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AREA INJECTION ORDER NO.38 Point Thomson Unit May 1, 2015 ExxonMobil's Application for Area Injection Order Point Thomson Unit (2 pages held in secure storage) May 5, 2015 Notice of Hearing, affidavit of publication, email distribution, and mailing list May 14, 2015 Emails re: legal description of affected area July 7, 2015 Hearing transcript, sign -in sheet, ExxonMobil presentation July 9, 2015 ExxonMobil's post hearing response (attachment held in secure storage) AREA INJECTION ORDER NO.38 Point Thomson Unit • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue Anchorage, Alaska 99501 Re: THE APPLICATION OF ) Area Injection Order No. 38 EXXONMOBIL ALASKA ) Docket No. AIO-15-017 PRODUCTON, INC. for an order ) authorizing underground injection of ) Point Thomson Field fluids for enhanced oil recovery in the ) Point Thomson Unit Thomson Sand Undefined Oil Pool, ) Thomson Sand Undefined Oil Pool Point Thomson Unit, North Slope ) Borough, Arctic Slope, Alaska ) August 25, 2015 IT APPEARING THAT: 1. By application received on May 1, 2015, Exxon Mobil Corporation, in its capacity as operator of the Point Thomson Unit, requested authorization to reinject produced gas to enhance oil recovery in the Thomson Sand Undefined Oil Pool of the Point Thomson Unit. 2. Pursuant to 20 AAAC 25.540, the Alaska Oil and Gas Conservation Commission (AOGCC) tentatively scheduled a public hearing for July 7, 2015. On May 5, 2015, the AOGCC published notice of the opportunity for 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 to all persons on the AOGCC's mailing distribution list. On May 6, 2015, the AOGCC published the notice in the ALASKA DISPATCH NEWS. 3. On May 6, 2015, the AOGCC approved a Designation of Operator request to change the operator of the Point Thomson Unit from Exxon Mobil Corporation to ExxonMobil Alaska Production, Inc. (ExxonMobil) 4. On May 7, 2015, the AOGCC asked ExxonMobil to check the legal description of the proposed affected area in its application. 5. On May 14, 2015, ExxonMobil provided a corrected legal description. 6. No protest to the application or request for hearing was received. 7. The hearing commenced at 9:OOAM on July 7, 2015, in the AOGCC's offices located at 333 West 7th Avenue, Anchorage, Alaska. 8. Testimony was received from representatives of ExxonMobil. 9. The record was held open until July 14, 2015, to allow the operator to respond to requests made during the hearing. 10. ExxonMobil provided the requested additional information on July 9, 2015. Area Injection Order 38 • • August 25, 2015 Page 2 of 12 FINDINGS: 1. Operator and Owners: ExxonMobil is the operator of the leases in the area 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 60 miles east of Prudhoe Bay along Alaska's northern coastline. 2. Project Area Pool and Formations Authorized for Enhanced Recovery: ExxonMobil proposes to re -inject residual produced gas to enhance recovery from an accumulation of condensate and oil within the Thomson Sand of the Point Thomson Unit. In absence of a Conservation Order from the AOGCC formally defining a pool, this accumulation is properly termed the Thomson Sand Undefined Oil Pool and governed by the statewide rules of 20 AAC 25. ExxonMobil's target injection zone is correlative to the interval between 16,126 and 16,377 feet measured depth on the VISION/Scope Measured Depth Log recorded in reference well PTU No. 15 (PTU-15; see Figure 1, below). 3. Proposed Injection Area: ExxonMobil proposes to re -inject residual produced gas within the Affected Area shown on Figure 2, below. The Thomson Sand Undefined Oil Pool will be developed initially from the onshore, 55-acre Central Pad drill site (Central Pad), which is located in Section 34, Township ION, Range 23E, Umiat Meridian (see Figure 2, below). ExxonMobil's development plans include a second, onshore, gravel drill site (termed the "West Pad") that will occupy about 17 acres within Section 36, Township 10N, Range 22E, Umiat Meridian. To date, 16 wells have penetrated the Thomson Sand Undefined Oil Pool in the Point Thomson Unit area.' Information from these wells and from seven overlapping, three- dimensional seismic surveys was used to determine the geologic structure, reservoir distribution, and the area that will be affected by re -injection of produced gas. Production test, drill -stem test, down -hole sampling, core, and well log data were used to establish reservoir properties, fluid properties, and the gas -oil and oil -water contacts for this pool. 4. Operators/Surface Owners Notification: All lands within the proposed Affected Area are leased. The only affected surface owner is DNR. The only affected operator is ExxonMobil. ExxonMobil provided the application for injection to all working interest owners and the DNR, the only affected parties within one -quarter -mile of the proposed affected area. 5. Description of Operations: ExxonMobil's planned operations, termed the Initial Production System Project, will initially develop the Thomson Sand Undefined Oil Pool from the Central Pad using two wells: PTU-15, the initial gas producer, and PTU No. 16 (PTU-16), a gas injector. ExxonMobil plans to drill one additional well, PTU No. 17 (PTU-17), from the 1 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. Area Injection Order 38 0 • August 25, 2015 Page 3 of 12 Co"Lation Da th Rests pcmsq GR R-D RHOS 0 APi"_. 3 O�w.... 50001 65 GX3 3. SaM•Sik• NSF+ Rests ORHO .5 OFM 5 2 G1C3 0. ND R-S TP NPH) 15FfvTvf.. _..3 0 _...... —._y�T__ <ME) DTGP(wn) 170 : ion 15700 : so -t2300 Canning Formation 15" 12400 -12400 159M -Soo -12500 16000 -16000 -16000 Hue / HRZ Shale 16100 s } 12700 ' -;k e- Thomson 16200 Undefined -12700 - Jr Oil Pool -7- 1630d'260c -12soo 16400 , am - Basement 16500 Figure 1. PTU-15 — Reference Well Log for the Proposed Injection Interval, Thomson Sand Undefined Oil Poole West Pad and complete it as a gas producer. Upon completion of PTU-17, well PTU-15 will be re -completed as a gas injector. 2 Figure 1 is presented for illustration purposes only. Refer to the well log measurements on the VISION/Scope Measured Depth Log recorded in reference well PTU-15 for a more precise representation of the Thomson Sand Undefined Oil Pool. The horizontal grid lines in this figure represent increments of ten feet true vertical depth subsea. The acronym TVD refers to true vertical depth, and the acronym TVDSS refers to true vertical depth subsea (true vertical depth below sea level). Area Injection Order 38 • is August 25, 2015 Page 4 of 12 ExxonMobil's project will produce and sell condensate liquids associated with gas from the reservoir and then re -inject the residue gas as the enhanced recovery mechanism (informally termed "gas -cycling"). This process will preserve gas for reservoir pressure maintenance and for future development. This project will also provide information about gas condensate production and reservoir connectivity. Condensate production and gas re -injection are scheduled to begin during the first quarter of 2016. The IPS is designed to produce approximately 200 million standard cubic feet per day (MMSCFPD) of gas and transport it via surface flow line to the Point Thomson Unit production processing facility located at Central Pad. Approximately 10,000 barrels of condensate per day will be extracted and transported by above -ground pipeline from the Central Pad for delivery to the Badami, Endicott, and Trans -Alaska Pipeline System common carrier pipelines. Approximately 194 MMSCFPD will be reinjected into the Thomson Sand Undefined Oil Pool. RED DOG 11 CHALLENGE IS 1 ALASKA ISLAND 1 PTU 4 0 3 Miles Beaufort Sea L(Future) ------------ ` PTU 15 O ALASKASTD, PTU 3 We ----- Pad ` ` Cenfral PTU 1 ` ad O i ' -PSU 16 P.ZUItl.I PTU2 ----- W STAINES ST ALASKA W STAINES ST 16-09- Y C? STAINES RIV ST 1 STAINES RIV ST 1A SOURDOUGH 3 ALASKA ST G 2 ALASKA ST A 2 ALASKA ST A 1 SOURDOUGH 2 ES ANWR Figure 2. Affected Area of Injected Gas, Thomson Sand Undefined Oil Pool — Solid red line indicates of the Pt. Thomson Unit. Solid blue line indicates approximate outline of the Affected Area. Dashed blue line indicates approximate Initial Production System Area. 3 Confidential wells are shown in red. 3 This map is presented for illustration purposes only. For more precise depictions, refer to Figures 1 and 2 of ExxonMobil's Application for Area Injection Order, Point Thomson Unit, received May 1, 2015, and to the legal description included on pages 9 and 10 of this order. Area Injection Order 38 August 25, 2015 Page 5 of 12 6. Hydrocarbon Recovery: The Thomson Sand Undefined Oil Pool contains an estimated original gas in place volume of 8 trillion standard cubic feet. Short-term flow tests on wells PTU-15 and PTU-16 suggest a condensate yield of approximately 65 barrels of condensate liquids per one million standard cubic feet of gas under gas sales separation conditions. However, with the higher outlet pressure of a gas cycling separation system anticipated condensate yield for the IPS is approximately 50 barrels of condensate liquids per one million standard cubic feet. 7. Geolog : a. Stratigraphy: The Thomson Sand Undefined Oil Pool comprises the early Cretaceous - aged Thomson Sand, which lies between 16,126 and 16,377 feet measured depth in reference well PTU-15 (equivalent to-12,614 and-12,828 feet true vertical depth below sea level, which is also termed "true vertical depth subsea" and shortened to TVDSS'). The Thomson Sand lies unconformably atop pre -Mississippian -aged basement rocks comprising phyllite, argillite, quartzite, and dolomite. 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 are expected to be phyllite and quartzite. b. The Thomson Sand consists of conglomerate, sandstone, and siltstone derived from an area of Pre -Mississippian -aged basement rock that was exposed, during the early Cretaceous, in the northern and northeastern portion of the Point Thomson Field.5 At that time, these exposed basement rocks were bordered to the southwest by a sea. Sediments eroded from this exposed source area were transported down -gradient to the southwest and deposited in alluvial fan, fan -delta, and shallow marine shoreface environments. Accordingly, the grain size of the sediments comprising the Thomson Sand diminishes progressively toward the southwest. ExxonMobil has identified and mapped a flooding surface that informally divides the Thomson Sand into an upper member and a lower member. The lower member is dominantly progradational, whereas the upper member is dominantly retrogradational. ExxonMobil also informally separates the Thomson Sand into six petrofacies based on grain size, sorting, cementation, and ductile grain content. These petrofacies are: cemented conglomerate and breccia, open -framework conglomerate, bimodal conglomerate, clean sandstone, silty sandstone, and siltstone. Each of these petrofacies occupies a well-defined area on a plot of core porosity versus core permeability. 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 has thinned the Hue and HRZ shale intervals toward the northeast, and these intervals are not present in the northern and northeastern parts of the Point 4 To avoid confusion, when depths presented in the text represent true vertical depth subsea (i.e., true vertical depth below mean sea level), the footage will be preceded by a minus sign and followed by the acronym TVDSS (e.g., 13,300 feet below mean sea level is depicted by the phrase-13,300 feet TVDSS). 5 ExxonMobil, 2015, see Figure 14 in ExxonMobil's Application for Area Injection Order, Point Thomson Unit, received May 1, 2015. Area Injection Order 38 August 25, 2015 Page 6 of 12 Thomson Field. Where the Hue and HRZ intervals are absent or very thin, mudstone and siltstone comprising the lower portion of the Canning Formation will arrest fractures and provide upper confinement for injected fluids.6 c. Structure: The structure of the Thomson Sand Undefined 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.7 The anticlinal closure is cut by several, north- and north -northeast -trending, normal faults, but none of these faults appear to completely offset the Thomson Sand or create isolated compartments within it. d. Trap Configuration: Well log and seismic information indicate that the condensate and oil accumulation within the Thomson Sand Undefined Oil Pool is influenced by both structural and stratigraphic elements. The broad, east -southeast -trending, shale -capped anticlinal closure provides primary control for the accumulation. Facies changes within the Thomson Sand strongly influence reservoir quality, especially in the southwestern portions of the Point Thomson Unit. e. Confining Intervals: Preliminary modeling for well PTU-16 indicates planned hydraulic fracturing operations will be confined to the Thomson Sand, and will yield an effective fracture half-length of about 50 feet. Figure 1, above, depicts the confining intervals above and below the reservoir. The Thomson Sand is overlain by thick, laterally extensive accumulations of siltstone, mudstone, and shale that are assigned to the Canning Formation, Hue Shale, and HRZ Shale, in descending stratigraphic order. These intervals will provide the top seal that will keep injected fluids within the approved interval and arrest any fractures caused by injection operations. Pre -Mississippian -aged phyllite and quartzite basement rocks will arrest fractures and provide lower confinement for injected fluids. f. Reservoir Compartmentalization: Facies distribution, flow tests, and reservoir pressure measurements suggest that the Thomson Sand Undefined Oil Pool is not separated into isolated compartments within the Affected Area. g. Permafrost: Permafrost base lies at about -1,800 feet TVDSS within the Affected Area. Reservoir Properties: Within the Affected Area, reservoir porosity for the Thomson Sand ranges from about 5% to 34%, and averages about 14%. Permeability ranges from 0.01 millidarcies in some samples of cemented conglomerate and breccia to 50 darcies in some samples of open -framework conglomerate. 9. Reservoir Fluid Contacts: The gas -oil contact is-12,975 feet TVDSS from Modular Dynamic Tester (MDT) pressure measurements and fluid samples obtained in PTU-16. The oil -water contact is-13,012 feet TVDSS based on well tests and well log data from a well granted extended confidentiality by the DNR. The elevations of these contacts are believed 6 ExxonMobil, 2015, see Figures 11 and 19 in ExxonMobil's Application for Area Injection Order, Point Thomson Unit, received May 1, 2015. 7 ExxonMobil, 2015, Top Thomson Sand Structure Map in the Participating Area, Figure 5 in ExxonMobil's Application for Area Injection Order, Point Thomson Unit, received May 1, 2015. Area Injection Order 38 • • August 25, 2015 Page 7 of 12 to be constant throughout the Affected Area. 10. Reservoir Fluid Properties: Within the Point Thomson Field, the hydrocarbon accumulation trapped in the Thomson Sand comprises a nearly 500-foot thick, high-pressure, condensate "gas cap" and an underlying, 37-foot thick rim of viscous oil. Public -domain well test results for wells Alaska State No. A-1 and Pt. Thomson Unit No. 1 yield gas -oil ratios of 864 and 5,830 standard cubic feet of gas per stock tank barrel (scf/stb) of oil,8 which requires classification of the Thomson Sand accumulation as an oil pool.9 Flow tests of PTU-15 and PTU-16 indicate the API gravity of the condensate liquid is 38°. The API gravity of the black oil in the oil rim is reported to be 12-14°. Hydrogen sulfide (H2S) and carbon dioxide (CO2) are present within the Thomson Sand reservoir.lo 11. Reservoir Pressure and Temperature: Average reservoir pressure is about 10,100 psi at the datum of-12,700 feet TVDSS. Reservoir temperature ranges from about 220' to 230' F. 12. Well Logs: Logs of the injection wells, PTU-15 and PTU-16, have been filed with the AOGCC according to the requirements of 20 AAC 25. 13. Mechanical Integrity and Design of Injection Wells: The casing and cementing programs for all injection wells will comply with 20 AAC 25.030. Cement -bond logs will be run to demonstrate the isolation of injected fluids to the Point Thomson reservoir as required by 20 AAC 25.412(d). Mechanical integrity tests will be performed in accordance with 20 AAC 25.412(c). To facilitate installation of gravel pack completions, ExxonMobil has applied for and obtained waivers from AOGCC to 20 AAC 25.412(b) to allow packers in injection wells to be located more than 200 feet measured depth above the top of the injection zone but below the top of the upper confining zone. 14. Type of Fluid / Source: The only fluid requested for injection is gas produced from the Thomson Sand Undefined Oil Pool. 15. Compatibility with Formation: Evidence of water compatibility is not required unless ExxonMobil seeks approval from the AOGCC to inject produced water or non-native fluids into the Thomson Sand reservoir. 16. Injection Rates, Pressures and Pressure Monitoring: ExxonMobil proposes to develop this pool as a gas -only injection, enhanced condensate liquid recovery project. Expected maximum gas injection will be approximately 194 million standard cubic feet per day, which represents 200 million standard cubic feet per day of production minus liquids sold and fuel gas consumed. Re -injection of residual produced gas will maintain reservoir voidage at a ratio of about 0.97:1. Injection pressures are expected to average approximately 9,800 to 10,000 psi at the wellhead, and they will be limited to a maximum of injection pressure of 11,025 psi at which time the injection process will be shutdown. Mechanical Integrity Tests (MITs) will be conducted on injection wells as required by the AOGCC. 8 AOGCC, 1984, Statistical Report: Reservoir Data for Wells Alaska State A-1 and Pt. Thomson Unit No. 1, p. 103. 9 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 commission establishes another ratio. io An 112S concentration of 30 PPM was measured in PTU-16. ExxonMobil's estimated composition of the injected gas stream includes 4.5 mole percent CO2 (see Table 1 in ExxonMobil's Application for Area Injection Order). Area Injection Order 38 • August 25, 2015 Page 8 of 12 17. Fracture Information: The fracture gradient for the confining interval is estimated to be 0.91 psi per foot. Maximum planned gas injection pressure is 10,400 psi at reservoir level, so injection operations will not initiate or propagate fractures through the confining intervals. 18. Absence of Underground Sources of Drinking Water: In September 2009, the U.S. Environmental Protection Agency (U.S. EPA) confirmed that there are no underground sources of drinking water within the Affected Area. 11 19. Mechanical Condition of Adjacent Wells: Twenty-two wells have been drilled within the Point Thomson Field area. Of these, four are currently suspended and 18 wells have been plugged and abandoned. All of these wells have sufficient mechanical isolation to confine fluids and prevent cross -flow. 20. Hydraulic Fracturing of Wells: Small-scale, cased -hole, frac-pack operations will be conducted in PTU-15, PTU-16, and PTU-17. Short (about 40-foot), lateral fractures will be hydraulically induced and then filled with sized -sand that will act as a filter to prevent the flow of formation sand into the wellbores. CONCLUSIONS: 1. The requirements of 20 AAC 25.402 have been met. 2. The accumulation of condensate and oil within Thomson Sand is properly classified as an oil pool properly termed the Thomson Sand Undefined Oil Pool. 3. ExxonMobil's IPS Project will not cause waste, and it will provide reservoir, fluid, and production information that is critical to determining future development of the Thomson Sand Undefined Oil Pool. 4. There are no underground sources of drinking water beneath the proposed Affected Area. 5. Only residual, produced gas is authorized for re -injection into the Thomson Sand Undefined Oil Pool. A separate approval is required before injecting any other fluids into the pool. 6. The proposed injection operations will be conducted in permeable strata, which can reasonably be expected to accept injected fluids at pressures less than the fracture pressure of the confining strata. 7. Injected fluids will be confined within the appropriate receiving intervals by impermeable lithology, cement isolation of the wellbores, and appropriate operating conditions. 8. Daily to continuous well surveillance and reservoir monitoring coupled with regularly scheduled MITs will demonstrate appropriate performance of the enhanced oil recovery project and disclose possible abnormalities. An annual report of injection performance is warranted, and it must include an assessment of fracture propagation into adjacent confining intervals. 9. Setting the packers in the injection wells more than 200 feet measured depth above the 11 U.S. EPA, 2009: letter from E.J. Kowalski, Director of the Office of Compliance and Enforcement, to D. Pittman, ExxonMobil Production Company, date stamped Sep 25 2009; included as Exhibit 4 in ExxonMobil's Application for Area Injection Order, Point Thomson Unit, received May 1, 2015. Area Injection Order 38 August 25, 2015 Page 9 of 12 injection interval to facilitate installation of the gravel pack completion will not increase the risk of an injection fluid confinement failure, provided that the packer is set at least 300 feet measured depth below the top of the production casing cement and is not above the confining zone. The location of production casing cement will be established through cement bond logging or alternate methods deemed acceptable by the AOGCC. Any alternative methods must be approved in advance by the AOGCC. MITs regularly scheduled by the AOGCC will ensure integrity of injection wells. 10. Reservoir voidage will be maintained at a replacement ratio of about 0.97:1. 