a PTU gas to PBU option, it is unlikely that the additional costs and diversion of resources could be justified for only a one or two year acceleration in PTU startup, which might not be achievable in any event. Any further consideration of this option would depend upon progress on the AKLNG Project. -34- 0 • 13.0 Conclusion PTU Pool Rules Application The most prudent development plan for Point Thomson is to simultaneously produce gas for delivery to an Alaska LNG project and condensate for export to the existing oil export pipeline system. The PTU WIOs request an allowable gas offtake rate of 1,100 MMSCFD. This will provide flexibility in design and operations of the PTU GE Project facilities and wells that will be used to deliver gas to an Alaska LNG project GTP, and account for seasonal variations. During normal operations, it is envisioned that the gas offtake rate from PTU will be approximately 920 MMSCFD during winter conditions, and approximately 820 MMSCFD on an annual average basis. Modeling shows ultimate recovery to have little to no sensitivity to the gas offtake rate at Point Thomson. Consistent with simultaneous gas and condensate production, ExxonMobil requests the Commission grant an exception to the requirements of 20 AAC 25.240(a) as provided in 20 AAC 25.240(c) which would otherwise limit gas offtake from the Thomson Pool. 14.0 Proposed Pool Rules ExxonMobil as operator on behalf of the PTU WIOs respectfully requests the Commission adopt the following Pool Rules for the Thomson Pool. Rule 1: Field and Pool Name The field is the Point Thomson Field and the Pool is defined as the Thomson Pool. Rule 2: Definition of Pool The Thomson Pool is defined as the accumulation of hydrocarbons corresponding to depths 16,126' to 16,377' measured depth (MD) (-12,614' to-12,828 True Vertical Depth Subsea or TVDSS) on the PTU_15 type log and contained within the area described Table 14.0-1. Rule 3: Gas Oil Ratio Exemption Wells producing from the Thomson Pool are exempt from the gas -oil ratio limits of 20 AAC 25.240 (a). Rule 4: Allowable Gas Offtake Rate The maximum allowable annual average gas offtake rate from the Thomson Pool is 1,100 million standard cubic feet per day (MMSCFD). -35- PTU Pool Rules Application Rule 5: 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. -36- 0 • PTU Pool Rules Application Table 14.0-1 Point Thomson Unit - Proposed Thomson Pool ADL No. Description 47557 T10N-R24E, UM Secs. 29, 30, 31, and 32 47558 T10N-R23E, UM Secs. 25, 26, 35, and 36 47559 T10N-R23E, UM Secs. 27, 28, 33, and 34 47560 T10N-R23E, UM Sec. 32 47561 T10N-R22E, UM Secs. 25, 26, 35, and 36 47562 T10N-R22E, UM Secs. 27, 28, 33, and 34 47563 T10N-R22E, UM Secs. 29, 30, 31, and 32 47564 T10N-R21E, UM Secs. 25, 26, 35, and 36 47566 T9N-R22E, UM Secs. 5, 6, 7, and 8 47567 T9N-R22E, UM Secs. 3, 4, 9, and 10 47568 T9N-R22E, UM Secs. 1, 2, 11, and 12 47569 T9N-R23E, UM Secs. 5, 6, 7, and 8 47570 MADE, UM Secs. 3, 4, 