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Home My WebLink AboutCO 725CONSERVATION ORDER 725 Docket Number: CO-16-007 Kuparuk River Unit Kuparuk River Field Kuparuk River -Torok Oil Pool North Slope Borough, Alaska 1. March 31, 2016 CPAI's request for Moraine Oil Pool rules 2. April 26, 2016 Notice of hearing, affidavit of publication, mailings, email distribution 3. May 10, 2016 Transcript, presentation, and sign -in sheet 4. May 24, 2016 CPAI's additional information 5. August 10, 2016 Request for reconsideration 6. September 1, 2016 Supplement information (CO 725.001) 7. March 31, 2017 Request for AA to remove requirement for an annual reservoir review meeting (CO 725.002) ORDERS aSTATE OF ALASKA • ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue Anchorage Alaska 99501 Re: THE APPLICATION OF ConocoPhillips Alaska, Inc. for an order for classification of a new oil pool and to prescribe pool rules for development of the proposed Moraine Oil Pool within the Kuparuk River Field, Kuparuk River Unit IT APPEARING THAT: Docket Number: CO-16-007 Conservation Order No. 725 Kuparuk River Unit Kuparuk River Field Kuparuk River -Torok Oil Pool North Slope Borough, Alaska July 22, 2016 1. By application received March 31, 2016, ConocoPhillips Alaska, Inc. (CPAI), as operator of the Kuparuk River Unit (KRU) and on behalf of the Working Interest Owners (WIOs), requested an order defining a new oil pool, the Moraine Oil Pool, within the KRU and prescribing rules governing the development and operation of that pool. 2. Pursuant to 20 AAC 25.540, the Alaska Oil and Gas Conservation Commission (AOGCC) scheduled a public hearing for May 10, 2016. On April 6, 2016, the AOGCC published notice of that hearing on the State of Alaska's Online Public Notice website and on the AOGCC's website, electronically transmitted the notice to all persons on the AOGCC's email distribution list and mailed printed copies of the notice to all persons on the AOGCC's mailing distribution list. No comments on the application were received. 4. The hearing commenced at 9:00 a.m. on May 10, 2016. Testimony was received from representatives of CPAI. The record was held open until May 24, 2016, to allow the operator to respond to requests made during the hearing. FINDINGS: Owners and Landowners: The State of Alaska is landowner for the planned Affected Area. (See Figure 1). WIOs include CPAI, BP Exploration (Alaska) Inc., Chevron USA Inc., and ExxonMobil Alaska Production Inc. CPAI verified by letter dated May 24, 2016 that the ownership and working interest percentage for oil and gas leases ADL 392374 and ADL 392371 are in alignment with the ownership and working interest percentage for those KRU oil and gas leases within the proposed Moraine Oil Pool boundary. The royalty interest for both ADL 392374 and ADL 392371 is 16.66667 percent. Royalty interest for the KRU oil and gas leases within the proposed Moraine Oil Pool ranges from 12.5 to 16.667 percent. O ep rator: CPAI is the operator of the leases in the proposed Affected Area, which is defined below. CO 725 • July 22, 2016 Page 2 of 15 W W 4yasW a 6060000F N N THETIS IS I Ni aitchuq Uni OOOGURUK 6040MOF N 1 • 04DDDOF N _ wR �J IK I 1 t ±Y (. .wwa va.�ssroo — •u.am � DSTJ6 ODST.39 KALUBIK 1 Ouruk Unit Y� t 9 ODsr-45 :"...:"'•KALI • Btl( 2. a »» 30 l ,/^I COLV DELIA2 I: ��•' �.omau / fI C~ �{� y; ". 602ODDOF 3O / t ODST-47 F OOOOF N NU4A1 .a 3N1 >i ,'f — N .na»ero NR r ]PBS/ -\.: I K '.._{ /•j_3S62D Kuparu River nit 600DOODFN %�, Yr�;-ram -+ 14` • �0i°10i 'ram""' .www .ameu� .nmFno 3) .nerJe. N 1 ,1 3H 3A MORMNE I: 3S Legend 95 0 `- ' I •a,»�o wa»ma .nos* u.nn... .a.��o: .mme» .a.ma.+ Coastline .............._._._..-_---...._.__ ��--� 313 Unit Boundary 0 1 z COLVILLE i Lease Boundary 598000OF N "0i®'61 ^� ^» Leases within AIO and N Pool area but outside KRU ® AID and Pool Area _...... ... ._........ ...... ... 2 Plac rr U 2T Drill Site Pads . ..... - w.».m »nk .naww wwsss .aa�e. 2X ro 22 59600WF N 2A' 2C 3 iu S Figure 1. Proposed Affected Area 3. Affected Area: As currently mapped, the planned Affected Area lies both onshore and offshore, North Slope, Alaska, within and outside the existing KRU. Two oil and gas leases, ADL 392374 and ADL 392371, are not presently within the KRU. CPAI plans to apply to the Department of Natural Resources, Division of Oil and Gas (DNR) for KRU expansion to include these two additional leases. CPAI's proposed Moraine Oil Pool will be developed initially from the existing onshore 3S Drill Site. Upon successful development of the pool from 3S Drill Site, additional drill sites may be constructed for further development. 4. Exploration and Delineation History: Moraine is an informal, local name applied by CPAI to turbidite sandstones within the Torok Formation (Torok) that were deposited in a lower slope -to - basin floor environment. The Torok reservoir was first penetrated in 1966 by the Sinclair Oil and Gas Colville No. 1 exploratory well in Section 25, Township 12 North, Range 7 East, Umiat Meridian (U.M.). In 1985 and 1986, Texaco Inc. drilled and tested the Colville Delta No. 2 and CO 725 July 22, 2016 Page 3 of 15 No. 3 exploratory wells. Initial, unstimulated drill -stem testing of the Torok turbidite sands in both wells yielded less than 50 BOPD oil production rates. Subsequent fracture stimulation of the Colville Delta No. 3 resulted in an average flow rate of 240 barrels per day of a crude oil and diesel mixture over a combined 84 hour test period. Oil gravity was reported to be 24.6° API.' ARCO Alaska, Inc. drilled the Kalubik No. 1 and Kalubik No. 2, in 1992 and 1998 respectively, to evaluate the turbidite sandstones within the Torok Formation. An unstimulated flow test of the Kalubik No. 1 yielded an average rate of 10 barrels of oil per day (BOPD).2 In 2010-2012, three production wells within the Oooguruk Unit—ODST-39, ODST-45A and ODST-46—were drilled and completed within the Torok turbidite sands. Conservation Order No. 