11. Sufficient information has been provided to authorize injection of gas into the Thomson Sand Undefined Oil Pool for the purposes of pressure maintenance and enhanced condensate recovery, subject to monitoring as described in the rules below. NOW, THEREFORE, IT IS ORDERED that: The underground injection of fluids for pressure maintenance and enhanced oil recovery is authorized in the following area, subject to the following rules and, to the extent not superseded by these rules, 20 AAC 25: Affected Area: Umiat Meridian Township, Ranue Sections Portions 10 North, 24 East 29 W-1/2 SW-1/4 10 North, 24 East 30 S-1/2, NW-1/4, and SW-1/4 NE-1/4 10 North, 24 East 31 All 10 North, 24 East 32 W-1/2 10 North, 23 East 16 SW-1/4, and S-1/2 SE-1/4 10 North, 23 East 17 SW-1/4, and S-1/2 SE-1/4 10 North, 23 East 18 SW-1/4, and S-1/2 SE-1/4 10 North, 23 East 19-22 & 25-30 & 34-36 All 10 North, 23 East 23 S-1/2,S-1/2 NE-1/4, and NW-1/4 10 North, 23 East 24 SW- 1/4, S-1/2 SE- 1/4, and NW-1/4 SE 1/4 10 North, 23 East 31 N-1/2, and N-1/2 SE-1/4 10 North,23 East 32 N-1/2, N-1/2 SW- 1/4, and N-1/2 SE- 1/4 10 North, 23 East 33 N-1/2, SE-1/4, N-1/2 SW-1/4, and SE-1/4 SW-1/4 10 North, 22 East 24 E-1 /2, and E-1 /2 SW-1/4 10 North, 22 East 25 E-1/2, E-1/2 NW- 1/4, and E-1/2 SW-1/4 10 North, 22 East 36 NE-1/4 9 North, 24 East 5 W-1 /2, and W- 1 /2 NE-1/4 9 North, 24 East 6 All 9 North, 24 East 7 N-1/2, N-1/2 SW- 1/4, and N-1/2 SE-1/4 9 North, 24 East J 8 NW-1/4 Area Injection Order 38 • August 25, 2015 Page 10 of 12 Township, Range Sections Portions 9 North, 23 East 1 & 2 All 9 North, 23 East 3 N-1/2, SE-1/4, N-1/2 SW-1/4 9 North, 23 East 4 NE-1/4 9 North, 23 East 11 N-1/2 NW-1/4, NE-1/4 9 North, 23 East 12 N-1/2, N-1/2 SW-1/4,and N-1/2 SE-1/4 Rule 1 Authorized Injection Strata for Enhanced Recovery Fluids authorized under Rule 3, below, may be injected for purposes of pressure maintenance and enhanced oil recovery within the Affected Area into strata that are common to, and correlate with, the interval between 16,126 and 16,377 feet measured depth on the VISION/Scope Measured Depth Log recorded in reference well PTU-15. Rule 2 Well Construction Packers in injection wells may be located more than 200 feet measured depth above the top of the Thomson Sand Undefined Oil Pool; however, packers shall not be located above the confining zone. The production casing cement volume must be sufficient to place cement a minimum of 300 feet measured depth above the planned packer depth. Cement placement must be confirmed by cement bond log or another method approved in advance by the AOGCC. Rule 3 Authorized Fluids for Enhanced Recovery The only fluid authorized for injection is natural gas produced from the Thomson Sand Undefined Oil Pool. Any other fluids shall be approved in advance by separate administrative action based upon proof of compatibility with the reservoir and formation fluids. Rule 4 Authorized Injection Pressure for Enhanced Oil Recovery Injection pressures must be maintained at or below 11,500 psi at the reservoir sand -face so that injected fluids do not fracture the confining intervals or migrate out of the approved injection strata. Rule 5 Monitoring Tubing -Casing Annulus Pressure Inner and outer annulus pressure shall be monitored each day for all injection and production wells. Inner annulus, outer annulus, and tubing pressure shall be constantly monitored and recorded for all injection and production wells. The outer annulus pressures of all wells that are not cemented across the Thomson Sand Undefined Oil Pool and are located within a '/-mile radius of a Point Thomson injector shall be monitored daily. All monitoring results shall be documented and available for AOGCC inspection. Rule 6 Demonstration of Tubing/Casing Annulus Mechanical Integrity The mechanical integrity of each injection well must be demonstrated before injection begins and before returning a well to service following any workover affecting mechanical integrity. An AOGCC-witnessed MIT must be performed after injection is commenced for the first time in a well, to be scheduled when injection conditions (temperature, pressure, rate, etc.) have stabilized. Subsequent tests must be performed at least once every four years thereafter. The AOGCC must Area Injection Order 38 August 25, 2015 Page 11 of 12 be notified at least 24 hours in advance to enable a representative to witness an MIT. Unless an alternate means is approved by the AOGCC, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1,500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, that shows stabilizing pressure and does not change more than 10 percent during a 30-minute period. Results of MITs must be readily available for AOGCC inspection. Rule 7 Well Integrity and Confinement Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by an injection rate, operating pressure observation, test, survey, log, or any other evidence (including outer annulus pressure monitoring of all wells within a 1/-mile radius of where the Point Thomson is not cemented), the Operator shall notify the AOGCC by the next business day and submit a plan of corrective action on a Form 10-403 for AOGCC approval. The Operator shall immediately shut in the well if continued operation would be unsafe or would threaten contamination of freshwater, or if so directed by the AOGCC. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the AOGCC for all injection wells for which well integrity failure or lack of injection zone isolation is indicated. Rule 8 Annual Performance Reporting An annual surveillance report will be required by April 1 st of each year subsequent to commencement of enhanced oil recovery operations. In addition to such other information as the AOGCC may require the report shall include the following: a. progress of the enhanced recovery project and reservoir management summary including engineering and geological parameters; b. reservoir voidage balance by month of produced and injected fluids; c. analysis of reservoir pressure surveys within the pool; d. results and, where appropriate, analysis of production and injection log surveys, tracer surveys and observation well data or surveys; e. assessment of fracture propagation into adjacent confining intervals; f. summary of MIT results; g. summary of results of inner and outer annulus monitoring for all production wells, injection wells, and any wells that are not cemented across the Thomson Sand Undefined Oil Pool and are located within a 1/-mile radius of a Point Thomson injector; h. results of any special monitoring; i. reservoir surveillance plans for the next year; and j. future development plans. Rule 9 Notification of Improper Class II Iniection Injection of fluids other than those listed in Rule 3 without prior authorization is considered improper Class II injection. Upon discovery of such an event, the operator must immediately notify the AOGCC, provide details of the operation, and propose actions to prevent recurrence. Additional notification requirements of any other State or Federal agency remain the operator's responsibility. Area Injection Order 38 • • August 25, 2015 Page 12 of 12 Rule 10 Other Conditions If fluids are found to be fracturing the confining zone or migrating out of the approved injection stratum, the Operator must immediately shut in the injection wells and immediately notify the AOGCC. Injection may not be restarted unless approved by the AOGCC. Rule 11 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. This order shall expire if ExxonMobil ceases to be the Designated Operator for the Point Thomson Unit or five years after the effective date shown below, whichever occurs first. DONE at Anchorage, Alaska, and dated August 25, 2015. S�OILq�r� Cathy f. Fo ster aniel T. Seamount, 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 Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the Commission denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the Commission grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the Commission, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), " [tlhe questions reviewed on appeal are limited to the questions presented to the Commission by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Carlisle, Samantha J (DOA) From: Carlisle, Samantha J (DOA) Sent: Tuesday, August 25, 2015 3:44 PM To: 'Ballantine, Tab A (LAW) (tab.ballantine@alaska.gov)'; '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)'; 'Crisp, John H (DOA) Oohn.crisp@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)'; 'Grimaldi, Louis R (DOA) (lou.grimaldi@alaska.gov)'; 'Guhl, Meredith (DOA sponsored) (meredith.guhl@alaska.gov)'; Herrera, Matthew F (DOA); 'Hill, Johnnie W (DOA)'; 'Hunt, Jennifer L (DOA)'; Jackson, Jasper C (DOA); 'Jones, Jeffery B (DOA) (Jeff Jones@alaska.gov)'; Kair, Michael N (DOA); Loepp, Victoria T (DOA); 'Mumm, Joseph (DOA sponsored) Ooseph.mumm@alaska.gov)'; 'Noble, Robert C (DOA) (bob.noble@alaska.gov)'; 'Paladijczuk, Tracie L (DOA)(tracie.palad ijczuk@alaska.gov)'; 'Pasqual, Maria (DOA) (maria.pasqual@alaska.gov)'; 'Regg, lames B (DOA) Oim.regg@alaska.gov)'; 'Roby, David S (DOA) (dave.roby@alaska.gov)'; 'Scheve, Charles M (DOA) (chuck.scheve@alaska.gov)'; 'Schwartz, Guy L (DOA) (guy.schwartz@alaska.gov)'; 'Seamount, Dan T (DOA) (dan.seamount@alaska.gov)'; 'Singh, Angela K (DOA) (angela.singh@alaska.gov)'; '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'; 'Kari 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'; 'Mikel 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'; 'Oliver Sternicki'; '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'; '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'; 'Tony Hopfinger'; 'trmjrl'; 'Tyler Senden'; 'Vicki Irwin'; 'Vinnie Catalano'; 'Walter Featherly'; 'Aaron Gluzman'; 'Aaron Sorrell'; 'Ajibola Adeyeye'; 'Alan Dennis'; 'Andrew Cater'; 'Anne Hillman'; 'Brian Gross'; 'Bruce Williams'; To: Brio, Jeff J (DNR); 'Caroline Bajsarowicz'; 'Caselullivan'; 'Diane Richmond'; 'Don Shaw'; 'Donna Vukich'; 'Eric Lidji'; 'Erik Opstad'; 'Gary Orr'; 'Graham Smith'; 'Greg Mattson'; 'Hak Dickenson'; Heusser, Heather A (DNR); 'Holly Pearen'; Hyun, James J (DNR); '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); 'Marc Kuck'; 'Marcia Hobson'; 'Marie Steele'; 'Matt Armstrong'; 'Matt Gill'; 'Mike Franger'; 'Morgan, Kirk A (DNR)'; 'Pat Galvin'; 'Pete Dickinson'; 'Peter Contreras'; 'Richard Garrard'; 'Robert Province'; 'Ryan Daniel'; 'Sandra Lemke'; 'Sarah Baker'; 'Shaun Peterson'; 'Susan Pollard'; 'Talib Syed'; 'Terence Dalton'; 'Tina Grovier (tmgrovier@stoel.com)'; Todd, Richard J (LAW); Tostevin, Breck C (LAW); 'Wayne Wooster'; 'William Hutto'; 'William Van Dyke' Subject: Area Injection Order 38 (Point Thomson) Attachments: aio38.pdf Please see attached. Samantha Carlisle Fxecutive Secretary 11 Alaska Oil and Gas Conservation C.`ommission. 333 1,17est 7; Avenue Anchora,oe, AK 99501. (907) 793-122 3 (phone) (90 ) 276-7,542 (fax) CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Samantha Carlisle at (907) 793-1223 or Samantha.Carlisle@alaska.gov. 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 Karen D. Hagedorn 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 Angela K. Singh ExxonMobil Development Comp Post Office Box 190267 Anchorage, Alaska 99519-0267 907 334 2943 Telephone 907 743 9809 Facsimile July 9, 2015 ER-2015-OUT-307 .JUL. 0 9 2015 Ms. Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Chri . Nordstrom Techn Manager Point Thomson Project E�onMobil Re: ExxonMobil Alaska Production Inc. Response to Questions Raised During the Point Thomson Unit AIO Public Hearing of July 7, 2015 Commissioner Foerster, I would like to thank you and Commissioner Seamount for the courtesy extended to us at the hearing earlier this week before your Commission to consider ExxonMobil Alaska Production Inc.'s (EMAP) application for an Area Injection Order for the Point Thomson Unit. We are providing the answers below in response to several questions that were raised during the course of the proceeding and for which the record was held open in anticipation of our response. 1. Question: What is the size of the Point Thomson Unit area? Answer: The Unit contains 93,291.12 acres. 2. Question: What is the size of the Affected Area? Answer: The Affected Area is 12,983 acres. 3. Question: If cycling were the way to go, how many compressors would you need and what do they cost? Answer: The number of compressors would depend on project parameters yet to be determined such as facilities throughput and the specific compressor selection. We do not have cost estimates for the compression, facility modifications, infrastructure expansion and additional wells that would be needed for an expanded cycling project since those too would depend upon the specific project objectives. 4. Question: What is the cost of an injector/producer well pair (in the context of oil rim development, potentially horizontal)? Answer: EMAP respectfully requests that AOGCC treat the answer provided to this question confidentially: See attachment 1. An ExxonMobil Subsidiary Commissioner Foerster 0 -2- 0 July 9, 2015 If you have any further questions, please contact Christina Nordstrom at (907) 334-2943 or via email at(christina.d.nordstrom@exxonmobil.com). For and on Behalf of ExxonMobil Alaska Production Inc. CDN:sc:bt Enclosure: Attachment 1 (Confidential Answer to Question 4) cc with enclosure: Commissioner Seamount 1 ALASKA OIL AND GAS CONSERVATION COMMISSION 2 Before Commissioners: Cathy Foerster, Chair 3 Daniel T. Seamount 4 In the Matter of Thomson Sand ) 5 Reservoir, Point Thomson Unit, ) 6 Proposed Area Injection Order. ) 7 ) 8 Docket No.: AIO-15-017 9 ALASKA OIL and GAS CONSERVATION COMMISSION 10 Anchorage, Alaska 11 July 7, 2015 12 9:00 o'clock a.m. 13 VOLUME I 14 PUBLIC HEARING 15 BEFORE: Cathy Foerster, Chair 16 Daniel T. Seamount, Commissioner • 1 TABLE OF CONTENTS 2 Opening remarks by Chair Foerster 03 3 Remarks by Ms. Nordstrom 06 4 Remarks by Mr. Eleftheriou 08 5 Remarks by Ms. Dougherty 19 6 Remarks by Mr. Podust 41 7 2 1 P R O C E E D I N G S 2 (On record - 9:03 a.m.) 3 CHAIR FOERSTER: Okay. I'll call this hearing 4 to order. Today is July 7th, 2015, it's 9:03 a.m. 5 We're located in the offices of the Alaska Oil and Gas 6 Conservation Commission, 333 West Seventh Avenue, 7 Anchorage, Alaska. To my left is Commissioner Dan 8 Seamount, I'm Cathy Foerster. 9 We are having a hearing today in reference to 10 Docket number AIO-15-017, Thomson Sand Reservoir, Point 11 Thomson Unit, proposed area injection order. 12 ExxonMobil Production Company by application dated May 13 1, 2015 has requested that the Alaska Oil and Gas 14 Conservation Commission issue an area injection order 15 to establish rules governing injection of fluids for 16 enhanced recovery purposes for the Thomson Sand 17 reservoir, Point Thomson unit. 18 Computer Matrix will be recording the 19 proceedings and you may get a copy of the transcript 20 from Computer Matrix Reporting. 21 I just want to remind you that when you are 22 testifying you need to try to speak into both 23 microphones, you need to make sure that the little 24 green light is on for both microphones and you try to 25 speak into both of them. One of them will capture what 3 1 you say for the court reporter, the other will enable 2 the people in the back of the room to hear what you're 3 saying. 4 Let me check who all -- one, two, three. Looks 5 like we have three or four people from ExxonMobil 6 testifying and I don't see that anyone else is 7 requesting to testify, but we'll provide that 8 opportunity later. So we will start with Exxon and 9 before we get started some of you are new to me and I 10 want to give you the rules so that we just explain this 11 once. Couple of things, as you speak and you refer to 12 an overhead exhibit please identify it either by slide 13 number or title of the -- of the slide because we're 14 creating a public record and, you know, 10 years from 15 now someone's going to want to read -- be able to read 16 through the transcript and know what you're referring 17 to when you say well, obviously you can see that. So 18 please make sure that your testimony is done in a way 19 that enables that to happen. 20 So before we start are all four of you going to 21 testify? 22 MS. NORDSTROM: I'll just make some 23 introductory comments and then we'll (indiscernible - 24 away from microphone)..... El 0 1 you in because you -- so what I'd like for you to do 2 now is all raise your right hand. 3 (Oath administered) 4 MS. DOUGHERTY: I do. 5 MR. ELEFTHERIOU: I do. 6 MS. NORDSTROM: Yes, I do. 7 MR. PODUST: I do. 8 CHAIR FOERSTER: Great. Okay. And so as -- 9 Sophie is going to make the introductory comments and 10 then I assume that the other three of you are 11 testifying as experts in an area. What I'll have -- 12 and I know you're an expert in several areas probably, 13 but you don't want to be sworn in as an expert, 14 correct? 15 MS. NORDSTROM: Right. (Indiscernible - away 16 from microphone)..... 17 CHAIR FOERSTER: When each one of you begins 18 your testimony what we'll ask you to do is describe -- 19 you know, identify what area you want to be recognized 20 as an expert in and then give us the qualifications 21 that justify accepting you as an expert and then we'll 22 rule on that. And, you know, just to warn you if 23 anybody says they went to Texas A&M that will make them 24 suspect. 25 (Off record comments) 5 1 CHAIR FOERSTER: All right. So let's begin. 2 And, you know, this is a very serious matter, but 3 there's no reason for you guys not to be able to take a 4 deep breath and relax and enjoy being proud of the hard 5 work that you've done on this project. So just go 6 ahead, Exxon. 7 CHRISTINA NORDSTROM 8 previously sworn, called as a witness on behalf of 9 ExxonMobil, stated as follows on: 10 DIRECT EXAMINATION 11 MS. NORDSTROM: Great. All right. So we're on 12 slide two. My name is Christina Nordstrom, I'm the 13 technical manager on the Point Thomson initial 14 production system project. I'll just make some very 15 brief comments and then turn it over to our technical 16 team. 17 Thank you for taking the time to meet with us 18 today. As you mentioned back on May 1st of 2015 on 19 behalf of the working interest owners ExxonMobil 20 Production Alaska, Inc., submitted an application for 21 an area injection order at Point Thomson. The material 22 we have here today is summarized from that application 23 and we have no confidential material in this package 24 that we have today. We have technical experts 25 representing reservoir engineering, geoscience and 1 drilling who will speak to the material and I will just 2 be available to answer broader kind of project 3 perspective questions if you have any. 4 And I think with that I'll turn it over to 5 George Eleftheriou, our reservoir engineer, he'll take 6 us through the bulk of the material. 7 MR. ELEFTHERIOU: Okay. 8 CHAIR FOERSTER: George, you -- I'm assuming 9 you want to be recognized as an expert in reservoir 10 engineering so give us..... 11 MR. ELEFTHERIOU: Yes, ma'am. 12 CHAIR FOERSTER: .....give us a little bit 13 about your education and your background. 14 MR. ELEFTHERIOU: Okay. My name is George 15 Eleftheriou, that's spelled E-L-E-F-T-H-E-R-I-O-U. 16 It's a long one. I'm representing ExxonMobil Alaska 17 Production, Inc., as a reservoir engineer. I received 18 a bachelor of science degree in chemical engineering 19 from the University of Texas at Austin in 2012, 20 performed reservoir modeling and analysis for Point 21 Thomson for three years. I intend to testify about the 22 general project overview and our injection operations. 23 CHAIR FOERSTER: Okay. Do you have any 24 questions? 25 COMMISSIONER SEAMOUNT: No question, no 1 objections. 2 CHAIR FOERSTER: Okay. Eleftheriou, is that 3 how you pronounce it? 4 MR. ELEFTHERIOU: Eleftheriou. 5 CHAIR FOERSTER: It's Eleftheriou? 6 MR. ELEFTHERIOU: Yes, ma'am. 7 CHAIR FOERSTER: Okay. 8 (Off record comments) 9 CHAIR FOERSTER: Please -- I have no objections 10 either so you're recognized as an expert in reservoir 11 engineering and you may proceed. And don't forget to 12 reference your slides for the..... 13 MR. ELEFTHERIOU: Yes, ma'am. 14 CHAIR FOERSTER: .....record. 15 GEORGE ELEFTHERIOU 16 previously sworn, called as a witness on behalf of 17 ExxonMobil, stated as follows on: 18 DIRECT EXAMINATION 19 MR. ELEFTHERIOU: Okay. Let's move on to slide 20 three then. Here we're showing a segment of the North 21 Slope with the Point Thomson unit located on the far 22 right portion of the map. The unit is approximately 25 23 miles away from our nearest field which is Badami, 24 that's shown there in the center of the map, and the 25 unit is about 60 miles east of Prudhoe Bay which you 6 . . 1 can see on the far left-hand side of the map. The unit 2 was formed in 1977 and is operated b ExxonMobil Alaska P Y 3 Production, Inc. 4 Moving on to slide four. So production from 5 the Thomson sand reservoir will be initiated with gas 6 cycling and delivery of liquid condensate for sale. 7 The Point Thomson project is designed to bring natural 8 gas and condensate to the surface from the Thomson sand 9 reservoir at approximately 200 million cubic feet per PP Y 10 day and produce up to 10,000 barrels per day of 11 condensate. The residual gas will then be reinjected 12 back into the Thomson sand. The wells that we're 13 including within the project are the PTU-17 production 14 well also known as the west pad well, you might see it 15 in other forms there, two injection wells which are the 16 PTU-15 and PTU-16 and one disposal well which is the 17 PTU-DW1 which is a UIC class one disposal well which is 18 primarily used here for disposal of waste water. I'll 19 just note that that well in injectingin a formation 20 that is shallower than the Thomson sand. 21 So I'll walk us through, there's a figure here 22 on the slide that kind of steps through each of the 23 major operations part of the project. So on the top 24 right-hand side we're showing the production of gas and 25 condensate from the west pad well or the PTU-17. As 9 1 the name kind of indicates it's on the western pad. So 2 that gas and condensate is then transported through a 3 gathering line that takes it to a central pad where our 4 facilities are located. There the gas and condensate 5 and some waste water are separated. That waste water 6 is then injected into our disposal well which is 7 located on the central pad. The condensate is 8 separated and is transferred to the Point Thomson 9 export pipe line which is connected to existing 10 infrastructure and ultimately makes its way to the 11 Trans Alaskan Pipeline. Finally the residual gas is 12 compressed and reinjected back into the reservoir via 13 our two injection wells, the PTU-15 and PTU-16 which 14 are also located on the central pad. 15 CHAIR FOERSTER: We typically save our 16 questions until the end unless there's something that's 17 just burning that we have to ask about. 