9, and 10 47571 MADE, UM Secs. 1, 2, 11, and 12 47572 T9N-R24E,UM Secs. 5, 6, 7, and 8 50983 T10N-R23E, UM Sec. 29 51667 T10N-R23E, UM Secs. 30 and 31 28380 T9N-R23E, UM Secs. 17 and 18 28381 T9N-R23E, UM Secs. 15 and 16 Sec. 21: N/2 Sec. 22: N/2 28382 T9N-R23E, UM Secs. 13 and 14 Sec. 23: N/2 Sec. 24: N/2 47556 T10N-R24E, UM Secs. 27, 28, 33, and 34 -37- PTU Pool Rules Application ADL No_ Description 47573 T9N-R24E, UM Secs_ 17 and 18 Sea. 19: N12 Sec. 20: NW 114 312862 TiON-R22&23E,UM TRACT C3D-110 (BF-11 D): A PORTION OF BLOCKS 753 AND 797 AS SHOWN ON THE "LEASING AND NOMINATION MAP" FOR THE FEDERAUSTATE BEAUFORT SEA OIL AND GAS LEASE SALE, DATED 1P30179, MORE PARTICULARLY DESCRIBED AS FOLLOWS: THOSE LANDS LOCATED IN THE S112 OF BLOCK 753, BEING A PORTION OF BLOCK 753 ON THE AFORESAID LEASING AND NOMINATION MAP, CONTAINING 1152.013HECTARES, AND THOSE LANDS LYING NORTHERLY OF THE SOUTH BOUNDARY OF SECTIONS 23 AND 24, T10N, R22E: U.M_, AK., AND LYING NORTHERLY OF THE SOUTH BOUNDARY OF SECTIONS 19AND 20. T10N, R23E; U.M., AK., IN BLOCK 797 (BEING THE NORTHERLY PORTION) LISTED AS STATE AREA ON THE "SUPPLEMENTAL OFFICIAL O.C.S. BLOCK DIAGRAM'APPROVED 1014f79, CONTAINING 1133.95 HECTARES. 312866 T10N-R23&24E, UM TRACT C313-114 (BF-114): A PORTION OF BLOCKS 799 AND 800 AS SHOWN ONTHE "LEASING AND NOMINATION MAP" FOR THE FEDERAUSTATE BEAUFORT SEA OIL AND GAS LEASE SALE, DATED 1130/79. MORE PARTICULARLY DESCRIBED AS FOLLOWS: THOSE LANDS LYING NORTHERLY OF THE SOUTH BOUNDARY OF SECTIONS 23 AND 24, T1ON. R23E; U.M., AK., AND LYING NORTHERLY OF THE SOUTH BOUNDARY OF SECTIONS 19 AND 20, T1DN, R24E; U.M., AK., IN BLOCK 799 (BEING THE NORTHERLY PORTION) LISTED AS STATE AREA ON THE 'SUPPLEMENTAL OFFICIAL O.C.S. BLOCK DIAGRAM'APPROVED 109179, CONTAINING 1081.11 HECTARES, AND THOSE LANDS LYING NORTHERLY OF THE SOUTH BOUNDARY OF SECTIONS 20.21. AND 22, T10N, R24E: U_M.,AK- AND LYING WESTERLY OF 140 DEGREES 00'00' WEST LONGITUDE IN BLOCK 800 LISTED AS STATE AREA ON THE "SUPPLEMENTAL OFFICIAL O.C_S. BLOCK DIAGRAM"APPROVED ID14179.CONTAINING916.21 HECTARES. 343109 T10N-11124E, UM Sea. 25: S12 Sea. 20 343110 T10Na224E, UM Secs_ 35 and 36 T9N-R24E, UM Sea. 2 343111 T9N-R24E, UM Seas_ 3.4. and 9 Sea. 10: N12 and SW14 343112 TW44124E, UM Sea. 15: All, excluding ANWR Sea. 10: Nf2 377020 T10N-1123E, UM That portion of Tract OM20, 'TRACT 05-020 ENCOMPASSES ALL THOSE LANDS IN THE S112 OF BLOCK 754 OCS OFFICIAL PROTRACTION DIAGRAM NR "APPROVED 429179, CONTAINING 1152 HECTARES, AND THOSE LANDS LYING NORTHERLY OF THE SOUTH BOUNDARY OF SECTIONS 20.21. 22AND 23, T. ION.. R. 23E.. UMIAT MERIDIAN, ALASKA IN BLOCK 798 (BEING IN THE NORTHERLY PORTION), LISTED AS STATE AREA ON THE 'SUPPLEMENTAL OFFICIAL OCS BLOCK DIAGRAM`APPROVED 1014179, CONTAINING 1109.94 HECTARES.' lying southerty of Sections 14, 15. 