645, dated May 26, 2011, defines the Oooguruk-Torok Oil Pool and prescribes rules governing the development and operation of that pool within the Oooguruk Unit. In 2012, Pioneer Natural Resources Alaska, Inc. (Pioneer) drilled the onshore Nuna No. 1 exploratory well to further delineate the Torok reservoir within the Oooguruk Unit. The bottomhole location for Nuna No. 1 is approximately one-half mile north of Colville Delta No. 3 and less than 3 miles from the bottomhole location for the recently drilled KRU 3S-620 Torok producer well. Nuna No. 1 tested an average flow rate of 1,524 BOPD, 240 API.3 In 2013, CPAI fracture stimulated the upper portion of the Torok (upper Moraine) turbidite sequence within the KRU 3S-19 well and obtained flow rates of 250 to 300 BOPD. Subsequently, in 2015, CPAI drilled and fracture stimulated horizontal well KRU 3S-620, which has a 4,200-foot section open to these turbidite sands. Initial production rate was 1,575 BOPD with 75 percent water cut. 5. Pool Identification: CPAI proposes that the Moraine Oil Pool be defined as the accumulation of hydrocarbons common to, and correlating with, the interval between 5,630 and 6,043 feet measured depth (MD) on the gamma ray log recorded in the Palm No. 1 exploratory well. (See Figure 2). CPAI divides the proposed pool into two informal members. In the Palm No. 1, the upper Moraine lies between 5,630 to 5,805 feet MD; whereas the lower Moraine lies between 5,805 and 6,043 feet MD. 1 Texaco Inc., 1986, Colville Delta No. 3 Well Testing Summary -Torok Zone, DST #2, in AOGCC Well History File No. 185-211. 2 ARCO Alaska, Inc., 1992, Formation Tests - Kalubik #1, in AOGCC Well History File No. 192-013. 3 Pioneer Natural Resources Alaska, Inc., 2012, Expro Nuna #1 Final Well Test Report, in AOGCC Well History File No. 211-155. CO 725 July 22, 2016 Page 4 of 15 The Affected Area for CPAI's proposed Moraine Oil Pool lies east and southeast of, and adjacent to, the Affected Area for the Oooguruk-Torok Oil Pool, which is operated by Caelus Natural Resources Alaska, LLC (Caelus). Conservation Order No. 645 defines the Oooguruk-Torok Oil Pool as the accumulation of hydrocarbons common to, and ResuDAy Shal._ OHMM 100 NSWa, Poros Rembvity Med. 60 PU 0 7V066 (R) MD (4) _ Dens 1 OHMM 100 Gamma Ray 1 m0 ReSmNr Dee 1 65 G/C3 2 65 Member Formation 0 GAPI 200 1 OHMM 100 5050 5550 5100 5600 56301, A,(: 5150 5650 0) C 5200 5700 O O v O d 5250 5750 Q O a 5800 5300 O -... F d 5850 5350 N 5900 O 5400 5950 i' Si 3 ' O 5450 6000 J - 6050 r>rx-• rv. 5500 - N 6,00 5550 6150 T y 5600 { < i Figure 2. Palm No. 1 Proposed Moraine Oil Pool correlating with, the interval between 4,991 and 5,272 feet MD on the resistivity well log recorded in exploratory well Kalubik No. 1. CO 725 • July 22, 2016 Page 5 of 15 Geology: a. Stratigraphy: CPAI's proposed Moraine Oil Pool consists of lower Cretaceous -aged, Brookian slope -to - basin turbidite deposits comprised of thinly laminated mudstones, siltstones and very fine to fine-grained sandstones. The proposed oil pool is informally divided into two members: the younger, upper Moraine with higher sand concentrations and the older, lower Moraine. The proposed pool varies in thickness from 60 to 640 feet, but thins towards the southeast and southwest and pinches out to the west against the paleo-shelf. The sandstone and siltstone beds are interpreted to be locally continuous, sheet -like deposits within turbidite lobe complexes. Individual beds range in thickness from less than an inch to a few feet. The sandstones comprise 50 to 70 percent quartz, 1 to10 percent feldspar, and 15 to 30 percent lithic fragments. Porosity values from core data range from 15 to 28 percent and average 19 percent. Air permeability values range from 0.5 to 93 millidarcies and average 5 millidarcies. Water saturation estimates for the reservoir siltstones and sandstones range from 30 to 85 percent. b. Structure: The structure of the proposed pool forms a broad, east -plunging anticlinal nose. Two dominant sets of normal faults are present in the proposed development area: an early Cretaceous -aged, west -northwest -trending system and a younger, Cenozoic -aged, north- northeast -striking set. Vertical displacement along these faults may range as much as 60 feet and, due to the thinly bedded nature of the reservoir, faults may act as barriers to flow. Structurally, within the proposed Affected Area, CPAI's informal upper Moraine member ranges in depth between -4,940 and -5,880 feet true vertical depth subsea (TVDss), and the lower Moraine ranges in depth from -5,240 and -5,920 feet TVDss. c. Trap Configuration and Seals: Well log and seismic information indicate that the proposed pool accumulation is trapped by both structural and stratigraphic elements. The sandstones that comprise the pool thin toward the west and pinch out as they lap onto the shelf slope. Much of the trap is stratigraphic, with a structural component from the broad anticline. To the south and southwest, the depositional limit of the fan defines the pool boundary. To the east and northeast structural dip and diminishing sand content define the limit of the oil accumulation. Progradational slope deposits consisting of Torok mudstones and siltstones provide the top seal for the proposed pool. Total thickness varies from about 250 feet to over 1,000 feet. CPAI defines the base of the proposed Moraine Oil Pool by the top of the HRZ Formation. d. Reservoir Compartmentalization: At present, extended production test results of both KRU 3S-19 and KRU 3S-620 are consistent with laterally continuous productive sands within the upper Moraine over development well spacing distances of 1,000 to 2,000 feet. Compartmentalization is possible due to faulting and the highly laminated nature of the reservoir. All wells, including injectors, will likely be fracture stimulated to enhance productivity, improve vertical injection sweep, and connect thin, individual sandstone beds. e. Permafrost