18 MR. ELEFTHERIOU: Okay. Good to know. Thank 19 you. 20 So on slide five we're showing a figure that's 21 indicating the affected area for the Point Thomson 22 project, it also shows the expected initial 23 participating area which includes A and B for the 24 Thomson sand. We're showing the surface and bottom 25 hole locations of the producing well and the two 10 1 injection wells. So the PTU-17 there we can see is 2 located by the green line. Surface location starts 3 onshore, it makes it way offshore. And the two 4 injection wells, PTU-15 and PTU-16 in the red lines, 5 PTU-15 is on the left and PTU-16 is on the right. The 6 affected area is indicated by the heavy purple dashed 7 line. We developed this area using simulation modeling 8 techniques which trace the path of the injected gas 9 over 30 years of the gas cycling operations. So we 10 think that's kind of a justifiable basis to define the 11 area of the reservoir which is impacted by the gas 12 cycling operations. 13 Okay. On slide six we have a figure that shows 14 the adjacent wells located within the affected area of 15 the gas cycling operations. The bottom hole locations 16 of the PTU-15 and PTU-16 wells are shown in the dark 17 solid red dots. The only active -- or let me mention 18 too the -- we're showing the affected area also as the 19 red striped area on this map. So the only active well 20 within the affected area is the disposal well, the DW-1 21 which is shown there towards the bottom of the affected 22 area. The only other wells that are contained within 23 the affected area are the PTU-1, the PTU-3 and the 24 Alaska State D-1 which are exploration wells which were 25 drilled throughout the 1970s and 1980s and have since 11 1 been permanently abandoned. 2 Okay. On slide seven we're showing two figures 3 that display two separate confirmation letters from the 4 EPA in 2003 and 2009 certifying that the Point Thomson 5 unit contains no underground sources of drinking water 6 therefore our injection operations should not impact 7 any freshwater or drinking water sources. Furthermore 8 the gas that is being reinjected is native to the 9 reservoir, it originated in the reservoir and we're 10 simply reinjecting it back into that reservoir. 11 So with that I'll hand it over to our lead 12 geologist, Sue Dougherty. 13 CHAIR FOERSTER: Okay. Well, we may have 14 questions for you right now. 15 MR. ELEFTHERIOU: Okay. That's fine. 16 CHAIR FOERSTER: Do you have any questions? 17 COMMISSIONER SEAMOUNT: Yeah, I have a few. 18 What's the size of the unit? I should know this, 19 but..... 20 MR. ELEFTHERIOU: I should know this too. I 21 don't know off the top of my head. 22 COMMISSIONER SEAMOUNT: It looks like it's 23 around 20,000 acres. 24 CHAIR FOERSTER: You can get --you can come 25 back with the answer. 12 1 MR. ELEFTHERIOU: Get back to you on the exact 2 number, yeah. 3 COMMISSIONER SEAMOUNT: Well, we've probably 4 got it in our files somewhere. Okay. How confident -- 5 well, I guess, you know, I'm just a geologist and I 6 probably know the answer to this, but I'm going to 7 confirm it anyway. Do you expect any decline in 8 condensate production? 9 MR. ELEFTHERIOU: Over the course of the gas 10 cycling operations, yes. 11 COMMISSIONER SEAMOUNT: So it's going to go 12 below 10,000 barrels a day? 13 MR. ELEFTHERIOU: That is expected at some 14 point in time, yes. 15 COMMISSIONER SEAMOUNT: Okay. And how much 16 water do you expect? 17 MR. ELEFTHERIOU: Our facility's design 18 capacity is 1,000 barrels per day, but we expect to be 19 below that. 20 COMMISSIONER SEAMOUNT: Okay. And then if you 21 determine that the gas cycling project or gas cycling 22 is the way to go how many compressors would you need? 23 MR. ELEFTHERIOU: I think that would be a 24 project dependent design question and I'm not sure I'm 25 prepared to speak to that right now. 13 1 COMMISSIONER SEAMOUNT: How much do these 2 compressors cost? 3 MR. ELEFTHERIOU: I'm not sure I know that -- 4 prepared to speak to that. 5 COMMISSIONER SEAMOUNT: All right. That's all 6 I have for now. 7 CHAIR FOERSTER: Well, but what we'll do is at 8 the end of the hearing we'll choose an amount of time 9 to leave the record open and let you guys answer the 10 questions that we're asking. I hope you wrote down the 11 questions that were asked, if not you can reask them. 12 COMMISSIONER SEAMOUNT: Actually I -- I won't 13 ask this question now, I'll wait. 14 CHAIR FORESTER: Okay. You sure? 15 COMMISSIONER SEAMOUNT: I'm positive. 16 CHAIR FORESTER: Okay. All right. I have a 17 couple questions for you. You're applying for an area 18 injection order, but you're not applying for any pool 19 rules so I'm assuming that statewide rules will suffice 20 for all other areas of the production and operations of 21 the IPS; is that correct? 22 MS. NORDSTROM: I mean, it..... 23 CHAIR FORESTER: If you -- someone other than 24 the designated speaker was going to answer the question 25 identify yourself for the record. 14 1 MS. NORDSTROM: Yes, this is Christina 2 Nordstrom. We did review the -- I guess the pool rules 3 and consider that, but since we only had the two 4 injection wells and we didn't need really a large 5 number of field wide variances and we also have 6 unitized and lined ownership at Point Thomson we didn't 7 think that we needed pool rules at this time for the 8 initial production. 9 CHAIR FORESTER: So you think statewide rules 10 are going to be sufficient? 11 MS. NORDSTROM: Correct. 12 CHAIR FORESTER: Okay. And from that I'm going 13 to lead into something else. As we congeal our area 14 injection order into very -- into specifics, it'll have 15 requirements for a number of things so I'm trying to 16 zero in on, you know, if -- since there are no pool 17 rules that anything we need to include that we do. 18 What sorts of surveillance data do you intend to gather 19 to ensure that one, well integrity is maintained and 20 maybe that's a question for the drilling engineer and 21 two, that you're gauging reservoir performance? 22 MR. ELEFTHERIOU: Sure. So this is George 23 Eleftheriou. On a high level from a surveillance 24 perspective we're interested in the pressures in the -- 25 all of the -- the wells, the producing well and the 15 1 injectors, we're interested in the condensate and gas 2 rates over time and we're also monitoring -- will be 3 monitoring the composition of those fluids. In terms 4 of well integrity, I know you mentioned that, we will 5 be monitoring the annular pressure on all of the wells 6 to ensure that the mechanical integrity of the wells is 7 preserved. 8 CHAIR FOERSTER: Okay. Okay. So do they still 9 give the Hamilton watch to the outstanding chemical 10 engineering graduate? 11 MR. ELEFTHERIOU: I'm not aware of that. 12 CHAIR FOERSTER: Well, either they don't..... 13 MR. ELEFTHERIOU: But I wasn't the 14 outstanding..... 15 CHAIR FORESTER: .....or it wasn't you. All 16 right. This is probably as good a time as any to share 17 with you guys that our technical staff wanted us to 18 thank you, that you provided them just the right amount 19 of data, you formatted it very well and that in all of 20 their interactions your technical people have been 21 great to work with. I won't say what they said about 22 your attorneys, but they loved working with your 23 technical people. So thank you. And this is one of 24 the first times you've come before us and often when an 25 operator comes to us the first time the process is not 16 1 very smooth, but from our -- from what I can gather 2 from staff that you guys have worked very hard to do a 3 very thorough and professional job on preparing for 4 this application and this hearing so we just want to 5 thank you for that. I wanted to make sure I said that 6 before we got too far into the technical details and I 7 forgot. 8 Do you have any other questions for..... 9 COMMISSIONER SEAMOUNT: I do not, Madam Chair. 10 CHAIR FORESTER: All right. Well, then we'll 11 move on to your next..... 12 MS. DOUGHERTY: Okay. 13 CHAIR FORESTER: .....witness. And again your 14 name..... 15 MS. DOUGHERTY: I am..... 16 CHAIR FORESTER: .....and what 17 qualifications..... 18 MS. DOUGHERTY: Okay. 19 CHAIR FORESTER: .....you have as an expert. 20 MS. DOUGHERTY: Okay. I'm Susan Dougherty and 21 I'm a geologist..... 22 (Off record comments) 23 MS. DOUGHERTY: All right. Susan Dougherty, 24 last name D-O-U-G-H-E-R-T-Y, I'm a geologist with 25 ExxonMobil. I received a bachelor of science from -- 17 1 in geology from the University of California at Santa 2 Barbara in 1994. Went on to Montana State for a 3 master's of science in earth sciences, graduated in 4 1997. Shortly thereafter I hired on by Exxon, fall of 5 197, then of course ExxonMobil in 199. Seventeen plus 6 years, I've worked a variety of projects all over the 7 place. Started with ExxonMobil Production Company 8 drilling development wells, Gulf of Mexico, offshore 9 California, Northwest Germany, offshore Nigeria, just 10 all over the place. And then five or six years with 11 the Exploration Company, working a variety of 12 unconventional reservoirs. So my role in Point Thomson 13 is really as a general geologist, it's not a very 14 glamorous title being a generalist, but I'm an 15 integrator and that's my role right now on Point 16 Thomson is to integrate our geologic understanding with 17 reservoir engineering, drilling engineering, the 18 commercial group, the facilities group, our partners in 19 the government. 20 CHAIR FORESTER: Well, it's not a glamorous 21 title, but is it a fun job? 22 MS. DOUGHERTY: Absolutely. And it's good to 23 be here. 24 CHAIR FORESTER: Do you have any questions for 25 this witness? 1 COMMISSIONER SEAMOUNT: I have no questions. 2 (Off record comments) 3 CHAIR FORESTER: I don't have any questions for 4 you either and I have no problems accepting you as an 5 expert witness so please proceed with your testimony 6 and don't forget to reference your slides. 7 MS. DOUGHERTY: That's right. Okay. 8 SUSAN DOUGHERTY 9 previously sworn, called as a witness on behalf of 10 ExxonMobil, stated as follows on: 11 DIRECT EXAMINATION 12 MS. DOUGHERTY: So I've been granted five 13 slides which is generous, I'm starting with slide 14 eight. We'll start with a general geologic description 15 and I'll work starting with the map in the upper left- 16 hand corner, that's a Thomson depth map. It's zoomed 17 into the participating area so it does not show the 18 whole unit, it's just area A and B. You see the two 19 injectors, PTU-15 and 16 in red with the producing 20 well, PTU-17. Also on here, granted fairly small, but 21 it's shown on other slides, the PTU-3 exploration well 22 so there's a series of exploration wells drilled in the 23 late 170s, early 180s, the PTU-3 which is sandwiched 24 between the 15 and the 16, off to the southwest, PTU-1 25 and then just outside the participating area the AK 19 1 State -- Alaska State F-1 and the D-1 is out here just 2 to the northeast. 3 The contra intervals are 250 feet if you can't 4 read that. And then as you see cross section A to A 5 prime is shown down here on the little schematic, the 6 cartoon in the lower left hand corner, the Thomson sand 7 is in yellow with the double arrows indicating that's 8 where we're injecting so you see the PTU-15 and the 16 9 where we're -- the completions will be. Overlying the 10 Thomson sand is the -- what we consider the confining 11 zone which is Hue/HRZ shale in the dark, I don't know 12 what color that is, brown, khaki and where that is 13 eroded it's replaced by the Canning formation, also a 14 very good seal obviously because we have an 15 accumulation here. The Thomson sand is overlain 16 unconformably on some Pre -Mississippian and we divided 17 that into an upper and a lower Pre -Mississippian 18 basement. As you see also inset here is a -- could be 19 considered a type log, the PTU-3 well which again is 20 located between the 15 and the 16, the two injectors. 21 What's shown here is a gamma ray of resistivity density 22 neutron and a total porosity log on the last track on 23 the right. And those little red dots are four points, 24 four firm data points from the core we've recovered. 25 We do recognize an internal flooding surface which 20 1 allows us to separate the Thomson into an upper and a 2 lower and we've mapped that flooding surface around the 3 field and that's helpful for us in our depositional 4 modeling and our model building. 5 And from there I'll just kind of run through 6 the bullet points on the right-hand side. It is lower 7 cretaceous Thomson sand, porosity ranging from 5 to 34 8 percent and permeability from very low, .01, typical up 9 to 50 thousand millidarcy, that's 50 RC and that's not 10 a lie, that's true. It's very, very good quality rock 11 so very wide range of permeability. And on the next 12 slide I'll show you a porosity/permeability plot that 13 puts all these in context. 14 Large accumulations, 500 foot gas cap with a 15 thin, 37 foot oil -- heavy oil rim. Heavy oil's around 16 12 to 14 API gravity. We had detected some H2S 17 particularly in the 15 and the 16 wells drilled in the 18 last drilling campaign 2009/2010 and some CO2 detected 19 during the well test of those two wells. It is 20 abnormally pressured. We've got 22 wells in the unit, 21 16 of those go all the way down to the Thomson. Those 22 are the wells that we use to describe the reservoir. 23 Quite a bit of core which is delightful for a 24 geologist, right, 1,776 feet of conventional core 25 that's been collected and described. The PTU-15 and 16 21 0 1 wells drilled recently, 2009/2010, quite a lot of 2 learnings and modifications of our model based on those 3 two wells. 4 We have full 3D seismic over the unit, it has 5 been converted to a prestack depth migrated cube, PSD 6 cube, and that's been recently reprocessed 2014. We 7 estimate the original gas in place to be 8 TCF and 8 that's based on our knowledge to date and that's 9 throughout the unit, not just the participating area. 10 We'll go on to page 9 to the description of the 11 reservoir quality. Start with the graph on the left, 12 that's a typical porosity/permeability plot. The 13 porosity scale on the horizontal scale is 0 to 40 14 percent porosity. The permeability scale vertical, 15 .001 up to 1 darcy is the last number that you can read 16 before it gets covered up by this thin section. And 17 that 1 darcy separates just conveniently to give you an 18 eyeball, those red dots from the orange dots, that's 1 19 darcy. So you can see quite good reservoir quality. 20 These color codes are based on petrofacies that we 21 define mostly on the poro/perm characteristics, but 22 also on grain size, grain content, further description, 23 but they plot out nicely on the poro/perm plot. 24 In the application we included more 25 photomicrographs, but they're not very photogenic so I 22 • PJ 1 took them off on this presentation just to declutter 2 the slide. The three that are shown here are mostly in 3 the proximal facies of our depositional environment. 4 That open framework conglomerate with the red dots was 5 recovered or identified in the PTU-15 well drilled in 6 2009. We've covered 130 feet of it so it wasn't just a 7 little bit, it was a lot. And just outstanding 8 reservoir quality, first we'd seen really in the field. 9 That can be compared with the bi-modal conglomerate, 10 the orange dots which are still pretty darn good as far 11 as reservoir quality, but you can see by comparing 12 those two pictures why the open framework conglomerate 13 has such good permeability, that intersticial space 14 between the coarse grains has been occluded by fine 15 grain sand in the bi-modal conglomerate and that's been 16 removed in the open framework. And we believe this is 17 due to winnowing action in a very robust, energetic 18 foreshore environment. So there are places along that 19 foreshore that have had concentrated wave action and 20 that's winnowed away these finer particles. The clean 21 sand also very good reservoir, very good 22 porosity/permeability. And again those three make up 23 most of that proximal facies. 24 In the lower right-hand corner is a schematic 25 or cartoon picture of how we envision the depositional 23 0 1 environment. We believe it is a fan -delta setting, 2 that's an alluvial fan, deposits that have been 3 deposited and reworked in a shallow marine setting. 4 And you can see the little inset there, the cartoon 5 with the blue water and the alluvial fan shedding some 6 sediment down into the water. Let's see, so we believe 7 that the source area which had now been eroded, the 8 alluvial fan is up to the northeast and it's indicated 9 by the blue polygon and the depositional down dip is 10 down to the southwest. And also before going on to the 11 next slide just point out that those long bands of 12 upper shore face, the foreshore, they're long bands and 13 that helps us feel more confident about lack of facies 14 compartmentalization, these broad bands. And obviously 15 that facies deteriorates as you go down dip and you get 16 poorer reservoir quality down dip, but we don't see 17 anything cutting across these large sloughs. 18 Okay. I think I'll just move on. Slide number 19 10. So about the fluid content. We estimate the gas 20 oil contact be 12,975 TVD subsea and the oil water 21 contact 13,012 TVD subsea. Those contacts are 22 established using drill stem tests, DST, or modular 23 dynamic tester, MDT which is a Schlumberger acronym, 24 and supported by log data. We estimate that the 25 contacts are field wide suggested by that depositional 24 • • 1 environment that I discussed in the last slide. We 2 have mapped some faults, but those faults do not offset 3 the reservoir, as best we can see in the seismic they 4 just don't completely offset the reservoir and we don't 5 believe that they compartmentalize across the unit. 6 Shown in the plot here is the MDT data, 7 pressure versus depth from the PTU-16. We get a lot of 8 information out of those MDTs, some of it is just the 9 number of pressure points that all line up so nicely 10 which gives you confidence that the data's good 11 quality. Also a good reservoir tends to give you lines 12 that -- points that line up nicely, it's not a lot of 13 scatter. Also we get the gas gradient from that 14 pressure profile. And then in the tool there are fluid 15 sensors as well as we recover samples to the surface. 16 So in this case we've got a number of samples that have 17 been identified as gas all the way down to 12,973 and 18 then the next sample we picked up at negative 12,979 19 was oil. So we have a couple of oil identified samples 20 as well as gas samples. So this has tightly -- fairly 21 tightly constrained our gas oil contact at 12,975. 22 Any questions before I go on to the next one? 23 CHAIR FOERSTER: I'm saving mine until the end. 24 25 MS. DOUGHERTY: All right. Let's see, page 11, oxi 1 slide 11. Just a brief description of the injection 2 zone since we have two wells that are going to serve as 3 injectors. So we have two cross sections on the left 4 that are pulled from the geologic model and you can see 5 where those cross sections are on the little postage 6 stamp on the lower left-hand corner. Those petrofacies 7 are displayed there with a legend, it's the same color 8 code as you saw on the poro/perm plot so that open 9 framework conglomerate is the red and you can see the 10 PTU-15 just penetrated an awful lot of that. Very good 11 quality rock. PTU-16 was further down dip, down 12 depositional dip, but still very good reservoir 13 quality. So mostly in that proximal facies we've got 14 conglomerate and sandstone. The wells to the right, 15 the well logs, there's a gamma ray and a VSH on that 16 left track. Just to the right of the depth track is 17 the petrofacies with that red winnowed facies. To the 18 right of that is the environmental deposition, 19 foreshore, upper shore face, et cetera. And then we've 20 got a permeability curve and a porosity curve. So the 21 porosity's from the porosity log and then we use the 22 poro/perm transforms depending on the facies to give us 23 the permeability. That permeability scale by the way 24 is .01 to 100,000 millidarcy. 25 Okay. Page 12. So this page is on the 26 1 confining zone, you see a cross section. In the upper 2 right-hand corner there's that map, the depth map. So 3 we're going from just outside the participating unit, 4 we'll hit the 15 and then go back up to the D-1 well 5 and then come back down to the unit. Let's see, so 6 those are the wells, the State F-1, PTU-15, the State 7 D-1, PTU-3 and PTU-16. The injection zone again shown 8 in yellow for the Thomson sand and thought it was 9 important just to show that the Hue/HRZ is eroded in 10 the up dip position, the crest, the Thomson and the Hue 11 has been actually eroded off of the (indiscernible) 12 structure on the backside. So but the Canning makes up 13 for it that's a verythick very silk clay rich rY Y Y 14 formation, very good seal capacity. And then again 15 this is overlain on the Pre -Mississippian. We estimate 16 the fracture gradient in that confining zone to be 0.91 17 PSI per foot. 18 I believe that's the end of my geology, my five 19 slides. 