16 and 17. T_ 10 N.. R. 23 E., U.1M., Alaska in OCS Block 798_ -38- 0 • PTU Pool Rules Application ADL No_ Description 377016 T10N4i21E, UM T16N-R22E, UM That portion of Tract 65-016. `TRACT 65-018 ENCOMPASSES ALL THOSE LANDS IN THE S1f2 OF BLOCK 751, OCS OFFICIAL PROTRACTION DIAGRAM NR "APPROVED 4f29175, CONTAINING 1152-OD HECTARES, AND THOSE LANDS LYING NORTHERLY OF THE SOUTH BOUNDARY OF SECTIONS 23 AND 24, T. 10N., R. 21 E.. UMIAT MERIDIAN, ALASKAAND LYING NORTHERLY OF THE SOUTH BOUNDARY OF SECTIONS 19 AND 20, T ION- R_ 22E., UMIAT MERIDIAN, ALASKA IN BLOCK 795 (BEING THE NORTHERLY PORTION) LISTED AS STATEAREA ON THE "SUPPLEMENTAL OFFICIAL OCS BLOCK DIAGRAM"APPROVED 1014179. CONTAINING 1107.58 HECTARES.' lying within T ID N.. R. 22 E., U.M., Alaska, and the E112EI12 of Sections 1,. 12.13 and 24, T I N_, R. 21 E.. U.M., Alaska. 377017 T10N-R22E, UM T_ ION-. R_ 22E., UMIAT MERIDIAN, ALASKA TRACT 65-017 IS A PORTION OF OCS BLOCKS 752 AND 798 AS SHOWN ON THE "LEASING AND NOMINATION MAP' FOR THE FEDERALISTiATE BEAUFORT SEA OIL AND GAS LEASE SALE, DATED 1130179, AND MORE PARTICULARLY DESCRIBED AS FOLLOWS: TRACT 85-017 ENCOMPASSES ALLTHOSE LANDS IN THE S112 OF BLOCK 752, OCS OFFICIAL PROTRACTION DIAGRAM NR 64 APPROVED V29/75, CONTAINING 1152 HECTARES, AND THOSE LANDS LYING NORTHERLY OF THE SOUTH BOUNDARY OF SECTIONS 20, 21, 22 AND 23. T. ION., R. 22E_, UMIAT MERIDIAN, ALASKA IN BLOCK 706 (BEING THE NORTHERLY PORTION) LISTED AS STATE AREA ON THE "SUPPLEMENTAL OFFICIAL OCS BLOCK DIAGRAM"APPROVED 10/4179, CONTAINING 1153.17 HECTARES_ THIS TRACT CONTAINS 5&98.18ACRES MORE OR LESS (2306.17 HECTARES MORE OR LESS). 389728 T10N-R21E, UM That portion of Tract 85-010, -TRACT 05-016 ENCOMPASSES ALL THOSE LANDS IN THE S1f2 OF BLOCK 751. OCS OFFICIAL PROTRACTION DIAGRAM NR 64 APPROVED 4f2W75, CONTAINING 1152.OD HECTARES, AND THOSE LANDS LYING NORTHERLY OF THE SOUTH BOUNDARY OF SECTIONS 23 AND 24. T. 10N., R_ 21E_, UMIAT MERIDIAN, ALASKAAND LYING NORTHERLY OF THE SOUTH BOUNDARY OF SECTIONS 19 AND 20, T. ION_, R_ 22E., UMIAT MERIDIAN, ALASKA IN BLOCK 796 (BEING THE NORTHERLY PORTION) LISTED AS STATEAREA ON THE 'SUPPLEMENTAL OFFICIAL OCS BLOCK DIAGRAM" APPROVED 1014179, CONTAINING 1187.58 HECTARES.' lying within T. ION., R_ 21 E., U.M., Alaska, excluding the E1f2Eif2 of Sections 1, 12, 13 and 24. 389730 T10N-11123E, UM That portion of Tract 65-020. 'TRACT 65-020 ENCOMPASSES ALL THOSE LANDS IN THE S 1f2 OF BLOCK 754 OCS OFFICIAL PROTRACTION DIAGRAM NR 64 APPROVED 4129V7g, CONTAINING 1152 HECTARES, AND THOSE LANDS LYING NORTHERLY OF THE SOUTH BOUNDARY OF SECTIONS 21), 21, 22AND 23. T. ION., R. 23E_, UMIAT MERIDIAN, ALASKA IN BLOCK 798 (BEING IN THE NORTHERLY PORTION). LISTED AS STATEAREA ON THE "SUPPLEMENTAL OFFICIAL OCS BLOCK DIAGRAM" APPROVED 1014179, CONTAINING 1109.94 HECTARES." tying in the S112 of OCS Block 754, and lying northerly of Sections 20, 21. 22 and 23. T_ 10 N., R. 23 E., U.M., Alaska in OCS Bock 798_ 390310 T9N-R24E, UM Sao. I, ALLTIDE AND SUBMERGED LAND, EXCLUDING STATE OF ALASKA OIL AND GAS LEASE ADL 372256 AND THE ARCTIC NATIONAL. WILDLIFE REFUGE, 15.80 ACRES 9916,10