Base: The base of the permafrost is interpreted to lie between -500 and -1,700 feet TVDss within the proposed development area. 7. Reservoir Fluid Contacts: Regional Reservoir Description Tool data were used by CPAI to delineate fluid contacts. The water zone contact is controlled by the Ivik 1 exploratory well, CO 725 July 22, 2016 Page 6 of 15 which is located within the Oooguruk Unit, and the oil zone contact is controlled by the Moraine 1 well, which is located within the Kuparuk River Unit. According to evidence provided on April 26, 2011 by Pioneer Natural Resources Alaska, Inc. (predecessor to current Oooguruk Unit operator Caelus), the highest known water for the pool is established by MDT (modular formation dynamics tester) measurements in the Ivik 1 exploratory well at -5,212 feet TVDss. CPAI estimates the oil -water -contact (OWC) between -5,190 and -5,275 feet TVDss. CPAI testified that there is mobile water present in the Moraine Oil Pool beginning at a depth of -5,190 to -5,275 TVDss. This may take the form of a single OWC, multiple OWCs, or a transition zone of mobile oil and water. Reservoir Fluid Properties 0,000 feet TVDss Datum): Initial reservoir pressure Reservoir temperature Gas -oil ratio API gravity Bubble point pressure Oil formation volume factor Oil viscosity Gas formation volume factor OWC 2,263 psig 1350 F 425 scf/bbl 26.50 F 2,134 psig 1.2 rb/stbo 2.5 cp 1.2 bbl/mscf (at saturation pressure) estimated between -5,190 and -5,275 feet TVDss 9. Relationship to a Previously Defined Oil Pool: Under AS 31.05.170(12), the term "pool" means an underground reservoir containing, or appearing to contain, a common accumulation of oil or gas. Based on testimony presented by CPAI, the upper portion of the proposed Moraine Oil Pool —as referenced on the Palm No. 1 log from 5,630 feet to 5,805 feet MD —is equivalent to, an extension of, and contiguous with, the Oooguruk-Torok Oil Pool in the adjacent Oooguruk Unit, which is operated by Caelus. Conservation Order No. 645, dated May 26, 2011, defines the Oooguruk-Torok Oil Pool as the accumulation of hydrocarbons common to, and correlating with, the interval between 4,991 and 5,272 feet MD on the resistivity well log recorded in exploratory well Kalubik No. 1. According to Conservation Order No. 645, initial reservoir pressure for the Oooguruk-Torok Oil Pool was 2,250 psi at a depth of -5,000 feet TVDss. The oil accumulation defined by the above wells lies within the upper Moraine interval as identified by CPAI. At the public hearing, CPAI testified that the hydrocarbon potential of the lower Moraine interval, as referenced on the Palm No. 1 log from 5,805 to 6,043 feet MD, is still being evaluated. 10. In -Place and Recoverable Oil Volumes: Hydrocarbon Resources Estimated Volume (MMSTB) Original Oil in Place (OOIP) Primary Recovery (5% OOIP) Primary + Waterflood (10-40% OOIP) Drill Site 3SAdditional Drill Site 100-500 5-25 10-200 100-300 5-15 10-120 Regular production of the proposed Moraine Oil Pool within the Kuparuk River Unit began in 2013 from KRU 3S-19, and has been reported in AOGCC records as the Kuparuk River Torok Undefined Oil Pool. CO 725 • July 22, 2016 Page 7 of 15 11. Reservoir Development Drilling Plan: CPAI currently plans to develop this oil reservoir in discrete phases, with the initial development phase from 3S Drill Site utilizing 10 to 40 horizontal production and injection wells. Most wells will trend northwest, along the maximum principal stress direction, to improve water flood performance. Wells will be arranged end -to -end to form alternating rows of producers and injectors in a line -drive flood pattern. Well spacing will range from 1,000 to 2,500 feet. The in -zone or horizontal production intervals of the wells will range in length from 3,000 to 8,000 feet. Fracture stimulation is planned for all injectors and producers. 12. Reservoir Management: CPAI plans to develop the reservoir as a water- and water -alternating - gas -injection enhanced oil recovery project. Production and injection voidage will be balanced to maintain reservoir pressure at or near the original measured pressure. Development will target a 1.0 voidage replacement ratio. Injection water will consist of produced water and water from the Kuparuk seawater treatment plant. 13. Reservoir Surveillance Plans: CPAI proposes to meet bottom -hole pressure survey requirements through the following reservoir pressure monitoring plan: a. Static bottom -hole pressure surveys will be conducted in all new injection wells prior to initiating injection. b. Static bottom -hole surveys may be performed on production wells at the discretion of CPAI. c. For annual pressure surveillance, a minimum of one pressure survey will be conducted annually in the oil pool, concentrating on injection wells. d. Since lengthy horizontal wells require extended shut-in periods to achieve stabilized bottom - hole pressures, CPAI proposes the following alternative pressure survey methods: i. Open -hole wireline formation fluid pressure measurements, ii. Cased hole pressure buildups with bottom -hole pressure measurement, iii. Injector surface pressure fall -off, static pressure surveys following extended shut-in periods, or iv. Bottom -hole pressures calculated from wellhead pressure and fluid levels in the tubing of a stabilized shut-in injector. Pressures will be referenced to a datum of -5,000 feet TVDss. All pressure surveys will be reported annually. 