20 CHAIR FOERSTER: Thank you. Commissioner 21 Seamount, do you have questions? 22 COMMISSIONER SEAMOUNT: I've got a few. 23 (Off record comments) 24 COMMISSIONER SEAMOUNT: Yeah, this is an 25 interesting field. Ms. Dougherty, do you know how 27 1 thick the permafrost is in this area? 2 MS. DOUGHERTY: Well, it varies from obviously 3 onshore to offshore..... 4 COMMISSIONER SEAMOUNT: Uh-huh. 5 MS. DOUGHERTY: .....and I'm trying to 6 remember, two to 3,000 feet onshore to about 1,500 feet 7 offshore perhaps. 8 COMMISSIONER SEAMOUNT: Okay. 9 MS. DOUGHERTY: I'd have to look. 10 COMMISSIONER SEAMOUNT: So the EPA exemption is 11 -- was valid then, correct, I mean, 1,500 feet. Do you 12 think there's any freshwater at all below the 13 permafrost? 14 MS. DOUGHERTY: No. 15 COMMISSIONER SEAMOUNT: Okay. Do you see any 16 change in the H2S concentration with time? 17 MS. DOUGHERTY: You want to take that, George? 18 MR. ELEFTHERIOU: Yes, this is George 19 Eleftheriou. By time what do you mean by that? 20 COMMISSIONER SEAMOUNT: Throughout the life of 21 the site -- of this pilot project or if you know if 22 you've modeled throughout the life of the field, that 23 would be interesting too. 24 MR. ELEFTHERIOU: Right. So we don't 25 explicitly model the -- the H2S in our reservoir NM 1 simulations, but we don't expect that we'll be 2 increasing the, I guess, total composition of the H2S 3 because we aren't really removing gas volumes -- 4 significant amounts of gas volumes from the field so we 5 can't concentrate it in that way. 6 COMMISSIONER SEAMOUNT: Okay. And then is the 7 source of the heavy oil the same as the source of the 8 gas condensate? 9 MS. DOUGHERTY: I don't believe so. No, I 10 think the oil migration was an earlier event. 11 COMMISSIONER SEAMOUNT: Okay. I don't think 12 I've ever seen porosity as a 34 percent at these 13 depths. You've mentioned winnowing, what else would 14 preserve that kind of porosity? 15 MS. DOUGHERTY: I think the porosity is 16 preserved by that grain support -- support with the 17 grains. There isn't any kind of clay coat preservation 18 that we've observed, it's really just that grain 19 supporting and then winnowing away of the lime grain. 20 CHAIR FOERSTER: The absence of clays? 21 MS. DOUGHERTY: Yeah. And the absence of 22 clays, right. It's not -- that part of the 23 depositional environment is not clay prone, that gets 24 winnowed away quickly. 25 COMMISSIONER SEAMOUNT: Okay. And then one 29 1 more question for Mr. Eleftheriou, Mr. E? 2 MR. ELEFTHERIOU: Eleftheriou. 3 CHAIR FOERSTER: Eleftheriou. 4 COMMISSIONER SEAMOUNT: Eleftheriou. 5 MR. ELEFTHERIOU: You can call me George. 6 COMMISSIONER SEAMOUNT: I asked previously what 7 was the size of the unit. It would also be interesting 8 to find out what the size of the drainage area of this 9 pilot project is? 10 MR. ELEFTHERIOU: The affected area? 11 COMMISSIONER SEAMOUNT: Yeah, the affected 12 area. Okay. 13 MR. ELEFTHERIOU: We can get back to you on 14 that. 15 COMMISSIONER SEAMOUNT: That's all I've got. 16 CHAIR FOERSTER: I do also have a few 17 questions. And you -all may need to tag team on this 18 one as well and you may even need to pull in -- call a 19 friend. So we'll see where it goes. 20 For Ms. Dougherty. How long have you been 21 working the project? 22 MS. DOUGHERTY: Point Thomson, just under a 23 year. 24 CHAIR FORESTER: Okay. So the Point Thomson 15 25 and 16 wells were drilled for you? 30 1 MS. DOUGHERTY: That's right, 2009, 2010. 2 CHAIR FOERSTER: Okay. And were you involved 3 in reconciling the old model with the new data? 4 MS. DOUGHERTY: No, not directly. 5 CHAIR FORESTER: That happened before you got 6 there? 7 MS. DOUGHERTY: That happened just after -- it 8 was really 2011 that we finalized..... 9 CHAIR FORESTER: Okay. 10 MS. DOUGHERTY: .....the geologic model. 11 CHAIR FORESTER: Okay. So are you aware were 12 there a lot of changes after the 15 and 16 were 13 drilled? 14 MS. DOUGHERTY: Yeah. Well, I think so. The 15 old geologic model had a facies distribution that 16 really looked like a bald high with sediment shed in 17 all directions. And now we're really just calling that 18 bald high and shedding down to the southwest in one 19 direction. Also incorporating the winnowed 20 conglomerate, I mean, that's just -- we had to come up 21 with a story for that. And also right around that time 22 we've received some input from John McPherson who's 23 well published on fan -delta systems and have discussed 24 with him where might we find this winnowed 25 conglomerate. And what he has seen in analogs, we have 31 1 a very good analog from Nevada, we've talked with your 2 AOGCC folks about this, that in Nevada you've got a 3 situation where an alluvial fan is exposed because the 4 water has dropped and so this foreshore environment is 5 exposed and you walk around and look at it. And the 6 distribution of these facies, it looks in that 7 particular case to be related to the wind direction, 8 right, so you've got this wind constantly coming in in 9 one direction and it tends to focus the wave energy in 10 certain pockets. And so we have adopted our geologic 11 model to do that, rather than spread this all over the 12 place we say, okay, here's the shape of the fan, we're 13 going to concentrate this, we don't have conglomerate 14 in certain pods. And the -- obviously we center that 15 on the PTU-15 and then we've sprinkled one or two 16 around the -- so that's a big change I think. 17 CHAIR FOERSTER: Yeah. And if I'm remembering 18 properly the gas in place number that I used to hear 19 was 9 TCF, has it been -- has the total reserve size 20 been tweaked by the results of the drilling or am I 21 remembering the nine incorrectly? 22 MS. DOUGHERTY: I can't speak to the nine, I 23 don't know about the nine. I do know that both wells 24 came in deep. we did change our velocity model and 25 we've changed our depth structure maps, however the gas 32 1 oil contact also came in deeper. So the impact on the 2 gas volume turned out to be very little, the results of 3 those two wells. 4 CHAIR FORESTER: So you drilled two new wells and 5 you got lots of surprises. Do you expect that you'll 6 get more surprises when you drill the 17? 7 MS. DOUGHERTY: No. 8 CHAIR FORESTER: Spoken like a true geologist. 9 10 MS. DOUGHERTY: Yea, I mean, every well you 11 never know, but we do have a lot of core and a good 12 analog model now. I think we feel more confident in 13 the analog model. 14 CHAIR FOERSTER: Okay. When we embarked on the 15 studies with you guys before the 15 and 16 were drilled 16 we were told that there are 14 or 15 wells and so we 17 have a lot of confidence that the model is good and now 18 the model is different. So you might want to keep that 19 in mind as you..... 20 MS. DOUGHERTY: I know. 21 CHAIR FOERSTER: .....as you take the Polyanna 22 approach to my model is perfect. 23 MS. DOUGHERTY: Okay. Well, we'll learn from 24 the PTU-17, that's..... 25 CHAIR FOERSTER: Yeah, you -- I think you will. 33 • 1 MS. DOUGHERTY: .....we -- looking at the 2 results of that well. 3 CHAIR FOERSTER: And I think that the 4 performance of the IPS will tell you additional..... 5 MS. DOUGHERTY: Yeah. 6 CHAIR FOERSTER: Yeah. The only thing you can 7 say about a model before you've started production is 8 that it will change. 9 MS. DOUGHERTY: Yes. 10 CHAIR FOERSTER: Okay. So now I have a couple 11 questions that will probably involve a larger group. 12 So what caused you to decide on this injector producer 13 geometry as opposed just sticking with the 15 and 16 14 and having one injector and one producer, what caused 15 you to change to two injectors and one producer? And 16 that's probably more a question for you, Mr. 17 Eleftheriou. 18 MR. ELEFTHERIOU: Very good. So when we 19 drilled the PTU-15 and 16 in 2009 and 2010, Sue had 20 mentioned that we discovered H2S up to 30 PPM which is 21 what we found in the PTU-16. At that time we weren't 22 expecting H2S concentrations up to that level and so 23 the metallurgy in those wells was not fit for sour 24 service. That caused us to need to install a liner in 25 those wells which reduces the tubing size that we can 34 1 put in the PTU-15 and 16 so we're now utilizing a five 2 and a half to five inch tapered string, tubing string 3 in those wells which cannot accommodate our target and 4 production rate of 200 million cubic feet per day in a 5 single well. So that's the primary reason why we've 6 decided to use the PTU-17 as the single producer. 7 CHAIR FOERSTER: Okay. That makes a lot of 8 sense. Now in your reservoir modeling, your initial 9 plan was to have the 15 and the 16, one of them be a 10 producer, one be an injector and now you've had to 11 change that plan for clear and obvious reasons. Does 12 your modeling suggest that the new plan is as good as 13 the old plan for giving cycling a chance to succeed or 14 is it less good or better or..... 15 MR. ELEFTHERIOU: I'm not sure I can comment on 16 the relative perspective, but I know on the absolute 17 perspective that our cycling efficiency is fairly good 18 because of the distance between the two wells. It is 19 somewhat dependent on what reservoir quality we see in 20 the western part of the field and if we will -- have 21 high quality we might see early gas breakthrough from 22 the injector to the producer which is really a primary 23 risk with gas cycling operations. 24 CHAIR FOERSTER: But the placement of the 17 is 25 chosen given that it's going to be the sole producer 35 1 and you're trying to optimize the likelihood of cycling 2 success? 3 MR. ELEFTHERIOU: We're also trying to 4 establish well control in the western part of the field 5 where we currently have none. So we want to ensure 6 that we can maintain deliverability from that well so 7 we hope to see good quality reservoir. And we also 8 hope to learn more about the western part of the field. 9 CHAIR FOERSTER: Okay. The reason I'm asking 10 these questions is that the performance of the IPS is 11 going to be critical to determining the future of how 12 Point Thomson is developed, whether cycling continues 13 or you go straight to gas blowdown. So it's critically 14 important to this agency that you've done your best job 15 of trying to ensure you've given cycling every chance 16 it can to succeed..... 17 MR. ELEFTHERIOU: Yes, ma'am. Yeah. 18 CHAIR FOERSTER: .....that it's not being 19 hardwired for failure. 20 MR. ELEFTHERIOU: That is not the case at all, 21 no, ma'am 22 CHAIR FOERSTER: Okay. And, you know, and 23 another concern that we have to address is Point 24 Thomson being primarily an oil field, you know, 25 classically, you know, there's a -- there's a 36 food kro 0 1 viscous oil rim that used to be thought of as a hundred 2 foot thick viscous oil rim. Could you tell me what it 3 would take to produce that oil rim? 4 MR. ELEFTHERIOU: So we've done several 5 modeling studies on producing the oil rim. From a 6 physics perspective it is challenging because it is a 7 thin oil rim which is heavy viscous overlain by gas and 8 underlain by water. we see coning of those fluids very 9 early in production from both vertical and horizontal 10 wells. So recovery on a per well basis is fairly low. 11 So it..... 12 CHAIR FOERSTER: Okay. 13 MR. ELEFTHERIOU: .....would be challenging. 14 CHAIR FORESTER: So low recovery and those 15 wells are going to be pretty cheap, right? Pop my 16 tongue out of my cheek and let you answer the question. 17 MR. ELEFTHERIOU: No, the wells are -- I don't 18 have a specific cost figure, but they're not cheap. 19 CHAIR FORESTER: I think your drilling engineer 20 might be able to give me a ball park within $5 million, 21 a horizontal producer, injector, payer would cost? 22 MR. PODUST: So these wells that we drill..... 23 CHAIR FORESTER: Oh, and your name for the 24 record. I'm sorry. 25 MR. PODUST: Apologies. I'm Alex Podust, I'm 37 1 the drilling engineering supervisor on the Point 2 Thomson project. 3 (Off record comments) 4 MR. PODUST: So the PTU-15, 16 and 17 wells are 5 all very similar and they're all vertical or close to 6 vertical wells. A horizonal well would be 7 significantly different and more challenging. So it 8 would be hard to say off the cuff like that how much 9 they would cost, but it would cost significantly more 10 than the existing wells. 11 CHAIR FORESTER: And the existing wells cost in 12 a ball park of how much? 13 MS. NORDSTROM: Yeah, I don't think that's a 14 number we've put out publicly before so I'll need to 15 follow-up with the team. And I would say when you 16 consider well costs about 40 percent of the cost of the 17 wells has to do with the fact we're in the remote, 18 roadless environment, all logistics and support costs 19 also get built into well cost so they're extremely 20 expensive wells. 21 CHAIR FOERSTER: All right. Well, this is a 22 question that will ultimately need to be answered as we 23 consider giving the gas allowable. And, you know, if 24 you don't want to establish a record for it at this 25 time that's fine, but I'll ask again. 1 MS. NORDSTROM: Okay. 2 CHAIR FORESTER: Okay. All right. I don't 3 have any other questions at this time, do you, 4 Commissioner Seamount? 5 COMMISSIONER SEAMOUNT: I do not. 6 CHAIR FORESTER: All right. Thank you, Ms. 7 Dougherty. 8 MR. ELEFTHERIOU: So I have a couple more 9 slides here just describing the injection operations. 10 So we are on slide 13 right now. This slide is 11 describing the injection rates and pressures as part of 12 the gas cycling operations. We intend to inject 13 approximately 194 million cubic feet per day into the 14 reservoir. That injected volume is comprised of the 15 200 million cubic feet per day that we're producing 16 with condensate, water and fuel gas removed. That 17 injected gas will roughly be split equally between the 18 PTU-15 and PTU-16 injectors. To get the gas back into 19 the reservoir we need to compress it and we expect that 20 the injection pressures for the injector wells will 21 range anywhere from about 9,800 PSI to 10,000 PSI. 22 That results in a sandface pressure at the Thomson 23 reservoir of approximately 10,150 PSI. Our injection 24 facilities will be carefully monitored, all of our 25 wells are equipped with downhole gauges which will be 1 able to monitor reservoir pressure and reservoir 2 temperature. As I mentioned before the annular 3 pressure of these wells will also be monitored 4 carefully to ensure that the mechanical integrity of 5 the wells is maintained throughout our injection and 6 production operations. Ultimately we do not anticipate 7 that we will be exceeding the fracture pressure of the 8 Thomson sand or of the confining zone during our 9 injection operations and we will be carefully 10 monitoring the process to ensure that that is the case. 11 Okay. And on slide 14 we're summarizing the 12 expected composition of the injected gas. Again the 13 injected gas is the produced gas with condensate, water 14 and some fuel gas removed. It is comprised primarily 15 of methane with some ethane and propane and some carbon 16 dioxide. The figure on the right-hand side there is 17 showing the expected injection gas composition within a 18 fluid characterization. As I mentioned before we also 19 do characterize the field having some H2S. That's not 20 represented within our fluid characterization, but up 21 to 30 PPM is what we've seen so far so we expect the 22 injected to contain some H2S. Ultimately the injected 23 gas is original or native to the Thomson sand reservoir 24 so we don't anticipate there to be any compatibility 25 issues with the formation or with the fluids as we 40 1 reinject that gas. 2 So I'm going to pass it off to Alex Podust if 3 you guys don't have any questions. 4 CHAIR FOERSTER: Okay. And again your name for 5 the record, what you do for Exxon and your 6 qualifications as an expert. 7 MR. PODUST: Right. Okay. So I'm Alex Podust, 8 P-O-D-U-S-T. I'm the drilling engineering supervisor 9 for the Point Thomson project so I'm well familiar with 10 the design and the technical execution of the wells 11 comprising the Point Thomson project. I have a 12 bachelor's of science and master's of science degree in 13 mechanical engineering from Georgia Tech. I graduated 14 in 2007. So I have eight years of relevant industry 15 experience and five of those years I've spent working 16 on Point Thomson, both the previous drilling campaign 17 and this current one that's currently ongoing. 18 CHAIR FORESTER: Okay. Do you have any 19 questions? 20 COMMISSIONER SEAMOUNT: I have no questions, no 21 objections. 22 CHAIR FOERSTER: I have no questions, I have no 23 objection. 24 MR. PODUST: Okay 25 ALEX PODUST 41 • • 1 previously sworn, called as a witness on behalf of 2 ExxonMobil, stated as follows on: 3 DIRECT EXAMINATION 4 MR. PODUST: So I'll walk us through slide 5 number 15, that's my only slide. So this slide deals 6 with the injector well construction and mechanical 7 integrity. So as was previously mentioned the PTU-15 8 and 16 wells were previously drilled, suspended -- 9 drilled, tested and suspended in 2010. And for the 10 current campaign both of these wells would be 11 configured as injectors. And, in fact, we're about two 12 weeks away from completing our first well, that's the 13 PTU-16. So that's going very well. 14 The casing and tubing programs for both of 15 these wells were designed to contain all the reservoir 16 fluids in accordance with ExxonMobil design 17 requirements as well as all relevant AOGCC regulations. 18 And the diagram on the left-hand side of the slide 19 shows the other casing and tubing program as well as 20 some details of our completion. After installation the 21 mechanical integrity of the casing, the tubing, the 22 cement as well as all the other downhole and surface 23 barriers was verified or will be verified prior to 24 putting the wells into surface -- service and that's 25 done either through pressure testing or by running 42 0 1 downhole logs. 2 And then lastly a few words about our 3 completion design. So for completion design we 4 selected the cased hole frac pack. And the reason for 5 that was to control sand production over the life of 6 these wells. So some characteristics of this 7 particular completion design is perforated casing with 8 installed mechanical liners and then sized sand 9 particles have been packed into short fractures that 10 extend about 40 feet laterally from the wellbore as 11 well as the annular space between the casing and the 12 screens. And then this sand -- this size sand acts as 13 a filter for preventing the production of formation 14 sand and its flow into the wellbore. 15 CHAIR FOERSTER: And you're frack packing your 16 injectors as well as your producer? 17 MR. PODUST: That's correct. So all three of 18 our wells will have identical completions..... 19 CHAIR FORESTER: Okay. 20 MR. PODUST: .....yes. 21 CHAIR FOERSTER: So one -- two of them will be 22 skinnier than the other one? 23 MR. PODUST. Skinnier. They will look 24 basically the same. 25 CHAIR FOERSTER: I mean, the capacity of the 43 1 smaller tubing? 2 MR. PODUST: Yes, smaller tubing in the 15 and 3 16, but again the production..... 4 CHAIR FORESTER: The configuration will be the 5 same. 6 MR. PODUST: .....casing is the same size. 7 CHAIR FORESTER: Yeah. Do you have any 8 questions? 9 COMMISSIONER SEAMOUNT: Are there indications 10 of shallow gas in this field? 11 MR. PODUST: We did not see any indication of 12 shallow gas while drilling these wells or any of the 13 other ones. 14 COMMISSIONER SEAMOUNT: Okay. And it -- on the 15 surface casing am I -- oh, yeah, 4,921. Do you bring 16 cement to surface on a surface casing? 17 MR. PODUST: Yes. 18 COMMISSIONER SEAMOUNT: Okay. I was kind of 19 confused because it looks like it stops below the 20 conductor..... 21 MR. PODUST: Oh, no. 22 COMMISSIONER SEAMOUNT: .....just a shade of 23 gray. 24 MR. PODUST: Yeah, those are -- that's just a 25 feature of this diagram, it's two different cement 44 1 blend types, but it's cement to surface. 2 COMMISSIONER SEAMOUNT: Okay. That's it for 3 me. 4 CHAIR FORESTER: All right. Although we've 5 been fracturing in this country and in this state for 6 tens of years and 25 percent of Alaska's wells have 7 been fractured, when you mention the word frack the 8 uninitiated in the world kind of tighten their muscles 9 a little bit. So could you just explain for the record 10 the difference between a fracking pack and a hydraulic 11 fracture and then a brief explanation of how pumping a 12 frack and pack does not create any public health risks? 13 MR. PODUST: Right. Well, the major difference 14 between what we're doing at Point Thomson and what 15 you'd call conventional or typical shale frack is just 16 the magnitude of scale. So the purpose of our frack is 17 different. So, you know, whereas typically a frack is 18 used to stimulate the well, to stimulate well 19 production, in this case we don't need to do that. The 20 purpose is really sand control, right, so we want to 21 form that filter so that the gas flows from the 22 reservoir through the sand or, you know, through the 23 sized sand particles into the wellbore. That prevents 24 the flow of formation sand. 25 CHAIR FORESTER: So when you say sand control 45 1 for the public you mean keeping the sand -- the 2 reservoir sand and rock where they are..... 3 MR. PODUST: Yes. 4 CHAIR FORESTER: .....preventing them from 5 sloughing into the wellbore and..... 6 MR. PODUST: Correct. Yes. 7 CHAIR FORESTER: Okay. 8 MR. PODUST: So therefore, you know, as already 9 mentioned our fracks are extremely small so we're an 10 order of magnitude smaller than what you would see in a 11 typical shale gas well. 12 CHAIR FORESTER: We have a couple of reporters 13 in the audience and this probably is more meaningful to 14 them than it is to you and me, but so, you know, we 15 want to make sure that they understand and -- okay. 16 And because of the way Alaska law requires that you 17 construct wells and because of the way Exxon's 18 practices require that you construct wells, there is no 19 risk of public health or safety concerns during or 20 after the pumping of a fracking pack, correct? 