14. Wellbore Construction: Within the planned development area, the base of permafrost is interpreted to be between -500 and -1,700 feet TVDss. Surface casing will be set below the West Sak reservoir and cemented to the surface. Intermediate casing will be set and cemented with the shoe in the target formation. Leak -off or formation integrity tests will be conducted, and significant hydrocarbon zones in the boreholes outside of the reservoir intervals will be isolated in conformance with AOGCC regulations. CPAI expects to develop the reservoir using horizontal wells with solid liners including pre - perforated pups and/or sliding sleeves and external swell packers to facilitate staged hydraulic fracture stimulation treatments. Both injection and production wells will likely be completed with 4-'/2 inch tubing to facilitate fracture stimulation. Uncemented slotted liners are included in the drilling plans on an "as -needed" basis. Current development utilizes gas lift as the artificial lift mechanism to produce; however, several different techniques, e.g., jet pumps or electrical submersible pumps, may be employed to optimize reservoir pressure drawdown, provide lift for long reach horizontal wells, and enhance production rates at anticipated increased water cuts. 15. Waivers: CPAI requested the following waivers: CO 725 • July 22, 2016 Page 8 of 15 a. Well Spacing: Spacing restrictions of 20 AAC 25.055 be waived for development wells in the proposed Moraine Oil Pool to accommodate horizontal, line -drive wells and maximize ultimate recovery. Without prior approval, development wells will not be completed any closer than 500 feet to an external boundary where ownership and/or landownership changes. b. Directional Wellbore Plans: In lieu of the requirements of 20 AAC 25.050(b), permit to drill application(s) shall include: plan view, vertical section, close approach data, and directional data. c. Petrophysical Logging: In lieu of the requirements of 20 AAC 25.071(a), that only one well per drill site be required to be logged for the portion of the well below the conductor pipe by either a complete electrical log or a complete radio -activity log, unless the AOGCC specifies which type of log is to be run. d. Gas -Oil Ratio Exemption: an exemption from the GOR limits of 20 AAC 25.240 to accommodate water -alternating -gas -injection for oil recovery. e. Well Work Operations: adoption of the "Well Work Operations and Sundry Notice/Reporting Requirements for Pools Subject to Sundry Waiver Rules — July 29, 2005" matrix, which applies to operations in all other KRU pools, for the proposed Moraine Oil Pool. f. Well Testing Frequency: a waiver of the testing requirements of 20 AAC 25.230(a) after the first 12 months of operation to allow for production tests to occur at least every three months. 16. Metering and Measurement Processes: Well testing and allocation will be conducted with equipment (i.e. a well test manifold to divert production from a given well to a well testing separator) and procedures used throughout the KRU. In the future multiphase metering may be installed to measure production from each well. CONCLUSIONS: l . Pool Rules are appropriate for CPAI's development of the proposed Moraine Oil Pool within the Kuparuk River Unit. 2. Well log correlation demonstrates that the interval between 5,630 and 5,805 feet MD in Palm No. 1—within the upper portion of CPAI's proposed Moraine Oil Pool —is equivalent to 4,991 and 5,272 feet MD in exploratory well Kalubik No. 1, which is defined in Conservation Order No. 645 as the Oooguruk-Torok Oil Pool. 3. The adjacent locations and nearly identical reservoir pressure values for the Oooguruk-Torok Oil Pool and CPAI's proposed Moraine Oil Pool (2,250 psi versus 2,263 psi at -5,000' TVDss, respectively) suggest the oil accumulation is common. 4. For naming consistency, to emphasize continuity of the accumulation across lease and unit boundaries, and to conform to the definition of the term "pool" under AS 31.05.170(12), the name Kuparuk River -Torok Oil Pool should be applied to this pool in lieu of CPAI's proposed name "Moraine Oil Pool". 5. Any acreage where Torok reservoir rock lies structurally below the estimated oil -water contact for the Kuparuk River -Torok Oil Pool should not be included within the defined pool as it does not comport with the definition of "pool" under AS 31.05.170(12) (reference CPAI's Upper Moraine Depth Surface Structure Map in the March 31, 2016 application). 6. The Kuparuk River -Torok Oil Pool is likely compartmentalized due to faulting and the highly laminated nature of the reservoir. Development requires unrestricted well spacing to optimize waterflood efficiency and ultimate resource recovery. Eliminating spacing restrictions on CO 725 • July 22, 2016 Page 9 of 15 wellbores within the Affected Area will increase the operator's flexibility in placing wells as the pool is developed and will not affect recovery, promote waste, jeopardize correlative rights, or result in an increased risk of fluid movement into freshwater aquifers. 7. Correlative rights of owners and landowners of offset acreage will be protected by a 500-foot set- back requirement from a property line where ownership changes hands. S. Water and water -alternating -gas injection into the Kuparuk River -Torok Oil Pool will preserve reservoir energy and increase ultimate recovery. 9. Adherence to the requirements of 20 AAC 25.071(a) would not significantly add to the geologic knowledge of the area, as long as one well drilled from each drill site is mud logged and logged with a complete suite of wireline or logging -while -drilling tools from the base of conductor through the Kuparuk River -Torok Oil Pool. 10. Annular pressure management is necessary to prevent failure of well integrity and uncontrolled release of fluids or pressure and to minimize threats to human safety and the environment. 11. Filing the proposed submittals, rather than those required by 20 AAC 25.050(b), will ensure equally accurate surveillance of the wellbore to prevent well intersection, compliance with spacing requirements, and protection of correlative rights. 12. A gas -oil ratio (GOR) limitation waiver is appropriate because the Kuparuk River -Torok Oil Pool will be developed as a waterflood and water -alternating -gas enhanced recovery project. Once pressure maintenance operations commence, GORs should not exceed the limits imposed by 20 AAC 25.240(a). However, before the pressure maintenance operations commence, injectors will be pre -produced to ensure adequate reservoir voidage to accommodate water injection. During this period there may be wells that exceed the GOR limits. 13. With regard to acceptable production allocation, insufficient data has been presented to support any change in the monthly production report requirement. 14. The remainder of CPAI's proposed production and fiscal allocation methodology is consistent with the methodology employed for the Kuparuk River Field, Kuparuk River Oil Pool. NOW THEREFORE IT IS ORDERED: The development and operation of the Kuparuk River -Torok Oil Pool is subject to the following rules and the statewide requirements under 20 AAC 25 to the extent not superseded by these rules: CO 725 • July 22, 2016 Page 10 of 15 Affected Area: Umiat Meridian (See Figure 3, below.) Township 11 North, Range 8 East Sections 1-4, 9-12: All Township 12 North, Range 7 East Sections 1-2: All Sections 11-14: All Sections 23-26: All Sections 35-36: All Township 12 North, Range 8 East Sections 2-11, 13-36: All Township 13 North, Range 8 East Sectionsl9-21, 28-34: All Rule 1 Field and Pool Name The field is the Kuparuk River Field. Hydrocarbons underlying the Affected Area and within the interval identified in Rule 2, below, constitute the Kuparuk River -Torok Oil Pool. Rule 2 Pool Definition The Kuparuk River -Torok Oil Pool is defined as the accumulation of oil and gas common to and correlating with the interval within the Kalubik No. 1 well between the measured depths of 4,991 and 5,272 feet on the resistivity log recorded in exploratory well Kalubik No. 1. (See Figure 4, below.) Rule 3 Well Spacing There shall be no restrictions as to well spacing except that no pay shall be opened to a well within 500 feet of an external property line where the owners and landowners are not the same on both sides of the line. Rule 4 Drilling Waivers All permit to drill applications for deviated wells within the Kuparuk River -Torok Oil Pool shall include a plat with a plan view, vertical section, close approach data and a directional program description in lieu of the requirements of 20 AAC 25.050(b). Rule 5 Well Logging and Sampling Requirements a. A suite of petrophysical well logs including, at a minimum, gamma ray, resistivity, neutron porosity, and density porosity logs shall be acquired across the Kuparuk River -Torok Oil Pool in one well from each drill site. A gamma ray curve shall be recorded from base of conductor to total depth in each well. The AOGCC may require additional wells to be logged using one or more petrophysical logging tools. b. A mud log and cutting samples shall be obtained from the base of the conductor through the Kuparuk River -Torok Oil Pool in at least one well drilled from each drill site. CO 725 • July 22, 2016 Page 11 of 15 G �X X i _ TMET1$ IS i Nikaitchuq Unit • 60/00002 ti� � � . �••• �� - bOdUQOOF N ♦a r r5. ♦. xrw � w.w... .¢ ti Lai �00.51 : 7.39 KALUDW 1 ♦ n R Odbg&ruk Unit r. 36, i •rr 20000E N 74 / �f COZY DELTA 3 r i ,i NtlNA 7P•1 ; S ai K r , Kuparuk River lnit �y _ k 35ib0 • 3 a >> r f • �3A 3524 F•un.: , � • ' y�` Legend <_ I 1 S 315 Unit BaxWazy f ��-r CGL ILLS 1 - L1858 Boundary s9a000aF twss .a 1K�� +[aunn .w+'w++ Leases YAU%n ANi and PW area W Ouis4e KRU -- ------ aI NO d POO Area - � I. MARU2 .------------ - M•t Ulilt • 2T Drip 5re Pads 2K I EiE ID _ Figure 3. Kuparuk River -Torok Oil Pool Affected Area Rule 6 Reservoir Pressure Monitoring a. A bottom -hole pressure survey shall be taken on each well prior to initial production or injection. b. The operator shall obtain the pressure surveys needed to manage properly the hydrocarbon recovery processes subject to the annual plan outlined in Rule 9, below. At a minimum a pressure survey shall be acquired from at least one well on each drill site each year. c. The reservoir pressure datum will be-5,000' TVDss. CO 725 • July 22, 2016 Page 12 of 15 Kuparuk River - Torok Oil Pool Correlation Depth Resis Porosoy GR <MD R.esD(RILD) RH06 10 API 240 D.2 OHMM 200 .65 GMXC 2 65; and - Sdt - Shale TVDSS> ResM(RILM) ow Por 2 OHMM 200 SP TVD ResS(RFOC) NPOR _ 100 _ ,.IV 10 .2 OHMM 200150 01 <M p _ DTCP(DT) 70 USfT 701 4800 4800 -4800 f 4900 4900 -4900 _ 5000 -5000 5100 f -5100 — - 5200 5200 �f -5200 ZXI 5300 5300 -5300 5400 5400 -5400'— ! 5500 5500 5500 } Figure 4. Kalubik No. 1—Type Well Log for Kuparuk River -Torok Oil Poo14 4 Figure 4 is presented for illustration purposes only. Refer to the well log measurements recorded in exploratory well Kalubik No. 1 for the precise representation of the Kuparuk-Torok Oil Pool. CO 725 July 22, 2016 Page 13 of 15 d. Pressure surveys may consist of stabilized static pressure measurements at bottom -hole or be extrapolated from surface measurements (single phase fluid conditions), pressure fall -off measurements, pressure buildup measurements, multi -rate test results, drill stem test results, and open -hole formation tests or other methods approved by the AOGCC. e. A Reservoir Pressure Report, Form 10-412, shall be utilized for all surveys; all relevant data shall be attached to the report. The data submitted shall include, at a minimum, rate, pressure, depth, fluid gradient, temperature, and all other well conditions necessary for a complete analysis of each survey being conducted. f. The results and data from any special reservoir pressure monitoring tests or surveys shall also be submitted in accordance with paragraph (e) of this rule. Rule 7 Gas -Oil Ratio Exemption Wells producing from the Kuparuk River -Torok Oil Pool are exempt from the Gas -Oil Ratio limits of 20 AAC 25.240(a) as long as CPAI is engaged in enhanced recovery operations. An enhanced recovery operation must be initiated within 12 months of the issuance of this order. Rule 8 Annual Reservoir Review a. An annual reservoir surveillance report must be filed by April 1 st of each year and include future development plans, reservoir depletion plans, and surveillance