21 MR. PODUST: No. So all of our modeling 22 indicates that the frack is contained within the 23 reservoir and we have also verified that the -- we 24 verified the cement quality of our production casing to 25 make sure that we have zonal isolation of them. Ent • • 1 CHAIR FOERSTER: And the pressure monitoring 2 that you did during the pumping of the fracking pack 3 confirmed that nothing was..... 4 MR. PODUST: Yes. 5 CHAIR FORESTER: .....was amiss? Okay. Thank 6 you. Do you have any concluding remarks because I have 7 other questions for the good of the order if you're 8 done? All right. You talk about the volume that's 9 going to be reinjected, it's a little bit less than the 10 volume that is produced obviously because not 11 everything's going back in. What is going to be the 12 impact of that on the reservoir pressure? 13 MR. ELEFTHERIOU: So we removed about 6 million 14 cubic feet per day as part of -- as fuel gas per 15 cycling operations. Ultimately the reservoir pressure 16 is basically maintained. There is a slight amount, 17 marginal amount, of decrease. Our modeling suggests 18 that the reservoir could -- pressure could decrease up 19 to 4 percent over 30 years of gas cycling operations. 20 But this decrease in pressure does not impact the 21 produceability of the gas at a later date. 22 CHAIR FORESTER: What impact does it have on 23 the produceability of the condensate? 24 MR. ELEFTHERIOU: So the reservoir is at its 25 dew point so as the pressure is reduced the amount of 47 1 condensate that is able to come out of the gas that's 2 produced does decrease. For gas cycling operations 3 though this amount is not very significant on the..... 4 CHAIR FORESTER: Except that you're right at 5 the dew point so..... 6 MR. ELEFTHERIOU: Right. 7 CHAIR FORESTER: .....any drop is significant 8 when you're right at the dew point? 9 MR. ELEFTHERIOU: The magnitude of the 10 condensate production decrease though at that amount of 11 reduction is not very much. I think our -- the main 12 mechanism of condensate decrease over time is really 13 due to gas breakthrough, not from reservoir pressure 14 reduction. 15 CHAIR FORESTER: Okay. According to your 16 model? 17 MR. ELEFTHERIOU: Yes, ma'am. 18 CHAIR FORESTER: And so -- okay. So I'm 19 hearing you say that gas breakthrough is the big 20 problem, that pressure reduction is not, but if 21 pressure reduction were an issue to you what would you 22 have to do to address that issue, import gas? 23 MR. ELEFTHERIOU: Could be. Also it would 24 depend on your objective and what hydrocarbons you were 25 trying to..... .• 1 CHAIR FORESTER: If your objective was to 2 maximize total hydrocarbon recovery? 3 MR. ELEFTHERIOU: Oh, importing gas to maintain 4 reservoir pressure could be an option. 5 CHAIR FORESTER: How easy is that to do at 6 Point Thomson? 7 MR. ELEFTHERIOU: Not easy at all. There's no 8 infrastructure or..... 9 CHAIR FORESTER: Okay. 10 MR. ELEFTHERIOU: .....sources identified. 11 CHAIR FORESTER: Okay. All right. Do you have 12 any other questions? 13 COMMISSIONER SEAMOUNT: Well, I noticed slide 14 16 is conclusions so are there going to be concluding 15 remarks? 16 MR. ELEFTHERIOU: Just a quick statement, 17 that's all. 18 COMMISSIONER SEAMOUNT: Okay. It looks like 19 quite an operation out there. Do you know what the 20 size of the footprint is? 21 MS. NORDSTROM: This is Christina Nordstrom 22 speaking. So our central pad is about 55 acres, that 23 footprint. The west pad, don't quote me, is probably 24 around 17. I might have to confirm, in fact, numbers 25 for the west has about 17 acres there. And so then 1 there's the -- all the remaining infrastructure that 2 was constructed such as the air strip, the infield, 3 gravel roads, et cetera that formed the footprint for 4 Point Thomson. 5 COMMISSIONER SEAMOUNT: Okay. I notice that 6 you've got quite a few buildings on the south side. 7 Are all those living quarters or..... 8 MS. NORDSTROM: Yes. The combination of 9 temporary living quarters for our construction phase 10 and then the permanent living quarters for operations. 11 COMMISSIONER SEAMOUNT: And would you be able 12 to tell me how many workers you have on location at any 13 one time? 14 MS. NORDSTROM: It is -- it is somewhat 15 seasonal. This past winter, our peak construction 16 season, we have over 800 at site. We're down in more 17 like the 600 range right now. We'll continue -- we'll 18 be ramping back up to our full bed space capacity here 19 in the next couple of months again. 20 COMMISSIONER SEAMOUNT: Okay. Thank you. Big 21 operation. 22 CHAIR FORESTER: I have no other questions for 23 you guys. We'll leave the record open for a week to 24 allow you to respond to the questions that were asked 25 that you weren't able to give answers to now. 50 1 And if Exxon is finished with their testimony 2 I'll ask if there's anyone else in the audience wishing 3 to testify? 4 (No comments) 5 CHAIR FORESTER: And I see no one. So I'll 6 thank you again for a very thorough application and a 7 very clear presentation today and for your indulgence 8 with our questions whether they be about your education 9 or trying to educate the media in the back of the room. 10 And I'll adjourn the hearing at 10:02. 11 (Adjourned - 10:02 a.m.) 12 (END OF PROCEEDINGS) 51 L] • 1 TRANSCRIBER'S CERTIFICATE 2 I, Salena A. Hile, hereby certify that the 3 foregoing pages numbered 02 through 52 are a true, 4 accurate, and complete transcript of proceedings in re: 5 Docket No.: AIO-15-017 public hearing, transcribed 6 under my direction from a copy of an electronic sound 7 recording to the best of our knowledge and ability. 8 9 Date Salena A. Hile, Transcriber 10 52 • 0 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION Public Hearing Docket No. AIO-15-017 Thomson Sand Reservoir, Pt. Thomson Unit Proposed Area Injection Order July 7, 2015 at 9am NAME AFFILIATION Testify (yes or no) OtRI J IVA(-L AC.E, 4�-D A CC No "NW41 es NsaSan", G1LUlA AOb" tyeS '::�TF� AC j ip—z f\ AA c� :E�co�n� A0 t� /&,v/Xv 44-4'e-1 4-4� /;;1 v,0/ A/y 1le1 / (_ 19,->!/1/)^C- )r�icon/406L lue) �1 DL, co P /J a Reye �kXoli /00W, /yo U-- . %fC-VAz01 1'UAe-- Gir .)- Dn / 1 t o q i( / V U U -0 o L �✓11C4- C_r— - /VV 1� w6v-- _ �y/�0 0 • Continuation Page NAME AFFILIATION TESTIFY (Please Print) (Yes or No) Point Thomson Unit Area Injection Order Public Hearing ExxonMobil Alaska Production Inc. July 7, 2015 01 • JJ�F.1 TT THOMSci_ 1j,�J1J j 1�'T Agenda Purpose • Obtain authorization to inject gas into the Thomson Sand, within the Point Thomson Unit area. Organization of the Material • Project Overview • Geology and Reservoir • Operations (Injection rates and pressures, fluid types and sources) • Drilling and Completion 2 • • Point Thomson Project Location D K ISLAN ti LIBERTY UDHOE BAY �' ` BADA'.1' - POMTTFIOMSON ANM E*onMobil Pipelines Pt. Thomson Unit and Point Thomson Gravel intrastruchue Project Location Q 5 tC Yks JULY 2015 is PTA-)11r�1 Project Overview • Establish key infrastructure • Drill and complete four wells • 1 production well (PTU-17, also known as West Pad Well) • 2 injection wells (PTU-15 and PTU-16) • 1 disposal well (PTU-DW1) • Develop facilities designed to produce 10 KBD condensate and cycle 200 MCFD of gas 16 Wastewater Daspoa& tMON- Gas a Gas t Injection Weis (Central Ped j Injection Compressor Point Thomson Export Pipeline Ell 0 t >_> � F. T To soN /// Point Thomson Unit and Affected Area ------------ Point Thomson Unit and Affected Area for A10 t080oC t E•37: :: >; u3000 "WX 466?kx 464= 4—,.= 43= 4wax 4XI333 53= $1.= Area POINT THOMSON UNIT t ' 7 PTt, S t • D Ik Area A Producer (condensate) -► injector (gas) i45 sa`ci 3 Affected Area of injected Gas """""' and Y. mile buffer c�000 t,6000 u�000 t3^000 u000a uaoao s56000 i6moo i-r000 sa�or>, esaooc a�a 0 , 3 i Sn et 01 -r 56t�w StYYfO JI 5 • • �) rJ F.]-,,TT THoms ON �1? 1�JJJT Adjacent Wells • DW-1: Class I UIC Disposal Well, drilled in 2015. Authorized by US EPA for injection of waste. • PTU-1, PTU-3, AK State D-1: Exploration wells drilled in 1970s and 1980s. Permanently abandoned per Applications for Sundry Approvals by AOGCC. 051 • r— { t J r7 f..1 TT 1.17y,_0RkLJ SCDN r-' i No Underground ' de ground Sources of ®ranking Water �n•w��•�, UNITED STATESENVIRONMENTALPROTECTION AGENCY REO!ON 10 Seat le. W Avrnue Seattle. WA9ti101 ..an° Rcq;Sy To AtLa of. OW-137 Leery D. I1ArIns Pint Thomson unit Regulatory Coordinator ttxxon✓obil Production Company AlexkA interest Organization 3301 C Strcet Suite 400 Anchorage, Xlaakn 99503 RR: Pt. Thomson Class I Injection Well - Underground Sources of Drinking Hater Door Mr. }(rums Thin letter confirms t at the CMited States EnVironmental Protection Agency (F.PA) concurs With your findin5 Lhat Lhure sic no underground oources of drinking water (U5DWr) beneath the =x:rmatrost underlying the Class 3 non-bdizardous injection Woll Currently p`opozed for thu Point Thom -non Unit (171W) on the astern North Slopu of Alaxka. The PTU i3 located immodiately Wont of the Canning Rivor and approximately 20 Mi:es enst of the • Feb. 3, 2003 EPA Determination of No Underground Sources of Drinking Water (USDW) in the Point Thomson Unit Mgr"y UNITED STATES ENVIRONMENTAL PROTECTION AGENCY A REGION 10 p 1200 Sixth Avenue, Suite 900 Seattle, Washington 98101-3140 '11.P7/ RECE SEP 2 5 Z()0� Reply To: OCE-127 SEP 30lime Par Production CERTIFIED .MAIL - RETURN R,,CFIPT REQUESTED Dale Pittman ExxonMobil Production Company P. O. Box 196601 Anchorage, Alaska 99519-6601 Re: Confirmation that the February 3, 2003, No Underground Sources of Drinking Water (USDW) determination by the U. S. Environmental Protection Agency (EPA) is still applicable to the Point Thomson Unit • Sept. 25, 2009 EPA Confirmation of No USDW Determination 7 I r_JT7T Geologic Description PTu-v Injection Zone Hue/HRZ Shale Upper Thomson ------------ Lower Thomson Pre -Mississippian Basement • Primary Resource - gas cap in the Lower Cretaceous Thomson Sand: • Porosity < 0.05 — 0.34 • • Permeability < 0.01 mD to > 50,000 mD • Hydrocarbon accumulation: —500 ft gas column; thin 37' heavy oil rim (12-14' API) • H2S 4-30 ppm; CO2 —4.5% *Abnormally pressured (-10,100 psi @-12,700' TVDSS ) • 22 wells in region, 16 penetrate Thomson Formation • • 1,776' of Thomson conventional core collected • Recent wells: PTU-15 and PTU-16 drilled 2009- 2010 • Full 3D seismic coverage, reprocessed in 2014 Original Gas in Place estimated —8 TCF r1.11_ 114 IT - � Reservoir Description p Open Framework Conglomerate Thomson: Clastic reservoir comprising conglomerates, sandstone, Bi-Modal Conglomerate and siltstones • Deposited in a fan delta setting (alluvial fan deposits reworked in shallow marine setting) Porosity average —0.14, up to 0.34 1000 100 o E 10 E d a 1' `o U 0.1 0.01 0.001 0.00 Brecda • •r 1 OPP Y• •• -.• •e • Silty sand/ S '• �• • siltstone - - PH PF2 PF5 PF3 PF4 PF6 Clean Sand i 0.05 0.10 0.15 0.20 0.25 0.30 0.35 0.40 Core Porosity • Permeability ranges from —0.01 - 50,000 mD • PTU15 penetrated high reservoir quality not previously seen in the field Sea/Leke After McPherson et al., 1987 ♦ \; y0RFr \+ ` RFSHO`f OOFO/ q14---UPgsHO E-- - - - - - - _ LTA 9 ! 'r j1. TT T HOMSON Fluid Contacts Gas Oil Contact: -12, 975' tvdss Oil Water Contact:-13,012' tvdss Contacts established using DST & MDT tests and logs is Field -wide contact suggested by depositional environment and lack of faults offsetting reservoir 12,800 12800 12,900 Q 0 13,000 13,100 PTU-16 MDT Pressure v. Depth -12767 TVDSS,12810 ND.16702 MD_ gas sam le • PTU-166as Pressure • PTU-16 Oil Pressure Gas grata l0 16 psT; 12850 — �Uoea(gas guar 12854 NDSS,12897 ND,16810 MD - gas sample 12900 12960 gas - VDSS.12953 ND.16881 MD -gas sample - 13000 13050 GOC -12,975' TVDSS oil _____ 12973NDSS.10016TV_ ----M- -gas fluid ID 12979 TVDSS.13022 TVD.16965 MD -oil sample t F�-12988 TVDSS,13031 TVD,16977 MD - oil sample 3100 luwu 10010 10080 10110 10130 10150 10170 10190 10210 10230 10250 10,050 250, 10 Pressure psi 10 0 IT THOMS ON ------------; Injection Zone Section A -A' SW — PTU-15 Section B-B' SW �I PTU-16 NE Conglomerate Clean Sand silty Sand Cemented Brec Ssitstone Cemented Corg Petrofacies PTU-16 Both injection wells penetrate excellent to good reservoir quality in the proximal facies of the fan delta (conglomerate and sandstone). 11 is r r Y1jJJ� JJ�'T Confining Zone Confining zone made up of Hue/Hrz shale or Canning Fm shale where Hue/Hrz is absent Fracture gradient — 0.91 psi/ft A AK-F1 PTI I_7 S AK-D1 1:19MI A' PTI I-1 A TA - IF t£ ,a • ,r . 1F ..:: ;�. T,: �4�5 �% 5. .::; ::ter -„,:a - - ...:......,: ,'.� ��'.: u Tv,^, N tS; •=..I 31'3 :a.a..-.xsu - - AN S. _ - - ,- =L5 ::. ..:...a _:. •3 ._..:...... w.. - =Canning F (t 8 i Pre is. base e t ? IAIt— V.3 ' I rC, •1 "� I I tR1`1t Tracks: gamma ray, deep and shallow resistivity Lwr CanningFm Confining Zone Hue/HRZShale Thomson Sand Injection Zone Pre -Miss Basement 12 IT Operations - Injection Rates and Pressures • Designed injection rate is 194 million standard cubic feet per day (MMSCFD) — Injected gas is gas from produced fluid minus condensate, water, and fuel gas — Injected gas split between PTU-15 and PTU-16 at approximately equal rates • Injection pressures for PTU-15 and PTU-16 at the wellhead range from 9,800 psi to 10,000 psi — Sandface pressure approximately 10,150 psi — Wells equipped with downhole gauges for reservoir pressure and temperature monitoring. Annulus pressure of injection wells PTU-15/16 will also be monitored — Sandface pressure gradient (-0.80 psi/ft) is less than the Thomson fracture gradient and confining zone fracture gradient (-0.91 psi/ft) Central Pad Processing Facilities 13 9 I J) �� TT I G;1\1I_l (� _ i Operations - Fluid Types and Sources • Injected gas is the produced fluid with condensate, water, and fuel gas removed — Contains mainly methane (Cl), ethane (C2), and carbon dioxide (CO2) — Trace components such as H2S (<30ppm) also present • Injected gas originated in the reservoir and is compatible with the reservoir fluid and formation Estimated Composition of Injected Gas Stream Component Mole 87.397 4.2190 1.6440 0.3200 0.5450 0.1890 0.1920 0.1860 0.0960 0.0430 0.0160 0.0050 0 0 0 0 0 0 0.6640 4.4600 14 • PTU-15 Completion Insulated Conductor 34" x 2O" X56 145'MD Surface casing 13-3/8"L80 1` 4,921'MD/4572'MD rr T i 7-5/8" Liner Top / PBR 13,439' MD / 10,586 TVD Intermediate Casing 10-3/4" P-110 13,773'MD / 10,822TVD 4" Shunted Screens 3-1/2" SCSSV 4500' TVD GP Packer 15,769'MD / 12,355TVD Top Thomson 16,127' MD / 12,658' TO Perforation Depth 16,144'MD / 12,672'TVD-16,358'MD / 12,855TVD Base Thomson 16,376 MD / 12,871' TVD Injector Well Construction and Mechanical Integrity • PTU-15 and PTU-16 wells drilled, tested, and suspended in 2010 • Both wells to be configured as injectors and completed in 2015 • Casing and tubing program was designed to contain reservoir fluids in accordance with ExxonMobil design requirements and all applicable AOGCC regulations • After installation, mechanical integrity of casing, tubing, cement, and other downhole and surface barriers tested prior to putting wells into service • Cased Hole Frac Pack completions installed for sand control over the life of the wells — Perforated casing with installed mechanical screens — Sized sand packed into short fractures (40" lateral length) and annular space between screens and casing 15 16 • • Roby, David S (DOA) From: Calder, Steve /C <steve.calder@exxonmobil.com> Sent: Thursday, May 14, 2015 12:27 PM To: Davies, Stephen F (DOA) Cc: Nordstrom, Christina D; Roby, David S (DOA) Subject: FW: Pt Thomson Area Injection Order Applications - Questions Attachments: EM Legal Description AIO Gas Injection Affected Area 05.13.15.pdf Hi Steve, Thanks for your careful review of the legal description. A revised description addressing all of your questions is attached. If there are no other questions, please replace the legal description table in the Application for Area Injection Order with this revised table. Regards, Steve Calder Environmental/Regulatory Point Thomson Project Consultant to ExxonMobil Office (907)564-3787 Cell (907)351-4538 steve.colder@exxonmobil.com Begin forwarded message: From: "Davies, Stephen F (DOA)" <steve.daviesnalaska.g,ov> To: "Nordstrom, Christina D"<christina.d.nordstrom@exxonmobil.com> Cc: "Roby, David S (DOA)" <dave.roby@alaska.gov> Subject: Pt Thomson Area Injection Order Applications - Questions Christina, On a page -sized map (attached), I plotted the legal description of the Affected Area provided in ExxonMobil's Application for Area Injection Order. The portion of the legal description shown on page 1 of ExxonMobil's application contains no errors or discrepancies. However, I have a few questions and comments on the portion of the description presented on page 2 of the application. My hand-written questions and comments are shown in the attachment. Could you please ask your staff to check the legal description and provide a revised version if necessary? Please let me know if you have any questions. Regards, Steve Davies Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission (AOGCC) Phone: 907-793-1224 • AOGCC: 907-279-1433 Fax: 907-276-7542 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 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 Steve Davies at 907-793-1224 or steve.daviesgalaska.gov<maiIto: steve.daviesgalaska.gov>. Affected Area: Umiat Meridian Townshin & Ranee Sections Portion(s) 10 North, 24 East 29 W-1/2 SW-1/4 10 North, 24 East 30 S-1/2, NW-1/4, and SW-1/4 NE-1/4 10 North, 24 East 31 All 10 North, 24 East 32 W-1/2 10 North, 23 East 16 SW-1/4, and S-1/2 SE-1/4 10 North, 23 East 17 SW-1/4, and S-1/2 SE-1/4 10 North, 23 East 18 SW-1/4, and S-1/2 SE-1/4 10 North, 23 East 19-22 & 25-30 & 34-36 All 10 North, 23 East 23 S-1/2, S-1/2 NE-1/4, and NW-1/4 10 North, 23 East 24 SW-1/4, S-1/2 SE-1/4, and NW-1/4 SE 1/4 10 North, 23 East 31 N-1/2, and N-1/2 SE- 1A 10 North, 23 East 32 N-1/2, N-1/2 SW-1/4, and N-1/2 SE-1/4 10 North, 23 East 33 N-1/2, SE-1/4, N-1/2 SW-1/4, and SE-1/4 SW-1/4 10 North, 22 East 24 E-1/2, and E-1/2 SW-1/4 10 North, 22 East 25 E-1/2, E-1/2 NW-1/4, and E-1/2 SW-1/4 10 North, 22 East 36 NE-1/4 9 North, 24 East 5 W-1/2, and W-1/2 NE- 1A 9 North, 24 East 6 All 9 North, 24 East 7 N-1/2, N-1/2 SW-1/4, and N-1/2 SE-1/4 9 North, 24 East 8 NW-1/4 9 North, 23 East 1 & 2 All 9 North, 23 East 3 N-1/2, SE-1/4, N-1/2 SW-1/4 9 North, 23 East 4 NE-1/4 9 North, 23 East 11 N-1/2 NW-1/4, NE-1/4 9 North, 23 East 12 N-1/2, N-1/2 SW- 1A, and N-1/2 SE-1/4 Roby, David S (DOA) From: Davies, Stephen F (DOA) Sent: Thursday, May 07, 201S 10:3S AM To: christina.d.nordstrom@exxonmobil.com Cc: Roby, David S (DOA) Subject: Pt Thomson Area Injection Order Applications - Questions Attachments: MAP_Pt_Thomson_Affected_Area_From_Legal_Description_201SOSO7.pdf Christina, On a page -sized map (attached), I plotted the legal description of the Affected Area provided in ExxonMobil's Application for Area Injection Order. The portion of the legal description shown on page 1 of ExxonMobil's application contains no errors or discrepancies. However, I have a few questions and comments on the portion of the description presented on page 2 of the application. My hand-written questions and comments are shown in the attachment. Could you please ask your staff to check the legal description and provide a revised version if necessary? Please let me know if you have any questions. Regards, Steve Davies Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission (AOGCC) Phone: 907-793-1224 AOGCC: 907-279-1433 Fax: 907-276-7542 333 West 7`h Avenue, Suite 100 Anchorage, AK 99501 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 Steve Davies at 907-793-1224 or steve.davies@alaska.gov. /1 S I PTU —AIO r Township & Ranee Section ` Portion s 10 North, 23 East 19-2 & 2S-30 & 34-36 • All 10 North, 23 East 21 4'/ All 10 North, 23 East 22 iicRiff All 10 North, 23 East 23 cdvt�/<cf ram' S-1/2, S-1/2 NE-1/4, and NW-1/4 10 North, 23 East 24 SW-1/4, S-1/2 SE-1/4, and NW-1/4 SE 1/4 10 North, 23 East 31 N-1/2, and N-1/2 SE-1/4 10 North, 23 East 32 N-1/2, N-1/2 SW-1/4, and N-1/2 SE-1/4 10 North, 23 East 33 N-1/2, SE-1/4, N-1/2 SW-1/4, and SE-1/4 SW-1/4 10 North, 22 East 19 ? All 1D r✓ 23 10 North, 22 East 24 E-1/2, and E-1/2 SW-1/4 10 North, 22 East 25 E-1/2, E-1/2 NW-1/4, and E-1/2 SW-1/4 10 North, 22 East 36 NE-1/4 9 North, 24 East 5 W-1/2, and W-1/2 NE-1/4 9 North, 24 East 6 All 9 North, 24 East 7 N-1/2, N-1/2 SW-1/4, and N-1/2 SE-1/4 9 North, 24 East 8 NE-1/4 ? 