information for the prior calendar year, including: i. The voidage balance, by month, of produced fluids and injected fluids and the cumulative status for each producing interval; ii. A reservoir pressure map at datum, and a summary and analysis of the reservoir pressure surveys within the pool; iii. The results and, where appropriate, an analysis of production and injection log surveys, tracer surveys, observation well surveys, and any other special monitoring; iv. A review of pool production allocation factors and issues over the prior year; V. A review of the progress of the enhanced recovery project; and vi. A reservoir management summary, including results of any reservoir simulation studies. b. By June 1" of each year, the operator shall schedule and conduct a technical review meeting with the AOGCC to discuss the annual reservoir surveillance report and items that may require action within the coming year. Rule 9 Annular Pressures a. At the time of installation or replacement, the operator shall conduct and document a pressure test of tubulars and completion equipment in each development well that is sufficient to demonstrate that planned well operations will not result in failure of well integrity, uncontrolled release of fluid or pressure, or threat to human safety. b. The operator shall monitor each development well daily to check for sustained pressure, except if prevented by extreme weather conditions, emergency situations, or unavoidable circumstances. Monitoring results shall be kept available for AOGCC inspections. c. The operator shall notify the AOGCC within three working days after the operator identifies a well as having (i)sustained inner annulus pressure that exceeds 2,000 psig for all development wells, or (ii) sustained outer annulus pressure that exceeds 1,000 psig. d. The operator shall submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action or increased surveillance for any development well having sustained pressure that exceeds a limit set out in paragraph (c) of this rule. The AOGCC may approve the operator's CO 725 • July 22, 2016 Page 14 of 15 proposal or require other actions or surveillance, including a mechanical integrity test or other approved diagnostic tests. The operator shall give sufficient notice of the testing schedule to allow the AOGCC to witness the test. e. If the operator identifies sustained pressure in the inner annulus of a development well that exceeds 45 percent of the burst pressure rating of the well's production casing for inner annulus pressure, or sustained pressure in the outer annulus that exceeds 45 percent of the burst pressure rating of the well's surface casing for outer annulus pressure, the operator shall notify the AOGCC within three working days and take corrective action. Unless well conditions require the operator to take emergency corrective action before AOGCC approval can be obtained, the operator shall submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action. The AOGCC may approve the operator's proposal or require other corrective action, including a mechanical integrity test or other diagnostic tests. The operator shall give the AOGCC sufficient notice of the testing schedule to allow the AOGCC to witness the tests. Except as otherwise approved by the Commission under (d) or (e) of this rule, before a shut-in well is placed in service, any annulus pressure must be relieved to a sufficient degree (1) that the inner annulus pressure at operating temperature will be below 2,000 psig, and (2) that the outer annulus pressure at operating temperature will be below 1,000 psig. A well subject to (c) but not (e) of this rule may reach an annulus pressure at operating temperature that is described in the operator's notification to the AOGCC under (c) of this rule, unless the AOGCC prescribes a different limit. g. For purposes of this rule, i. "inner annulus" means the space in a well between tubing and production casing; ii. "outer annulus" means the space in a well between production casing and surface casing; and M. "sustained pressure" means pressure that (A) is measurable at the casing head of an annulus, (B) is not caused solely by temperature fluctuations, and (C) has not been applied intentionally. Rule 10 Production Surface Commingling, Measurement and Allocation a. Production from Kuparuk River —Torok Oil Pool may be commingled on the surface with production from the other pools within the KRU as well as with production from the Oooguruk Unit. b. Wells must be tested at least monthly until such time that the operator can demonstrate to the AOGCC's satisfaction that less frequent well testing will provide for equally accurate production allocation. c. A minimum of 12 months of production and well testing must occur from a given well before the operator can seek reduction of testing frequency for that well. Rule 11 Well Work Operations The provisions of Conservation Order 261A apply to the Kuparuk River -Torok Oil Pool. Rule 12 Administrative Action Upon proper application, or its own motion, and unless notice and public hearing are otherwise required, the Commission my 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 aquifers. CO 725 • July 22, 2016 Page 15 of 15 This order shall expire if ConocoPhillips Alaska Inc. ceases to be the Designated Operator for the Kuparuk River Unit or five years after the effective date shown below, whichever occurs first. DONE at Anchorage, Alaska and dated July 22, 2016. Cathy P oers er Daniel T. Seafnount, Jr. Chair, Itommissioner Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. • Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Friday, July 22, 201611:21 AM 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)'; 'Bixby, Brian D (DOA)'; 'Brooks, Phoebe L (DOA) (phoebe.brooks@alaska.gov)'; Carlisle, Samantha J (DOA); 'Colombie, Jody J (DOA) Oody.colombie@alaska.gov)'; 'Cook, Guy D (DOA)'; 'Davies, Stephen F (DOA) (steve.davies@alaska.gov)'; Eaton, Loraine