9 North, 23 East 1 & 2 All 9 North, 23 East 3 N-1/2, SE-1/4, N-1/2 SW-1/4 9 North, 23 East 4 NE-1/4 9 North, 23 East 11 N-1/2 NW-1/4, NE-1/4 9 North, 23 East 12 N-1/2, N-1/2 SW-1/4, and N-1/2 SE-1/4 1.4 Project Description [20 AAC 25.402 (c)(4)) (4) a full description of the particular operation for which approval is requested; ExxonMobil is progressing construction and drilling activities to develop hydrocarbon resources within the PTU, located on the North Slope of Alaska. The primary hydrocarbon accumulation is the Thomson Sand, a high-pressure gas condensate reservoir that underlies state lands onshore and state waters offshore. The Thomson Sand discovery well, the Point Thomson Unit No. 1 well, was drilled in 1977. Altogether 22 wells have been drilled in the Point Thomson area, including most recently PTU-15 and PTU-16 in 2009-10, and PTU DW-1 in 2015. ExxonMobil is pursuing a gas cycling project to initiate production from the Thomson Sand reservoir and deliver liquid condensate for sale. 2 �Z� 0 ■ m Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Docket No. AIO-15-017 Thomson Sand Reservoir, Pt. Thomson Unit Proposed Area Injection Order ExxonMobil Production Company, by application dated May 1, 2015, has requested that The Alaska Oil and Gas Conservation Commission, issue an area injection order to establish rules governing injection of fluids for enhanced recovery purposes for the Thomson Sand Reservoir, Pt. Thomson Unit. The AOGCC has tentatively scheduled a public hearing on this application for July 7, 2015 at 9:00 a.m. at the Alaska Oil and Gas Conservation Commission, at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. To request that the tentatively scheduled hearing be held, a written request must be filed with the AOGCC no later than 4:30 p.m. on May 25, 2015. If a request for a hearing is not timely filed, the AOGCC may consider the issuance of an order without a hearing. To learn if the AOGCC will hold the hearing, call 793-1221 after June 10, 2015. In addition, written comments regarding this application may be submitted to the Alaska Oil and Gas Conservation Commission, at 333 West 71h Avenue, Suite 100, Anchorage, Alaska 99501. Comments must be received no later than 4:30 p.m. on June 10, 2015, except that, if a hearing is held, comments must be received no later than the conclusion of the July 7, 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 July 1, 2015. / �) ;41e-� Cathy . Foerster Chair, Commissioner STATE OF ALAS" ADVERTISING ORDER ADVERTISING ORDER NUMBER AO-15-021 FROM: Alaska Oil and Gas Conservation Commission AGENCY CONTACT: Jody Colombie/Samantha Carlisle DATE OF A.O. 05/05/15 AGENCY PHONE: 1(907) 793-1221 333 West 7th Avenue Anchorage, Alaska 99501 DATES ADVERTISEMENT REQUIRED: COMPANY CONTACT NAME: PHONE NUMBER: Publish 5/6/15 FAX NUMBER: (907)276-7542 TO PUBLISHER: Alaska Dispatch News SPECIAL INSTRUCTIONS: PO Box149001 Anchorage, Alaska 99514 TYPE OF ADVERTISEMENT: DESCRIPTION PRICE AIO 15-017 Initials of who prepared AO: Alaska Non -Taxable 92-600185 S1 B0.4TT tNVO ICE SHOWING ADVERTISING G ORDERNO., CERTrF ED AFFIDAVIT OF PUBLICATION WITH ATTACHED COPY OF ADVERTISNIENT TO: Department of Administration Division of AOGCC 333 West 7th Avenue Anchorage, Alaska 99501 Pace I of I Total of All Paaes S REF Type Number Amount Date Comments I PvN ADN84501 2 Ao AO-15-021 3 4 FIN AMOUNT SY CC PGYI LGR ACCT FY DIST LIQ 1 15 02140100 73451 15 2 3 4 Pure in e: Title: Purchasing Authority's Signature TelephoneNwuber DISTRIBUTION: Division Fiscal/Original AO Copies: Publisher (faxed), Division Fiscal, Receiving Form:02-901 Revised: 5/4/2015 270227 0001364124 • • RECEIVED $ 209.18 MAY 0 8 Z015 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 May 06, 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 6th day of May, 2015 Notary Pubtiein and for The State of Alaska. Third Division Anchorage, Alaska MY COMMISSION EXPIRES Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Docket No. AIO-15-017 Thomson Sand Reservoir, Pt. Thomson Unit Proposed Area Injection Order ExxonMobil Production Company, by application dated May 1, 2015, ha: requested that The Alaska Oil and Gas Conservation Commission, issu( an area injection order to establish rules governing injection of fluids for enhanced recovery purposes for the Thomson Sand Reservoir, Pt Thomson Unit. The AOGCC has tentatively scheduled a public hearing on this application for July 7, 2015 at 9:00 a.m. at the Alaska Oil and Gas Conservarequeston Commission, at ht 7th �te 100 Anchoage, Alaska 99501. To at he scheduledtentatively hearing be held, a written request must be filed with the AOGCC no later than 4:30 p.m. on May 25, 2015. If a request for a hearing is not timely filed, the AOGCC may consider the issuance of an order without a hearing. To learn if the AOGCC will hold the hearing, call 793-1221 after June 10, 2015. In addition, written comments regarding this application may be submitted to the Alaska Oil and Gas Conservation Commission, at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. Comments must be received no later than 4:30 p.m. on June 10, 2015, except that, if a hearing is held, comments must be received no later than the conclusion of the July 7, 2015 hearing. If, because of a disability, special accommodations may be needed to -omment or attend the hearing, contact the AOGCC's Special Assistant, lody Colombie, at 793-1221, no later than July 1, 2015. AO-15-021 Published: April 16, 2015 Cathy P. Foerster Chair, Commissioner Singh, Angela K (DOA) From: Colombie, Jody J (DOA) Sent: Tuesday, May 05, 2015 9:58 AM To: Bender, Makana K (DOA); Bettis, Patricia K (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Guhl, Meredith D (DOA); Hunt, Jennifer L (DOA); Kair, Michael N (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Wallace, Chris D (DOA); AKDCWellIntegrityCoordinator; 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); Donna Ambruz; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Frank Molli; Gary Oskolkosf, George Pollock; ghammons; Gordon Pospisil; Greg Duggin; Gregg Nady; gspfoff, Hulme, Rebecca E (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; 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; Thor Cutler, Tim Mayers; Todd Durkee; Tony Hopfinger; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Walter Featherly; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater; Anne Hillman; Bajsarowicz, Caroline J; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Donna Vukich; Eric Lidji; Erik Opstad; Gary Orr, Smith, Graham O (PCO); Greg Mattson; Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Holly Pearen; 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; Peter Contreras; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Peterson, Shaun (DNR); Pollard, Susan R (LAW); Talib Syed; Todd, Richard 1 (LAW); Tostevin, Breck C (LAW); Wayne Wooster, William Hutto; William Van Dyke Subject: Notice of Public Hearing, AIO-15-017 (Exxon's Request for AIO) Attachments: Notice of Public Hearing, AIO-15-017.pdf • • James Gibbs Jack Hakkila Bernie Karl P.O. Box 1597 P.O. Box 190083 K&K Recycling Inc. Soldotna, AK 99669 Anchorage, AK 99519 P.O. Box 58055 Fairbanks, AK 99711 Gordon Severson Penny Vadla George Vaught, Jr. 3201 Westmar Cir. 399 W. Riverview Ave. P.O. Box 13557 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Karen D. Hagedorn 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 Angela K. Singh ExxonMobil Production Comp P. O. Box 196601 Anchorage, Alaska 99519-6601 907 561 5331 Telephone 907 564 3677 Facsimile May 1, 2015 ER-2015-OUT-198 Cathy Foerster, Chair Alaska Oil & Gas Conservation Commission 333 West Seventh Avenue, Suite 100 Anchorage, Alaska 99501-3572 Karerlftagedorn AlaskalWction Manager E�onMobil Production RECEIVED MAY 0 1 2015 AOGCC Re: CONFIDENTIAL ExxonMobil Alaska Production, Inc. Application for Area Injection Order, Point Thomson Unit Dear Commissioner Foerster: Attached please find ExxonMobil Alaska Production, Inc.'s application for Area Injection Order (AIO) to re -inject gas produced from the Thomson Sand back into the Thomson Sand, within the Point Thomson Unit area. Two copies of the application are being provided; a public application with confidential content removed and a confidential application that is marked "CONFIDENTIAL" on the front page of the application and at other points in the document. ExxonMobil Alaska Production, Inc. specifically requests that AOGCC treat Figure 9 and other information identified as "Confidential" in the confidential application as confidential, and not disclose this information in the formal public process, or otherwise. Please contact Christina Nordstrom by phone at (907) 334-2943 or via email at christina.d.nordstrom@exxonmobil.com if you have any questions. Sincerely, KDH:jpc Attachments: Public Application with Confidential Content Removed Confidential Application for Area Injection Order A Division of Exxon Mobil Corporation CONFIDENTIAL Application for Area Injection Order Point Thomson Unit Submitted to Alaska Oil and Gas Conservation Commission by ExxonMobil Alaska Production, Inc. May 1, 2015 • This page left intentionally blank PTU — NO Table of Contents 1. Introduction and Development Overview............................................................................................ 1 1.1 Introduction........................................................................................................................................1 1.2 Plat of Wells [20 AAC 25.402(c)(1)]..................................................................................................... 1 1.3 Operators and Surface Owners [20 AAC 25.402 (c)(2) and (c)(3)].....................................................1 1.4 Project Description [20 AAC 25.402 (c)(4)]........................................................................................ 2 2.0 Geoscience and Description of Injection Zone................................................................................. 4 2.1 Geoscience [20 AAC 25.402 (c)(5), (c)(6),(c)(7)]................................................................................. 4 2.1.1 Structure.....................................................................................................................................4 2.1.2 Stratigraphy (Thomson Sand)..................................................................................................... 5 2.2 Description of Injection Zone.............................................................................................................. 5 2.2.1 Thomson Sand and Pre -Mississippian Basement........................................................................ 5 2.2.2 Reservoir Quality, Petrofacies, and the Geologic Model (Thomson Sand) ................................. 6 2.2.3 Petrofacies in the IPS Wells......................................................................................................... 7 3.0 Drilling and Completion.................................................................................................................... 7 3.1. Mechanical Integrity and Design of Injection Wells [20 AAC 25.402 (c)(8)]..................................... 7 3.1.1 Casing Design.............................................................................................................................. 8 3.1.2 Cased Hole Frac Pack Design........................................................................................................ 9 3.1.3 Mechanical Integrity of Other Wells [20 AAC 25.402 (c)(15)]..................................................10 4. Production and Operations................................................................................................................. 10 4.1 Injection Fluid Description [20 ACC 25.402(c)(9)]............................................................................10 4.2 Injection Pressures [20 ACC 25.402(c)(10)]..................................................................................11 4.3 Confining Zone [20 ACC 25.402(c)(11)]........................................................................................ 12 4.3.1 Confining Zone (Hue/HRZ Shale, the Canning Fm, and pre -Mississippian Basement) ..............12 4.4 Formation Water [20 ACC 25.402 (c)(12)]........................................................................................12 4.5 Freshwater Exemptions [20 ACC 25.402 (c)(13)]..........................................................................13 4.6 Incremental Recovery [20 ACC 25.402(c)(14)]............................................................................. 13 ReferencesCited: ........................................................................................................................................ 14 Exhibit 1— Notice of Area Injection Order Application Affidavit................................................................15 Exhibit 2 — Wellbore Schematic, PTU-16..................................................................................................... 17 Exhibit 3—Wellbore Schematics for Point Thomson Unit #1, Point Thomson Unit #3, andAlaska State D-1..................................................................................................................................18 Exhibit 4 — EPA Determination of No USDW............................................................................................... 21 Confidential Exhibit - Point Thomson Area Injection Order Application.................................................... 24 • • This page left intentionally blank PTU — AIO PTU — AIO 1. Introduction and Development Overview 1.1 Introduction This application for area injection order (AIO) seeks authorization to re -inject gas produced from the Thomson Sand back into the Thomson Sand, within the Point Thomson Unit area. This application has been prepared by ExxonMobil Alaska Production, Inc, operator of the Point Thomson Unit, in accordance with 20 AAC 25.460 (Area Injection Orders) and applicable technical requirements of 20 AAC 25.402. (Enhanced Recovery Operations) that are referenced in 20 AAC 25.460. While the Section 402 requirements are included under the general heading of Enhanced Recovery Operations, no "extraneous substances" are proposed to be injected during this gas cycling operation. 1.2 Plat of Wells [20 AAC 25.402(c)(1)] (1) a plat showing the location of each proposed injection well, abandoned or other unused well, production well, dry hole, and other well within one -quarter mile of each proposed injection well; Figure 1 shows the PTU IPS affected area for the injected gas in relation to the Point Thomson Unit, the expected Initial Participating Area (Areas A and B) for the Thomson Sand, and the surface and bottomhole locations of the three development wells for the IPS Project. Figure 1— PTU IPS Affected Area 1 PTU - A10 QUARTER MILE BOUNDARY FRO161 AFFECTED AREA ijPOINT THOMSON PROJECT • • • PTU — AIO Figure 2 shows the affected area plus a % mile buffer superimposed on the township -range - section grid. In addition, Figure 2 shows the PTU field facility layout including gravel infrastructure, which includes the Central Pad and West Pad. Figure 2 also shows the PTU-15 and PTU-16 wells, both of which will be in injection service and covered by this AIO, and the planned PTU-17 producing well, the Class I UIC disposal well, PTU-DW1, and three abandoned wells within or adjacent to % mile of the affected area (Point Thomson Unit #1, Point Thomson Unit #3, and Alaska State D-1). 1.3 Operators and Surface Owners [20 AAC 25.402 (c)(2) and (c)(3)] (2) a list of all operators and surface owners within a one -quarter mile radius of each proposed injection well; (3) an affidavit showing that the operators and surface owners within a one -quarter mile radius have been provided a copy of the application for injection, The Point Thomson Unit was formed in 1977 and is operated by ExxonMobil. The approximate working interests of the Unit owners are: • ExxonMobil62.24% • BP Exploration (Alaska) Inc. 32.04% • ConocoPhillips Alaska, Inc. 4.96% • 21 other owners with a total combined working interest of less than 1% The State of Alaska is the surface owner of the PTU leases. Exhibit 1 is an affidavit showing that the Point Thomson Unit working interest owners and the State of Alaska, Department of Natural Resources, Division of Oil and Gas have been provided a copy of the application for area injection order. The affected area of injected gas as indicated by the areal distribution of injected gas (methane) in the reservoir simulation after 30 years is shown in Figure 1. Below is the legal description for the affected area shown in Figure 1. Affected Area: Umiat Meridian Township & Ranee Section (sJ Portion s 10 North, 24 East 29 W-1/2 SW-1/4 10 North, 24 East 30 S-1/2, NW-1/4, and SW-1/4 NE-1/4 10 North, 24 East 31 All 10 North, 24 East 32 W-1/2 10 North, 23 East 16 SW-1/4, and S-1/2 SE-1/4 10 North, 23 East 17 SW-1/4, and S-1/2 SE-1/4 10 North, 23 East 18 SW-1/4, and S-1/2 SE-1/4 0 PTU — AIO Township & Ranee Section (sl Portion s 10 North, 23 East 19-23 & 25-30 & 34-36 All 10 North, 23 East 21 All 10 North, 23 East 22 All 10 North, 23 East 23 S-1/2, S-1/2 NE-1/4, and NW-1/4 10 North, 23 East 24 SW-1/4, S-1/2 SE-1/4, and NW-1/4 SE 1/4 10 North, 23 East 31 N-1/2, and N-1/2 SE-1/4 10 North, 23 East 32 N-1/2, N-1/2 SW-1/4, and N-1/2 SE-1/4 10 North, 23 East 33 N-1/2, SE-1/4, N-1/2 SW-1/4, and SE-1/4 SW-1/4 10 North, 22 East 19 All 10 North, 22 East 24 E-1/2, and E-1/2 SW-1/4 10 North, 22 East 25 E-1/2, E-1/2 NW-1/4, and E-1/2 SW-1/4 10 North, 22 East 36 NE-1/4 9 North, 24 East 5 W-1/2, and W-1/2 NE-1/4 9 North, 24 East 6 All 9 North, 24 East 7 N-1/2, N-1/2 SW-1/4, and N-1/2 SE-1/4 9 North, 24 East 8 NE-1/4 9 North, 23 East 1 & 2 All 9 North, 23 East 3 N-1/2, SE-1/4, N-1/2 SW-1/4 9 North, 23 East 4 NE-1/4 9 North, 23 East 11 N-1/2 NW-1/4, NE-1/4 9 North, 23 East 12 N-1/2, N-1/2 SW-1/4, and N-1/2 SE-1/4 1.4 Project Description [20 AAC 25.402 (c)(4)] (4) a full description of the particular operation for which approval is requested, ExxonMobil is progressing construction and drilling activities to develop hydrocarbon resources within the PTU, located on the North Slope of Alaska. The primary hydrocarbon accumulation is the Thomson Sand, a high-pressure gas condensate reservoir that underlies state lands onshore and state waters offshore. The Thomson Sand discovery well, the Point Thomson Unit No. 1 well, was drilled in 1977. Altogether 22 wells have been drilled in the Point Thomson area, including most recently PTU-15 and PTU-16 in 2009-10, and PTU DW-1 in 2015. ExxonMobil is pursuing a gas cycling project to initiate production from the Thomson Sand reservoir and deliver liquid condensate for sale. 0 0 PTU — AIO The Point Thomson Initial Production System (IPS) Project will: 1) bring natural gas and condensate to the surface from the Thomson Sand reservoir; 2) recover liquid condensate; 3) re -inject the residual gas back into the reservoir. The condensate will be transported through the Point Thomson Export Pipeline (PTEP) for delivery to the Badami, Endicott and Trans -Alaska Pipeline System common carrier pipelines. The IPS also will provide information about gas condensate production and reservoir connectivity to assist in subsequent development plans. The IPS Project includes drilling wells, installing and operating infield pipelines and processing facilities, and installing support infrastructure including construction of the PTEP. In its full production mode after PTU-17 is drilled, the IPS will have one producing well (PTU-17) and two gas injection wells (PTU-15 and PTU-16). Gas will be cycled at the rate of about 200 million standard cubic feet per day (mmscfd) and routed to the Central Processing Facility where up to 10,000 barrels per day of condensate will be extracted from the gas. Some of the cycled gas will be used as fuel for the processing facilities. The remainder of the gas will be injected back into the Thomson Sand reservoir to help maintain reservoir pressure and conserve the gas for future development. One option under consideration is commissioning and initial startup of the IPS processing facilities using the PTU-15 well as a producer and the PTU-16 well as a single injection well, both of which are located on the Central Pad. In that case, after the third development well (PTU- 17) is drilled and completed, that well would become the single producing well and PTU-15 would be converted to injection service. The following activities have been completed to date: • Two development wells (PTU-15 and PTU-16) were drilled in 2009 and 2010. • An Environmental Impact Statement was prepared and federal, state and local permits and authorizations needed to initiate expanded site construction were obtained during 2009 through 2012. • Pads, connecting roads, an airstrip, camps, and other support infrastructure have been installed and the PTEP constructed. • A UIC Class I nonhazardous disposal well was drilled during 1Q 2015. This well was permitted by the US Environmental Protection Agency and is not part of the proposed AIO. • A gathering (flow) line was installed from West Pad to Central Pad in 1Q - early 2Q 2015. Remaining work scope to be completed in 2015-16 includes the following: 3 • PTU — AIO • Central Pad wells PTU-15 and PTU-16 will be completed during 2nd and 3'd Q 2015. PTU- 15 is being completed in a manner such that it may be used to initiate production as discussed above and then converted to injection service without requiring any downhole well work. Facility process modules are being fabricated offsite and will be sealifted to Point Thomson, installed, and commissioned in the 2nd half of 2015. • Anew development well, PTU-17, will be drilled on the West Pad during 2015 and 2016 and completed as a producer. 