E (DOA); Toerster, Catherine P (DOA) (cathy.foerster@alaska.gov)'; Trystacky, 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)'; 'Hollis French'; 'Jones, Jeffery B (DOA) (Jeff Jones@alaska.gov)'; Kair, Michael N (DOA); 'Link, Liz M (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.paladijczuk@alaska.gov)'; 'Pasqual, Maria (DOA) (maria.pasqual@alaska.gov)'; 'Quick, Michael (DOA sponsored)'; 'Regg, James 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.waIlace@alaska.gov)'; 'AKDCWellIntegrityCoordinator'; 'Alan Bailey'; 'Alex Demarban'; 'Alexander Bridge'; 'Allen Huckabay'; 'Andrew VanderJack'; 'Anna Raff'; 'Barbara F Fullmer'; 'bbritch'; 'Becky Bohrer'; 'Bill Bredar'; 'Bob Shavelson'; 'Brian Havelock'; 'Bruce Webb'; Burdick, John D (DNR); 'Caleb Conrad'; 'Candi English'; 'Colleen Miller; 'Crandall, Krissell'; 'D Lawrence'; 'Dale Hoffman'; 'Dave Harbour'; 'David Boelens'; 'David Duffy'; 'David House'; 'David McCaleb'; 'David Tetta'; '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'; 'Gordon Pospisil'; Greeley, Destin M (DOR); 'Gregg Nady'; 'gspfoff'; Hyun, James 1 (DNR); 'Jacki Rose'; 'Jdarlington Oarlington@gmail.com)'; 'Jeanne McPherren'; 'Jerry Hodgden'; 'Jerry McCutcheon'; 'Jim Watt'; 'Jim White'; 'Joe Lastufka'; 'Joe Nicks'; 'John Easton'; 'Jon Goltz'; 'Juanita Lovett'; 'Judy Stanek'; 'Julie Little'; 'Kari Moriarty'; 'Kazeem Adegbola'; 'Keith Torrance'; 'Keith Wiles'; 'Kelly Sperback'; 'Laura Silliphant (laura.gregersen@alaska.gov)'; 'Leslie Smith'; 'Louisiana Cutler'; 'Luke Keller'; 'Marc Kovak'; 'Mark Dalton'; 'Mark Hanley (mark.hanley@anadarko.com)'; 'Mark Landt'; 'Mark Wedman'; 'Marguerite kremer (meg.kremer@alaska.gov)'; 'Mary Cocklan-Vendl'; 'Mealear Tauch'; 'Michael Calkins'; 'Michael Moora'; 'MJ Loveland'; 'mkm7200'; 'Morones, Mark P (DNR)'; Munisteri, Islin W M (DNR); 'nelson'; 'Nichole Saunders'; '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'; 'Richard Cool'; 'Robert Brelsford'; 'Ryan Tunseth'; 'Sara Leverette'; 'Scott Griffith'; 'Shannon Donnelly; 'Sharmaine Copeland'; 'Sharon Yarawsky'; Shellenbaum, Diane P (DNR); Skutca, Joseph E (DNR); 'Smart Energy Universe'; Smith, Kyle S (DNR); 'Stephanie Klemmer'; 'Stephen Hennigan'; 'Steve Moothart (steve.moothart@alaska.gov)'; 'Steve Quinn'; 'Suzanne Gibson'; 'Tamera Sheffield'; 'Ted Kramer'; 'Temple Davidson'; 'Teresa Imm'; Thor Cutler, 'Tim Mayers'; Todd Durkee; trmjrl; 'Tyler Senden'; Vicki Irwin; Vinnie Catalano; '/o=SOA/ou=First Administrative Group/cn=Recipients/cn=kjking'; 'Aaron Gluzman'; 'Aaron Sorrell'; Ajibola Adeyeye; Alan Dennis; Anne Hillman; Assmann, Aaron A; Bajsarowicz, Caroline J; Brian Gross; 'Bruce Williams'; Bruno, Jeff J (DNR); Casey Sullivan; 'Don Shaw'; Eric Lidji; Garrett Haag; 'Graham Smith'; Hak Dickenson; Heusser, To: Heather A (DNR); Holly Pearen; Jamie M. Long; 'Jason Bergerson'; 'Jim Magill'; Joe Longo; John Martineck; Josh Kindred; Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; 'Marie Steele'; Matt Armstrong; 'Mike Franger'; Morgan, Kirk A (DNR); Pat Galvin; 'Pete Dickinson'; Peter Contreras; Richard Garrard; Richmond, Diane M; Robert Province; 'Ryan Daniel'; 'Sandra Lemke'; 'Susan Pollard'; Talib Syed; Tina Grovier (tmgrovier@stoel.com); Tostevin, Breck C (LAW); 'Wayne Wooster'; 'William Van Dyke' Subject: CO 725 and AIO 39 Attachments: aio 39.pdf, co 725.pdf Please see attached. Docket Number: AIO-16-011 Area Injection Order No. 39 Kuparuk River Unit Kuparuk River Field Kuparuk River -Torok Oil Pool North Slope Borough, Alaska Docket Number: CO-16-007 Conservation Order No. 725 Kuparuk River Unit Kuparuk River Field Kuparuk River -Torok Oil Pool North Slope Borough, Alaska Jody J. COlomllle _AO(i('C Special _Assistant .Alaska Oil and (jas Conservation Commission 333 West 7"' Avenue .Anchorage, .Alaska .9,95c17 Office: (g07) 793-1221 Jfax: (g07) 276-7542 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 Jody Colombie at 907.793.1221 or iody.colombie@alaska.gov. • • Jack Hakkila P.O. Box 190083 Anchorage, AK 99519 Penny Vadla 399 W. Riverview Ave. Soldotna, AK 99669-7714 Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Kazeem Adegbola Manager, GKA Development Richard Wagner North Slope Operations and Development P.O. Box 60868 ConocoPhillips Alaska, Inc. Fairbanks, AK 99706 ATO-1326 700 G St. Anchorage, AK 99501 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 0 s*� Angela K. Singh • THE STATE 'ALASKA GOVERNOR BILL WALKER • Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL CONSERVATION ORDER NO. 725.001 Kazeem A. Adegbola Manager, GKA Development North Slope Operations and Development ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Re: Docket No. CO-16-007 Docket No. AIO-16-011 Request for Reconsideration of Conservation Order No. 725 and Area Injection Order No. 39, Kuparuk River -Torok Oil Pool Dear Mr. Adegbola: By letters dated August 10, 2016, and September 1, 2016, ConocoPhillips Alaska, Inc. (CPAI) requested the Alaska Oil and Gas Conservation Commission (AOGCC) to reconsider Conservation Order (CO) 725 and Area Injection Order (AIO) 39, both entered July 22, 2016. A request for reconsideration is timely if filed within 20 days of issuance of the order. However, AOGCC can extend that time for good cause; CPAI's August 10, 2016 request is timely filed. CPAI's September 1, 2016 request, filed after the 20-day period, is focused on one specific issue, the AOGCC's use of the phrase "regular production." At the time of both CPAI's applications for pool rules and an area injection order and the hearing on those applications, the issue of whether production was considered regular had little significance. On June 28, 2016, House Bill 247 was signed into law, and will become effective on January 1, 2017. Under the language of House Bill 247, the date when regular production commences has significant tax consequences. CPAI contends that the change in the law, and its concomitant tax consequences constitute "good cause" to reconsider the