2.0 Geoscience and Description of Injection Zone 2.1 Geoscience [20 AAC 25.402 (c)(5), (c)(6), (c)(7)] (5) the names, descriptions, and depths of the pools to be affected, (6) the name, description, depth, and thickness of the formation into which fluids are to be injected, and appropriate geological data on the injection zone and confining zone, including lithologic descriptions and geologic names; (7) logs of the injection wells if not already on file with the commission; There are 16 penetrations to the reservoir interval (Thomson Sand) in the Unit, including the recently drilled PTU-15 and PTU-16 wells. The Thomson Sand interval is shown on the gamma ray and resistivity logs for the PTU-16 well (Figure 3). Other wells drilled in the area that did not penetrate the Thomson Sand provide information in delineation and understanding of the extent of the Thomson Sand, as well as important velocity information in the overburden. Over 1,750 feet of Thomson Sand core has been acquired and described. Multiple drill stem tests were conducted during the exploration stage in the late 1970-early 1980s. Modular dynamic tester (MDT) and well test results were conducted in the PTU-15 and PTU-16 wells. Multiple 3D pre -stack time migration and pre -stack depth migration surveys exist over the Point Thomson Unit, acquired from 1989 —1998. The primary dataset used for current mapping is constructed from four merged 3D surveys: Challenge Island, Point Thomson Unit, Island Corridor West, and Flaxman Lagoon (Figure 4). In 2013, the Point Thomson Unit 3D survey was re -processed to improve reservoir image and definition. In 2011, a well -based velocity model was constructed using five velocity intervals; depth maps are constructed using this velocity model and the 1989 Point Thomson merged seismic cube. 2.1.1 Structure The Thomson Sand hydrocarbon accumulation is mainly defined by a gently dipping anticlinal closure. Normal faults are observed in seismic, but they do not completely offset the reservoir PTU — AIO (Figure 5). The sand -on -sand juxtaposition across faults and the fairly continuous facies bands across the field suggest the reservoir is not compartmentalized. Good reservoir communication both between wells and within each wellbore is supported by similar gas pressure gradients measured in the MDT tests in the PTU -15 and PTU-16 wells. 2.1.2 Stratigraphy (Thomson Sand) The Thomson Sand was deposited during the Early Cretaceous above a regional unconformity. It overlies Pre -Mississippian basement and is overlain by the Late Cretaceous Hue shale (Figure 6). The reservoir comprises pebbly to boulder conglomerates and breccias, sandstones, and siltstones that were likely shed from proximal basement provenance in the northeast, transported towards the southwest, and deposited in a fan delta/shoreface setting (Figure 7). Evidence for a fan -delta 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 interpreted source terrain with rapid facies transition down -dip. Based on core description and log analysis, the Thomson Sand is separated into Upper and Lower members. The lower member is largely progradational, while the upper member is largely retrogradational. The areal distribution of environments of deposition (EOD) is guided by the description of facies distribution at the Rose Creek fan delta, Walker Lake, Nevada by Blair and McPherson (2008). 2.2 Description of Injection Zone 2.2.1 Thomson Sand and Pre -Mississippian Basement The Lower Cretaceous Thomson Sand is the primary reservoir affected by injection. It is dominantly a gas reservoir with a —500' gas cap and a thin 37' oil rim. The Thomson Sand is approximately-13,000' subsea depth and abnormally pressured. Reservoir pressure is approximately 10,100 psi at-12,700' TVDSS, the approximate midpoint of the gas cap. Average reservoir temperature is 220-230'F. The gas -oil and oil -water contacts are interpreted to be consistent across the field, and water drive is expected to be weak. The gas -oil contact (GOC) is -12,975' TVDSS, and, in parts of the field, the gas -filled reservoir overlies basement rock. The GOC was identified with Modular Dynamic Testing (MDT) samples which identified gas at -12,973 TVDSS and oil at -12979 TVDSS (Figure 8). The oil -water contact (OWC) is estimated at - 13,012' TVDSS based upon confidential well tests and log data included in a separate confidential attachment. The injection interval correlates to strata in the PTU-3 (13,657-13,932' MD) as observed on the gamma ray and resistivity logs (Figure 10). The reservoir is a high net -to -gross system with reservoir quality decreasing to the southwest. Reservoir thickness ranges from —200' to —300' 5 PTU — AIO TVD. In the two injector wells, the thickness is 214' TVD (PTU-15) and 264' TVD (PTU-16). In the planned producer, the PTU-17, the reservoir thickness is estimated to be —200' TVD. Gas will be injected back into the Thomson Sand matrix porosity, assisted by the cased -hole frac pack described in 3.1.2 and will not cause further fracturing of the Thomson Sand or breach the overlying confinement zone. The Thomson Sand lies unconformably on upper pre -Mississippian basement (Figure 11) which, based on cuttings description and limited cores in exploration wells, is composed of various low-grade metasedimentary rocks (phyllite, argillite, quartzite, and dolomite). Dolomitic basement is possibly naturally fractured, as indicated by DSTs in three wells in the north part of the Unit (Alaska State F1 and Alaska Island 1 tested gas, and the Alaska State Al tested water). Therefore, fractured dolomitic basement is considered to be in pressure communication with the Thomson sand in the north area. Low porosity (1%) and modest permeability (78 mD vertical, 1 mD horizontal) values are assigned to the upper basement. Based on the predicted distribution of fractured basement and limited storage capacity, the pre -Mississippian basement is not expected to play a significant role during the IPS cycling program. Very limited information is available for the lower pre -Mississippian basement; it is considered non -net and defines the base of the geologic model. Original gas in place (OGIP) for the Point Thomson Unit is approximately 8 TCF. This volume is stored mostly in the Thomson Sand (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. 2.2.2 Reservoir Quality, Petrofacies, and the Geologic Model (Thomson Sand) The average porosity for the Thomson Sand is —14% (range "2% to —32%) with permeability extending to more than 10 darcy for the open framework conglomerates. Six petrofacies (PF1- 6) have been identified in core based on grain size, sorting, cementation, and ductile grain content; these six petrofacies also form logical groupings in a porosity and permeability plot (Figure 12). Conglomerates are divided into three petrofacies on the basis of sorting and cement concentration (open -framework, bi-modal, and cemented conglomerates). The open framework conglomerate, which was cored in the PTU-15, is hypothesized to be a re -worked facies, where the interstitial, fine -to -very fine sand component has been removed by wave action resulting in excellent reservoir quality. The sandstones are divided into two categories based on ductile grain concentration (clean and silty). Generally, the Thomson sand is a litharenite (Figure 13), with the lithic components predominately sedimentary fragments of dolomite, stable quartz -rich fragments, and clay -rich sedimentary fragments. A 3D geocellular model has been constructed using Petrel software. The primary inputs to the geologic models are: C] • PTU — AI0 • Depth maps interpreted using the pre -stack depth seismic cube, tied to tops identified in 16 wells • Petrofacies and depositional environments from cored wells • Petrophysical logs output used in a neural net predictive tool to populate petrofacies in all the wells • Depositional analog from the Rose Creek fan delta at Walker Lake, Nevada to further populate the model between well control Combinations of the petrofacies are assigned to the various EOD belts (Figure 14). The proximal facies are dominated by conglomerates and clean sandstones with the more distal facies comprising silty sand and siltstone. The foreshore environment contains the "winnowed" sub -environment dominated by the open framework conglomerate petrofacies. The distribution in the model of this petrofacies and EOD away from the PTU-15 is driven by analog with the Rose Creek fan delta at Walker Lake, Nevada (Figure 7). 2.2.3 Petrofacies in the IPS Wells Based on the model described above for the planned producer, PTU-17, the EOD for the Upper Thomson sand is expected to be proximal lower shoreface, and in the Lower Thomson, the EOD is expected to be upper shoreface with a mix of either winnowed foreshore or foreshore (Figure 15). These EODs are in the same general, proximal position as the PTU-15, although there may not be as much of the winnowed conglomerate in PTU-17 (Figure 16). Even if winnowed conglomerate is not found in the PTU-17 well, very good reservoir quality is expected in the bi- modal conglomerate and clean sand facies. The PTU-16 injection well penetrated a section slightly down depositional dip, and, therefore, had more distal lower shoreface reservoir than the PTU-15. Nevertheless, the distal lower shoreface includes the clean sand petrofacies which exhibit very good porosity and permeability properties. Figure 17 shows well logs comparing the petrofacies and EODs from the PTU-15 and PTU16 with the expected petrofacies in the PTU-17 producer. 3.0 Drilling and Completion 3.1. Mechanical Integrity and Design of Injection Wells [20 AAC 25.402 (c)(8)] (8) a description of the proposed method for demonstrating mechanical integrity of the casing and tubing under 20 AAC 25.412 and for demonstrating that no fluids will move behind casing beyond the approved injection zone and a description of (A) the casing of the injection wells if the wells are existing; or (B) the proposed casing program, if the injection wells are new; PTU — AIO The PTU-15 and PTU-16 injection wells were drilled, cased, tested, and suspended in 2009 and 2010 and will be completed in 2015 for service as described above. The wells will be completed with cased hole frac packs under AOGCC regulations 20 AAC 25.283 (see Exhibit 2 — Wellbore Schematic PTU-16). The initial drilling as well as the completion of the wells comply with AOGCC regulations and ensure mechanical integrity as outlined below and described in more detail in the drilling permit applications, completion reports, and Applications for Sundry Approvals. • The injection wells have been cased and cemented in accordance with 20 AAC 25.030 to prevent leakage into oil, gas, or freshwater sources. • After completion, the injection wells will be equipped with tubing and a packer that isolates pressure to the injection interval. The minimum burst pressure rating of the tubing will exceed the maximum surface injection pressure by at least 25 percent as required by 20 AAC 25.412. • The packers will be placed as close to the perforations as practical given the completion design requirements and the spacing has been approved by the AOGCC in the Applications for Sundry Approval for the completion operations. • Before injection begins, the injection wells will be pressure -tested to demonstrate the mechanical integrity of the tubing and packer and of the casing immediately surrounding the injection tubing string. The test pressures will be addressed in the Applications for Sundry Approvals. • At least 48 hours' notice of the above pressure tests will be provided to the AOGCC so that a representative can witness the tests, if desired. • A cement quality log will be run as part of the completion process and provided to the AOGCC with the frac pack Applications for Sundry Approval. 3.1.1 Casing Design The casing programs for the PTU-15 and PTU-16 wells are set forth below. PTU-15 and 16 wells, drilled and tested in 2009 — 2010, were not designed for sour service. During testing, up to 30 ppm H2S levels were measured. It was determined that the existing metallurgy of the production casing was not suitable for long term service at observed H2S concentrations and that remediation was required. A tieback liner, made out of H2S resistant material, will be installed to fully cover the existing production casing and convert PTU-15 and 16 wells to sour service. PTU-16 Casing Design: 8 PTU — AIO • 13-3/8" 72# L-80 Vam Top KE, which was set below permafrost at 4,480' TVD • 10-3/4" 71.1# P-110 Vam Top KS intermediate casing, which was set incompetent formation to allow for Thomson Sand penetration • 8-5/8" 52# C-110 Vam SFC liner tie -back, which will be set to isolate the P-110 intermediate casing due to H2S • 9.307" 32.39# C-90 SET Expansion liner, which was set to gain additional formation integrity to allow for production interval drilling • 7-5/8" S13Cr95 Vam Top FJL production liner, which was set at TD at the base of the Thomson Sand interval (13,155' TVD) PTU-15 Casing Design: • 13-3/8" 72# L-80 Vam Top KE set, which was below permafrost at 4,572' TVD • 10-3/4" 71.1# P-110 Vam Top KS intermediate casing, which was set incompetent formation to allow for Thomson Sand penetration • 8-5/8" 52# C-110 Vam SFC liner tie -back, which will beset to isolate the P-110 intermediate casing due to H2S • 7-5/8" S13Cr95 Vam Top HC SC80 production liner, which was set at TD at the base of the Thomson Sand interval (12,952' TVD) 3.1.2 Cased Hole Frac Pack Design Point Thomson wells are designed to utilize a cased -hole frac pack completion. The completion will consist of perforated casing with installed mechanical screens. The frac pack completion will create a short length fracture packed with gravel as well as a gravel pack around the mechanical screens that, combined, will serve to control potential sand production from the wells. The Hue/HRZ shales act as an upper confining layer limiting upward extension of the fracture, and the Pre -Mississippian basement properties provides the lower confining layer. Fracture gradient in the Thomson is estimated at 0.88 — 0.94 psi/ft (17 —18 ppg). In the location of the PTU-15 and PTU-16 injectors the anticipated fracture pressures are estimated to be between 11,100 psi to 12,000 psi. Preliminary modeling from PTU-16 shows that the fracture will be confined within the reservoir formation and an effective fracture half-length of about 50 feet is expected (Figure 18). Sensitivities of various modeling parameters such as Young's modulus, fluid properties, and fracture stage evolution are still being tested. Preliminary fracture geometry for both PTU-15 and PTU-16 will be included in the Sundry Application to Fracture (plan to be submitted in 2nd quarter 2015). 9 0 PTU — AIO 3.1.3 Mechanical Integrity of Other Wells [20 AAC 25.402 (c)(15)] (15) a report on the mechanical condition of each well that has penetrated the injection zone within a one -quarter mile radius of a proposed injection well. ExxonMobil understands that for an Area Injection Order, the area of review of other wells is applied to the affected area as shown in Figure 1. On this basis, in addition to the PTU-15 and PTU-16 injection wells, the following wells within one -quarter of a mile the affected area and their mechanical integrity conditions are: Class I UIC Disposal Well, PTU-DW1 As noted, the Class I UIC Disposal Well was permitted by the US Environmental Protection Agency (AK 11015-A) and authorization for injection of wastes is not being requested pursuant to this AIO application. The well has been drilled and cased in accordance with AOGCC Permit to Drill 214-206 and AOGCC regulations including 25 AAC 25.412. Abandoned Exploration Wells There are three abandoned exploration wells that are within or adjacent to 1/4 mile of the area affected by injection into the PTU-15 and PTU-16 wells: Point Thomson Unit #1, Point Thomson Unit #3, and Alaska State D-1. All three wells were drilled in the 1970s and early 1980s and have been permanently plugged and abandoned in accordance with the Applications for Sundry Approval approved by the AOGCC. All three wellbores are greater than one -quarter of a mile from the PTU-15 and PTU-16 injection wells at their injection intervals. Further, the wells contain adequate cement plugs around and within the well casing so that the wells will not allow injection fluids from the PTU-15 and PTU-16 wells to migrate from the injection zone. Copies of the Well Completion or Recompletion Reports and final wellbore schematics are attached as Exhibit 3. 4. Production and Operations 4.1 Injection Fluid Description [20 ACC 25.402 (c)(9)] (9) a statement of the type of fluid to be injected, the fluid's composition, the fluid's source, the estimated maximum amounts to be injected daily, and the fluid's compatibility with the injection zone; The produced full wellstream from the Thomson Sand reservoir will be separated into gas, condensate, and water. The fluid proposed for injection is the residue gas. The estimated composition of this gas is shown in Table 1. The hydrocarbon and non -hydrocarbon components, as defined by fluid characterization, are expressed by the mole percentage. 10 • PTU — AIO The estimated maximum amount to be injected on a daily basis will be approximately 194 mmscfd, which represents the estimated 200 mmscfd production rate minus shrinkage for condensate extraction and fuel. The injection gas originates from the Thomson Sand reservoir and, other than removal of condensate, will not be altered. Consequently, it is inherently compatible with the injection zone. Table 1: Estimated Composition of Injected Gas Stream Component Mole % 4.2 Injection Pressures [20 ACC 25.402 (c)(10)] (10) the estimated average and maximum injection pressure; The average steady-state wellhead injection pressures for PTU-15 and PTU-16 are estimated to be from 9,800 psi to 10,000 psi at a gas injection rate of approximately 100 mmscfd per well. The anticipated sandface pressures for PTU-15 and PTU-16 under steady-state injection operations are estimated to be 10,150 psi at these rates. If severe wellbore degradation were to occur and impair injectivity in the wells (skin greater than 500), sandface pressures would be expected to rise to 10,400 psi. This scenario would not exceed the fracture pressures of the 11 0 PTU — AlO confining zones nor the Thomson sand in PTU-15 and PTU-16. In addition to careful surface monitoring, the injection wells will be outfitted with bottomhole gauges which will allow the operator to ensure that the sandface pressures remain within a safe range of operation. Process controls will shut down the system if the injection pressure reaches 11,025 psig. 4.3 Confining Zone [20 ACC 25.402 (c)(11)] (11) evidence to support a commission finding that each proposed injection well will not initiate or propagate fractures through the confining zones that might enable the injection fluid or formation fluid to enter freshwater strata; 4.3.1 Confining Zone (Hue/HRZ Shale, the Canning Fm, and pre -Mississippian Basement) As described in Section 3.1.2, the confining zone is represented primarily by the Hue/HRZ marine shale and secondarily by the overlying Canning Formation of the Lower Brookian sequence (Figure 11). The Hue/HRZ shale is characterized by high gamma ray response indicating high clay and/or organic content (Figure 19). In the PTU-15, this shale is —89' thick, and in the PTU-16, it is —321' thick. This shale unit has variable thickness due to erosion by the base Canning Formation and may not be present in the northern part of the field. However, where the Hue/HRZ shale may be absent or very thin, the lower Canning siltstone and shale is present and is considered the confining layer. Below the Thomson Sand, the upper pre -Mississippian basement rocks act as a lower confining zone (Figure 11). Basement in the PTU-15 and PTU-16 wells is argillite and quartzite metasedimentary rocks, and core from PTU-3 found argillite and phyllite with calcite -filled fractures. Both gamma ray and density logs in the two injector wells indicate this zone will prevent downward growth of the fracture during the cased -hole gravel pack completions (Figure 20). 4.4 Formation Water [20 ACC 25.402 (c)(12)] (12) a standard laboratory water analysis, or the results of another method acceptable to the commission, to determine the quality of the water within the formation into which fluid injection is proposed, No formal water analyses have been performed due to the unavailability of a true formation - water sample (uncontaminated by drilling fluids). The only water sample data available are from drill stem tests (DSTs) in the AK C-1, AK G-2, Staines River State #1, and PTU-4 wells; the chlorides (CI) from these tests ranged from 35,000 — 41,000 ppm. Pickett Plot analysis using resistivity and density porosity logs indicate a base -case formation water resistivity (Rw) of 0.04 ohmms, or 58,000 ppm NaCleq. The range of Rw is from 0.055 to 0.04 ohmms, or 37,000 ppm to 81,000 ppm. 12 0 PTU — AIO 4.5 Freshwater Exemptions [20 ACC 25.402 (c)(13)] (13) a reference to any applicable freshwater exemption issued under 20 AAC 25.440 There are no known underground sources of fresh water in the affected zone and, accordingly, no requests have been made for exemptions pursuant to 20 AAC 25.440. AOGCC previously approved injection into shallower formations for disposal of drilling and other oilfield wastes into the Alaska State A-2 disposal well and into annuli of exploration wells. In conjunction with approval of the application for the UIC Class I disposal well, the EPA confirmed there are no underground sources of drinking water (USDWs) within the PTU. This determination (Exhibit 4) was initially confirmed by EPA on February 3, 2003, and re -confirmed on September 25, 2009, for aquifers below approximately 1800'TVD (base of the permafrost). 4.6 Incremental Recovery [20 ACC 25.402 (c)(14)] (14) the expected incremental increase in ultimate hydrocarbon recovery, As noted in Section 1.4, the IPS is a gas cycling project that will produce condensate associated with gas from the reservoir and re -inject the residue gas. As with any gas cycling project, re- injection of the gas is inherent to the process and all produced liquids are considered "base" production rather than incremental recovery. The IPS will recover liquid condensate while preserving the gas for future development. Condensate recovery rate in a gas cycling project such as the IPS is dependent on the condensate -gas -ratio of the fluid, the connectivity between the injection wells and the producing well, and the total rate of production from the producing well. The expected initial condensate -gas -ratio for the produced fluid will be approximately 50 stock tank barrels per million standard cubic feet of gas, and it will decline as reservoir pressure decreases and injected gas migrates to the producer. The IPS Project produces condensate while preserving the potential for gas production in the future by re -injecting gas. The IPS will also improve understanding of the reservoir. Consistent with industry accepted practice, the IPS cycling project will result in a small reduction in field pressure (approximately 4% over 30 years) due to condensate production and associated fuel consumption. 13 • • References Cited; PTU — A10 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. Schenk, C.J., and Houseknecht, D.W., 2008, Geologic Model for Oil and Gas Assessment of the Kemik-Thomson Play, Central North Slope, Alaska, USGS Scientific Investigations Report 2008- 5146, 27p. 14 • • PTU - AIO Exhibit 1- Notice of Area Injection Order Application Affidavit Affidavit of Karen D. Hagedorn I, Karen D. Hagedorn, being duly sworn, hereby state as follows: 1. 1 am the Alaska Production Manager for ExxonMobil. I have personal knowledge of the matters set forth in this affidavit. 2. The accompanying application for an Area Injection Order addresses wells PTU-15, PTU-16, and PTU-17 which are located within the Point Thomson Unit. 3. The Point Thomson Unit is located on land owned by the State of Alaska and leased for purposes of oil and gas development to the Working Interest Owners listed on the following page. 4. ExxonMobil Alaska Production, Inc. is the Operator of the Point Thomson Unit and is authorized by the State to develop the oil and gas resources within the Unit. 5. A copy of this application has been sent to the Point Thomson Unit Working Interest Owners. 6. A copy of this application has been sent to the Director of the Division of Oil & Gas, State of Alaska Department of Natural Resources, as notice to the owner / lessor of the land comprising the Point Thomson Unit. 7. There are no other operators or surface owners within a one -quarter mile radius of the proposed injection wells. 8. 1 certify under penalty of perjury that the above statements are true and correct to the best of my knowledge and information. Subscribed and sworn this 1st day of May, 2015: Karen D. Hagedorn Date otary Signature Date Notary Public JANICE P. CAMPBELL State of Alaska My Commission Expires Apr 30, 2016 15 Exxon Mobil Corporation BP Exploration (Alaska) Inc. ConocoPhillips Alaska, Inc. Colt Alaska, LLC Pacific Lighting Gas Development Company Kingdon R. Hughes Family Partnership Cook Inlet Energy LLC Chap-KDL, LTD Eastland Property & Minerals John Peery Searls Susan Jeanne Searls Collier The Eastland Oil Company Aubris Resources, LP PBA Land Development Ltd. Jan D. O'Neill G. Arther Donnelly III Robert R Donnelly Pinta Real Development, LLC David Donnelly Trust Richard Donnelly, Jr. Trust Samson Offshore, LLC Sunlite International Inc. Linda Lou Searls Neidert WoodBine Petroleum Inc. 16 PTU - AIO • 0 Exhibit 2 - Wellbore Schematic, PTU-16 UplxY J? 162015 PTU-16 Planned Final Schematic ALL DEPTHS APPROXIMATE 1.5 x hied Conductor 4" 320' X58, PE weld 157 TVDI6ID I'A" amv+�,nhn x ru1: B.9ppg Isotherm insulating packer fluid T.berim 6.8ppg base oft Surface Casing; 13-M" 72# L-80 VAM TOP KE- Special Drift 4.889 MD 14,4110' TVD B 5J8' 52# SMC 110T To back Liner 8-518' Tie back Liner Seal Assembly ID 8.542' 7-5f8" Liner top I PBR 13.68V MD f 10,254' TVD Intermediate Casing; 10-3-4" 71. 1# P-110 VAM TOP KS 13,548' MD 110,576' NO 1 1 1 1 Expandable Casing; tiW x 10-3t4" SET 1 14,ii6'� 111,270' TVD j Tap Thomson 10.088` MD 112.79T TVD Perforation Depth 10.0981dD / 12,805rf VD - 17,DD4WD 113.053'TVD Base Thomson 17.D14' MD 113,001' TVD Production Liner; 7-578' Liner, 47.1# 13Cr;-95, FJL 17.128' MD 113,155' TVD TD Well 17.136' MD 1 13,161, TVD Tubing Hanger 5.5", 29.7# S13Cr95 Tubing 5" DCIM Inc 718 5" DCIM Inc 118 3-1l2' TRSCSSV Inc 118 5.5", 29.7# S13Cr95 Tubing 5.5" NPQG Inc 718 5.5", 29.7# 513Cr95 Tubing 5", 23"S13Cr95 Tubing 1 3-112" Sliding Sleeve S13Cr110 1 2.75" "X" Landing Nipple 1 Production Seal Assembly 1 GP Packer Assembly 10,452 .' 12.008-TVD MCS Inc 711 Fluid Loss Valve 18,523'W0 t2,805TV0 Safety Shear Joint 4-.11 04 Regular Blanks I 4-,11.010 Dpbpac Blanks .�. 2 X 2 Optipac Screens S13Cr95 Permanent Seal Assembly Sump Packer - Permanent Packer 17 Top of Shx Track 5, 90V ...t.. 12,986' 10144 13.086' 10.254 16.210' 12.4 16.398' 14`11 16,452' 12;608- 16.527 12, 665 16.68V 16,696' 1T.004' 17,014' 17.029' PTU - A10 E PTU — A10 Exhibit 3-Wellbore Schematics for Point Thomson Unit #1, Point Thomson Unit #3, and Alaska State D-1 Exxon Mobil Corporation Pt. Thomson Unit #1 AN #: 50-089-20005 PTD#: 176-085 Final Well Schematic 13.318" x 9 51�t1" Annulu#: • Cemant from marker plate to #3,276' 3.5r)tY mudIC:aCi2 interface Perforations 11,392' - 11,421,, squeezed with 50 sx class G Retainer at 19,302' Perforations 12,834'-12.874, a sqLoezod with 76 sx class G Perforations 12.963' - 13,0E0, squeezed with 145 sx class G through retainer Point Thommon Unit In t3' below tundra 10 6 ppg CaC12 TO - 13.298' 18 in 9.5/8" from marker plate to t130' 18-518' at 801 13.378% 72#, N-80 at 3,276' Top 7' casing 4,000't — 15.3 ppg mud 15.6 Mg mud TOC betwnd 9-5t8' casrrtg at 6.900' 7", 36111, whack cmtd wr 120 sx Class G Top?" finer at 9,032' 9-518'. 40#, 5-95 at 9,537 TOG at 10,740'1 in 7' C811 V TOL 4-1Z finer at 10.873' Packer at 11,300`± 7'. 35", S-95 at 11.390' TOG In 4-1/2' Nner at 12.100 . 3bbis cement cn top of retainer Packer at 12,700'1 Retainer at 12,895' 15.6 Dog rruc Pae:keratt2,900r .---��— P8TD at 13,248', 4-1/2- 15.1q, 5-95 canny at 1:3,2CNVNfdW wth 31 / sx class U • PTU — NO Exxon Mobil Corporation Point Thomson Unit #3 API 0: 50-089-20007 PTD #: 178-OOS Final Well Schematic Marker Plate _>3' below tundra level Cement plug from marker plate — ±75' 8GL in 9-&S" casing 10.2 ppg CaCl2 s 18-5/8', 96 4 ppf. K55, BTC cond csg at 811MD (811' TVD), Brine ' ' cmtd w/ 4,300 sx permafrost — Cement in 9-5i8" x 13.3I8" annulus from marker plate to ±3,338'. Cast iron bridge plug at 2,000' MD 15.9 pp8 Fresh 13-318" 72 ppf, L80, BTC surf csg at 3,338' MD t4'ater (1298' TVD), cmtd to surf wf 3,750 sx permafrost i Mud TOC behind 9.5/8' casing estimated at 5,000' Top cf cement in 9-5i8" casing at 8,869' MD Bake( cement retainer at 9,019' MD PP9 Fresh 7", 35 ppf, P110, BTC production casing stub at 9,502' MD Water 9-5/8' 47# Soo-95 at 10,347' MD (9681' TVD) cmtd wi 2,450 Mud : sx class G Top of cement inside 7' casing at 13,612' MD Top of cmt outside 7" csg at 13,664' MD per cmt bond log Halliburton cement retainer at 13,847' MD Baker model F-1 production packer at 13.852' MD Perlorations 13,872'—13,885' MD, 2 spf. 1800 Cast iron bridge plug at 13,890' MD Baker model F-1 production packer at 13.892' Parforations 13.908' — 13,925 MD, 2 spf, 180' Top of cement inside 7' casing at 14,024' MD (float collar) JP.�-t 7", 35 ppf, P110, BTC, prod csg at 14,114' MD (13,140' t' I'-TVD), cmtd w/ 1.035 sx class G 8-117 open hole TD at 14,125' MD (13,151' TVD) Poktt Thon»on Unk 93 Pa" 1 at 1 19 0 • LI Dapthw RK6 RK6 = 3/' MLLW Grade = 0' M" Cement Tn 13 3/fS x 9 i/B' Anmdw tram 53, b aS' Mf6 CaGy is 13 3/6' x N SA' Mnukw 1rm 66' to r Permafrost Rasa Costa 20' x 13-3/6'fo 2.100' Comets Below 13-3/6' shwa PaAW~ LEGEND QComont U Mud MCOC12 Wahr NO SCAti FAIR/EXXOWUAS 101 1:1 6/15/96 $R q'f 9 i 1 AN Casinga Cut annl d Reowe4 a -1S' 1/LLW (53' no' 42' RarigaaNan Casing O 30' Structural Cosky a 110' MN of Conant O 154' a/- (RKO) Permafrost Camed to 53' M(B 10.2 ppg CaC12 to 2.000' 26' 133 6/ff K55 NTC Conductor Casing O 2.056' I'sawinfed to Surface roe Appf*A Mel, 3AW', C$m i U-3/6' 72 //ft 110 OTC Surface Casng a 3AW 0.6 PP0 Mud 7 PP9 Mud NC APOMWMG" 7.500'. Close G " tap 9.90a'. 120 Socks Gan G NOW00 USV Rafafn a 9,979' 9-5/6' 43.5 #/R Pita LTC Prd.eNw Coaing 610.0e t 1.S No Mad I Botbm ! 10,200' 15.7 PP9 Mud 11.200 Top of Plug NO at Clap 0 11,90 OeMem of Plug t1P6 MW Skkdrack a 12.959' 1IAW N a 13,060' 6-1/2' NW* Figure 1 EXXON Company U.S.A. Alaska State D-1 Wellbore Schematic, April 1998 PTU — AIO • • Exhibit 4 - EPA Determination of No USDW �... e+A � UNITED STATES ENVIRONMENTAL PROTECTION AGENCY REGION 10 1 200 Sint» Avenue. Suite 900 S.M., Waatting;on 96101.3140 '�"°"°g RECEIVED SFP 2 5 200' SEP 341009 Reply To: OCE-127 D" PM"W Producton 44MIM C ERTIFIED ~JAIL - REJURti RECEIPTREQUFSTED Dale Pittman ExxonMobil Production Company P. O. Box 196601 Anchorage. Alaska 99519-6601 Rc: Confirmation that the February 3, 2003, No Underground Sources of Drinking Water (USDW) dettrmination by the U. S. Environmental Protection Agency (EPA) is still applicable to the Point Thomson Unit Dcar Mr. Pittman: This letter is in response to your correspondence sent September 14. 2009. socking confirmation that EPA's no USDW determination on February 3, 2003. is still applicable to the Point Thomson Unit as described. Thank you for providing the map and legal descnption of the Point Thomson Unit. Based on the review by my staff of the map and legal description of the Point Thomson Unit, EPA hereby confums that the determination by EPA on February 3, 2003, that thcrc are no USD W's below the pennafTost within the Point Thomson Unit is still applicable to the unit area as defined by the legal description and Point Thomson Unit trap. If you have any question, or concern,, please feel free to contact 'Thor Cutler of mr stab' at(206)553.1673. Sincerely. - [dward J wa i, Director Office of Compliance and Enforcement cc: Shawn Stokes. ADEC Division of Water, Wastewater Discharge Permits Dan Seamouni, AOGC'C op"em rlbe.- Po r 21 PTU — A10 • • F`�-03-2Ob3 'XiN R9.31 Afl P. t►2 FibiW141 UNITED STATESSENYIRONMENTAL PROTECTION AGENCY A L 0 SbA 10 +zoosmhAVM" 33 SaalNe, WA9eSOt A�1n•) ( ...T � rR Mply To c' n n 2A03 I� W of: M-137 Lwrx y 1). Norms point Thomson Uric: Regulatory Coordinator 3: rxonvobi i Prod%icr i.on Company Al,imka Interest Organization 3301 C Strcwt Suite 400 Anchorave, Alaska 99503 Rr: Pt. Thomson Class I injection Well - Underground Sources of Drinking water vonr Mr. I[Axms. Thin letter confirms that tee Jotted Staten Environmental Pr*teetion Agency (EPA) concurs with your fi.-adinci that there ore no underground sources of drinking water (USDWr) beneath the permafrost underlying the Claus i non -hazardous injection wall currently proposed for the Point Thomson Unit (PTU) on the 4:agtarn North Slope of Alaska. The PTU is located immodiatolY wort of the craning River and npproximataly 20 miles east of the Ifadamt devolopnent. Moro specifically, RPA agrees with your conclusion that chore are no USDWs baneath.the 15oroafrost anywhere within the PTU boucadanries as depicted in figures 2-1 of the "Point Thomson Ca■v Gya).inq Project - Hnvironwmntal Report' prepared by URS (July 1. 2001) (gee: attachment). This conclusion is based on the analysis Of four (4) drill stem test formation water samplwm (from wells Alaska State V-1, Alaska State G-2, Alaska C-1, and eadami i5) and lvg derived total dio3olved solids (TDS) estimates from the "'our wells non --out to the proposed Class I well in the PTU (Wpet Staines-1, PTU 111, PTU 10, and Alaska State C-1) desccibed in your lettern of October and December. 2002 (Exxonmobil PTU "rhu8nce of USDW' Correspondence from Larry Harms to Randall S:eith, 8HA dated 10/18/02 and 12/13/02). These analyses and octimatosn, coznhihad with the facts that the aquiforc within the Vill do not supply any publie water nyestem and do r:oL currently supply drinkiwi waster for human consumption, indicate that theca atli.i tars do not -moat the definition of "undorground source of drinking wator' found at 40 C F.R. 5 144.3. To confirm this conclusion, EPA zaquoste that Hxxontlobil obtain uccual rormacton water samples from potential water- *ft1Wd *P9V~rn 22 PTU — AIO • • PTU — AIO FEB-03-M MN 09:32 M FM Na P. U3 2 b,0,%rjng zones in the interval between the base of the permafrost anA the top of the proposed injection interval. It this is not feasil,)e, oithor slue to constraints resulting from well construction or reservoir uechunics, a mininum suite of open hole gcophysical logs cahould be run so that reliable log -derived TDS erseimat"s from Resistivity - Porosity and/or Spontaneous Potential logs can be calculated for the PTU Class I injection wall. Por any questions, please call Thor Cutler at (206) 553- 1613 . sincerely, r^ pandall P . Smith Director Office of Water tiny AtteLcbwentl Figure 2.1 of the Point Thomson Gas Cycling ProjAct - Unvironuontal Report prepared by DRS (July 1, 2001). Filn: l-6'/-1 q_00001 No-USM B"Onitobil Pt. Thomson Class 1 ccc Anita Praukol, SPA Oil.& Gas Team (w/attachsent) Tim Hamlin, MpU Mqr. (W/attachment) rete W-Geft, ADD, FSKS (w/attacbmant) Marcia Comhes, ZPAi ADO (w/attaChMOnt) Ted Rockwell, EPA. ADO D/G Team (M/attAch:sent) 23 Figure Set for Application for Area Injection Order Point Thomson Unit May 1, 2015 • 0 • Figure 3: Gamma ray and resistivity logs for the PTU-16 showing the Thomson Sand (injection zone) and the overlying Hue/HRZ and Canning Formation (confining zone) • Canning Formation Hue/HRZ Shale Thomson Sand C ? u Yukon Gold 1994 2d seismic lines 3D Seismic Database: Primary Dataset constructed from 4 merged 3D surveys: — Challenge Island (1998) — Pt. Thomson Unit (1989) —Island Corridor West (1998) —Flaxman Lagoon (1998) Other 3D surveys (pstm): — West Thomson (1997) — Flaxman OBC (1997) —Yukon Gold (1994) Merged Prestack Depth Migrated Seismic Volume Figure 4: Map showing historic surveys acquired in the Point Thomson area. Current seismic survey used is the Pt Thomson, 1989 Merged Survey • 0 444000 448000 452000 � AAK F✓ P 10 4 � o � 438000 440000 444000 448000 45= 4,% 480000 contour interval 250' 4CAC 9Z77 Thomson Sand Pre -Miss Basement Figure 5: Top Thomson Sand Structure Map in the Participating Area with a representative seismic profile at the reservoir interval • 0 Ma z lwJ CENOZOIC Z 40 w L 65 Z Y 96 8 CRETACEOUS m 9144 0 w v JURASSIC Z UJ =) 208 O w Z TRIASSIC zas � v+ PERMIAN 286 UJ 320 CARBONIFEROUS 360 DEVONIAN TO PROTEROZOIC Hue Shale (seal/ confining zone) Thomson Sand (reservoir/injection zone) Figure 6: Generalized stratigraphic column for the Pt Thomson area, (modified from Schenk and Houseknecht, 2008) • . — q P7IIJ - Non net AK' , 11�•f Grhhore IJ TrarwtgrW � t>MWtowershoretxt . prOUffQ1 rower stwrtfxt . upper srwrelxe Q Fort+nae WS _ . roreswe wwowed 0 Srfldas W_■ 1✓ N G2 571 Coalescing Fan Deltas, Walker Lake Nevada FAN -DELTA �+� `• =Tarr �Y, , (A) y� Fan Delta , nnr va^e�w, •se , ,•,', , Now"O"k ,jam*,'fe,rripiiir�E` •'•K=• faub Pan Do& . fH Dsh •rar � WALKSt LAKE V0:an Ewe �,,�FMemhng Wind Prevailing Wind Direction Direction Coalescing Fan Deltas, Walker Lake Nevada w/EODS ` C `......... ,r' -Taw N e AlluvialFm, Foreshore Shoreface Offshore Direction Figure 7: Depositional model for the Thomson Sand with Environments of Deposition (EOD) and petrofacies composition with analog from Walker Lake, Nevada (Blair and McPherson, 2008) • 12800 12850 12900 13000 13050 13100 10 PTU 16 FORMATION PRESSURE VS. DEPTH -12767 TVDSS,12810 TVD,16702 MD - gas sam le • Thomson PTU16 gas samples ■ Thomson PTU 16 oil samples Gas grad (0,16 psi4t) -Linear (gas -12854 TVDSS,12897 TVD,16810 MD - gas sample grad) f--12910 TVDSS,12953 TVD,16881 MD -gas sample -12973 TVDSS,13016 TVD,16958 MD -gas fluid ID _ —----k---4----I--- --- 12979 TVDSS,13022 TVD,16965 MD - oil sample -12988 TVDSS,13031 TVD,16977 MD - oil sample GOC 13018 -------- TVD / -1297 TVDSS — —— — — —— " - - - - - - - - - - - - - - - - - - - - - - - - - - 1050 10070 10090 10110 10130 10160 10170 10190 10210 10230 10, FM Press (PSI) Figure 8: Results of MDT data from PTU-16 showing the gas points (16,958' MD and above) and the two oil points (16,965' and 16,977' MD) >-50 0 • PTU_3 [SST-1D_ VSH SST -VD ME) DRESS RHOS xe Z -1 PHIT 0. C4 1.G5 1:2c24 =v+... '"C. scd.�cce GR gAPI 3 w ',fRES PlPHI .. C.POR . Su SRES Colorfill Colorfill 12500 -1-1349:.5 127Cd -I-137:0-3 128r.O+'MD4.5-3 —7- — 12900 -T- 1 MW.8 13=+ -±714013.1 I I I I r131001t4"741 M I I I I JA I I I I Track 1: Gamma ray and VShale Track 2: Deep, medium, and shallow resistivity (0.2— 2000 ohm) Track 3: Density (Rhob, 1.65-2.65 g/cm3) and Neutron Porosity (0-0.60) Track 4: Total Porosity with core porosity points (0-0.50) Hue/HRZ Shale I* Upper Thomson Lower Thomson Pre -Mississippian Basement Figure 10: The Thomson sand interval in the PTU-3 exploration well, shown with the overlying Hue/HRZ Shale and Canning Fm and the underlying pre -Mississippian basement Producer PTU-17 Injector PTU-15 ^'1 mi Canning Formation Vertical exaggeration 1Ox Hue/HRZ Shale ----------------------- 1 Thomson Sand ----------- ------------------------------------------ .;o 129 5 OWC-13012'� • Upper Pre -Mississippian Basement Figure 11: Schematic cross section from the producer (PTU-17) to one of the injector wells (PTU-15). PF-2 Bi-modal Conglomerate ' 6 �. i PTU-15, 16288.7 ft MD Poorly sorted conglomerate Increasing presence of fines obstructing pore space. PF-5a&b Cemented Cong. & Breccia E AK-G2, 15741.3 ft >10% cement PF-1 Open Framework Conglomerate PTU-15, 16309.8 ft MD Moderately well sorted, pore space not obstructed by the presence of fine to very fine grain sand. � ■t• —7 mm Z-velu . Petro/ j" FINAL, CleenFe ■ ■ ■ ■ ■ ■ ■ a •• ■o�❑�° Aga ❑❑ 8 j' �o °❑ -- :: ■ ■ ■ a It ❑m® ❑ J oe �Y '•• l� • • 74 .71 .. i' • sue'' .. � i�,• VVV�� ` �. c Vr PfR RW, ClwPHI —P Core Porosity _P • PHr_F 1.. Klf_- CleanPHe Ciea■( PF-3 High Quality Sandstone - «'Tlw 3,y� �: e yzts"ts ` y F j7c. � q PTU-15, 16208.2 ft Low ductile grain content. Primarily found in the northern wells. PTU-4, 14973.2 ft High ductile grain content. Primarily found in the southern portion of the field. Figure 12: Porosity v. permeability plot, colored by the six petrofacies. Petrofacies are primarily defined by grain size, sorting, cementation, and ductile grain content. Petrofacies were updated in 2011 based in part by results of the PTU-15 and PTU-16 wells. • Chart Area Q Quartz Arenite 5 Subarkose IN Sublitharenite 75 Lithic Feldspath Arkose Arkose Litharenite F R Figure 13: Ternary diagram showing the grain composition of Thomson sand. 0 EOD w/ petrofacies assemblages Lithofacies Description EOD open framework conglomeratic 35% PF2 WND 5% PF3 5% PF 1 Mainly conglomerate FS w/ minor sand 85%PF2 10°o PF3 2% PFt Mainly conglomerate 75%PF2 USF with increasing sand 20%PF3 3% PF4 20% PF2 Proximal 65% PF3 15% PF4 Mixed clean sand & LSF conglomerate 5'. PF2 5'. PF3 W. PF4 1V PF6 Gistal 35'. PF4 0 L Dirty sand & silt 65% PF6 F`_ 5% PF4 Sin OFS 95% PF6 Top Upper Thomson Petrofacies Top Lower Thomson Cleary Sand Silty Sand Cemented Brec Siitstone I Cemented Cara PTUu--" 7 C� Off Sh Trans DLSF PLSF USF Fore Sh IVAnnowed AI Fan i " < PTU-16 Depositional Environments off Sh Trans —AK--Pt DLSF PLSF USF Fore Sh- 5 � nrawFan PTU-16. Petrofacies Depositional Environments Figure 14: EOD chart with petrofacies assemblages. Maps show view from the top of the Upper and Lower Thomson for both petrofacies and EODs (from the geologic model). • opmFrameCon conglomerate �— clean Sand Silty Sand Cemented Brec PTU-17 Siltstone - � Petrofacies cemented c°N Figure 15: Wellbore cross section through the producer PTU-17 showing the estimated petrofacies to be penetrated NE SW �i Fore Sh Winrowed Al Fan Bsl Thom • 9 Section A -A' sw NE EOD sw PTU_15 ction B-B' NE Petrofacies sw NE EOD Legends EODs Off Sh Trams DLSF PLSF USF Fore Sh Winnowed AI Fan Bsl Thom Petrofacies u Figure 16: Cross sectional view through the injectors PTU-15 (A) , PTU-16 (B), with extractions of EODs and petrofacies 0 1 PTU-15 TTHOM ;on Irt FS Ut.1' ; TTHOM ion_Int_FS BTHOM PTU-16 Tracks: GR, tvdss, Environment of Deposition, Petrofacies, Perm Transform, Total Porosity PTU-17 +mast aaa xea ssr,�o ix �' ,� .c cvc EOD Top Tho RSF Facies son oa+�nsazx ,,agco Perm. PHIT t� I F--- i "` arr Mtemaflooding CNglOmaalr r, �Ongloma+oe Conq:pmery, surfs USF GonO-- ea�q:omase Figure 17: Extractions from the Geologic Model at Key Wells. Figures on left show the interpreted EOD and Petrofacies based on core description and log character. Permeability Transform is based on poro-perm transforms for each petrofacies (Figure 12). Figure on Right shows the expected EODs and petrofacies for the PTU-17 well as predicted by the geologic model. Legend for EOD and petrofacies found in Figure 16. • • top perf- > base perf� ND ft 12800 12M 13M 13100 PTU-16 20 40 60 80 feet 1.000 • 7 nnn N 3.000 V ,n 4.000 a R 5.000 c U 6.000 c R a 7.000 c P IL '710.000 8.081 misec Figure 18: Preliminary estimated fracture geometry for the PTU-16. Model shows a "low leak -off" case DR A AK-F 1 PTL 1-1 S AK -DI iJ015-3 A' PTU-16 nd - ., _ - - - - - - --ww rc •xm l 4 41 ! 77 Ij e � a Tracks: gamma ray, deep and shallow resistivity LwrCanningFm Hue/HRZShale Thomson Sand Pre -Miss Basement Figure 19: Structural cross section A -A' showing the overlying confining zones of the lower Canning Fm and Hue/HRZ shales, and underlying pre -Mississippian basement. Although the Hue/HRZ is severely eroded in Alaska D1, the lower Canning Fm provides the confining zone. Map shows the isochore thickness of Hue/HRZ shale becoming thinner to the northeast E • PTU-15 P PTU_15 [SSTVD] 17537 ftUS VSH SSTVD I MD DRIES RHOB PHIT VSH 0.00 1.09 122 11 - 1 &'.00� 0 0.50 R 03fl3 00 0.00 GR MRES NPHI CPOR GR 0 gAPI 300 - 0600oR ft300000 0.50 0.00 0 gAPI vs[af SIRES Color fill Color fill za»e,—.—.zaoo:ooa HCSFL'Rou�n Canning I'm j } 12500-�15OW-5 Hue/HRZ Shale i 12600 16110 12700116343,9 16226.8 Thomson 12800 12900 1 16461.3 Pre -Mississippian Basement Trackl: Gamma ray and VShale Track 2: Deep, medium, and shallow resistivity (0.2— 2000 ohm) Track 3: Density (Rhob, 1.65-2.65 g/cm3) and Neutron Porosity (0-0.60) Track 4: Total Porosity with core porosity points (0-0.50) PTU-16 PT U 16 SSTVD MD DRIESRHOB PHIT i i �—, �— . ' m z.00a aaw 7 6600 g/=3 2-6500 0.50 MM3 0.00 MIRES NPHI + CPOR zaoa onm mz.oao.oaaa 0.6000 ft3fft30.Dow 0.50 0.0( SIRES 7i 2-- z,o Oaaz,o Ooa 12600 4.16495.1 12700 16618.5 12800116990 16742.5 12900168669 13000.9 13100 -T- 17113 6 Figure 20: Petrophysical logs showing gamma ray, resistivity, density and neutron, and total porosity above and below the Thomson Sand. • •