wording of the order. The AOGCC agrees and will rule on both of CPAI's motions. CPAI's requests are addressed in order. CPAI first requests reconsideration of the expiration clauses (CO 725 has an expiration clause; AIO 39 has an expiration date rule [Rule 12]; collectively they are referred to by the phrase expiration clause) in each order. CPAI objects to the inclusion of the expiration clause in each order and requests they be removed. Docket No. CO-16-007 • • Docket No. AI0-16-011 September 15, 2016 Page 2 of 3 The expiration clauses will remain in the order. However, the orders should have the same expiration clause language. A rule will be added to CO 725 to incorporate the language in AIO 39. CPAI next requests reconsideration of the language of Conclusion 12 of CO 725 which states, in part, that CPAI would pre -produce injectors before beginning injection operations. Because pre -production may not be used for the Kuparuk-Torok injection wells, CPAI asks that the statement that the wells will be pre -produced be removed from the order. The AOGCC agrees. Conclusion 12 of CO 725 will be revised in the manner that CPAI requests. CPAI also requests reconsideration of Rule 9(d) of CO 725 which requires, in part, a sundry application proposing corrective action or increased monitoring for wells with sustained casing pressures in excess of the thresholds set in Rule 9(c) of CO 725. Because sustained casing pressure remains a significant concern, the AOGCC will require the submittal of a sundry application to develop a response, either increased monitoring or a corrective action. CPAI's proposed change is rejected. Rule 9(d) of CO 725 will not be modified. CPAI's final request is that the phrase "regular production" be removed from CO 725. The word "regular" will be removed from CO 725 because whether regular production is occurring is not material to AOGCC's determination of pool rules and because of the potential substantial tax consequence to CPAI if the phrase remains in CO 725. The AOGCC specifically notes that its willingness to delete "regular" is not a determination of whether regular production has or has not occurred. NOW THEREFORE, it is ordered that CO 725 be modified in the following ways: Finding 10 is modified to read as follows: In -Place and Recoverable Oil Volumes: Hydrocarbon Resources Estimated Volume (MMSTB) Drill Site 3S Additional Drill Site Original Oil in Place (OOIP) 100-500 100-300 Primary Recovery (5% OOIP) 5-25 5-15 Primary + Waterflood (10-40% OOIP) 10-200 10-120 Production from the proposed Moraine Oil Pool within the Kuparuk River Unit began in 2013 from KRU 3S-19, and has been reported in AOGCC records as the Kuparuk River Torok Undefined Oil Pool. Conclusion 12 is modified to read as follows: A gas -oil ratio (GOR) limitation waiver is appropriate because the Kuparuk River -Torok Oil Pool will be developed as a waterflood and water -alternating -gas enhanced recovery Docket No. CO-16-007 Docket No. AI0-16-011 September 15, 2016 Page 3 of 3 project. Once pressure maintenance operations commence, GORs should not exceed the limits imposed by 20 AAC 25.240(a). And, the expiration clause is replaced by a new rule that reads as follows: Rule 13 Expiration Date This order shall expire if ConocoPhillips Alaska Inc. ceases to be the Designated Operator for the Kuparuk River Unit or five years after the effective date shown below, whichever occurs first, unless prior to the expiration date CPAI requests the order be extended. Any such request shall include: a. A review of the existing rules in the order and an analysis whether or not those rules should be retained, amended, or repealed; b. A review of, and discussion on, whether or not the affected area of the order should be revised; and c. A discussion of, and justification for, proposed new rules or revisions to existing rules. DONE at Anchorage, Alaska and dated September 15, 2016. 1,2 Cathy . Foerster Daniel T. Sea' -mount, Jr. Chair, Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. 1�1 • Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Friday, September 16, 2016 9:05 AM To: Ballantine, Tab A (LAW); Bender, Makana K (DOA); Bettis, Patricia K (DOA); Bixby, Brian D (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Cook, Guy D (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA); French, Hollis (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Herrera, Matthew F (DOA); Hill, Johnnie W (DOA); Jones, Jeffery B (DOA); Kair, Michael N (DOA); Link, Liz M (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Quick, Michael J (DOA); Regg, James B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Wallace, Chris D (DOA); AK, GWO Projects Well Integrity; AKDCWellIntegrityCoordinator, Alan Bailey; Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew VanderJack; Ann Danielson; Anna Raff; Barbara F Fullmer; bbritch; bbohrer@ap.org; Bill Bredar; Bob Shavelson; Brian Havelock; Bruce Webb; Caleb Conrad; Candi English; Cocklan-Vendl, Mary E; Colleen Miller, Crandall, Krissell; D Lawrence; Dale Hoffman; Dave Harbour, David Boelens; David Duffy, David House; David McCaleb; David Tetta; ddonkel@cfl.rr.com; DNROG Units (DNR sponsored); Donna Ambruz, Ed Jones; Elizabeth Harball; Elowe, Kristin; Evan Osborne; Evans, John R (LDZX); Gary Oskolkosf, George Pollock; Gordon Pospisil; Greeley, Destin M (DOR); Gregg Nady; Gretchen Stoddard; gspfoff, Hyun, James J (DNR); Jacki Rose; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jerry McCutcheon; Jim Watt; Jim White; Joe Lastufka; Radio Kenai; Burdick, John D (DNR); Easton, John R (DNR); Jon Goltz; Juanita Lovett; Judy Stanek, Julie Little; Kari Moriarty; Kasper Kowalewski; Kazeem Adegbola; Keith Torrance; Keith Wiles; Kelly Sperback; Kruse, Rebecca D (DNR); Gregersen, Laura S (DNR); Leslie Smith; Louisiana Cutler, Luke Keller, Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Kremer, Marguerite C (DNR); Mealear Tauch; Michael Bill; Michael Calkins; Michael Moora; MJ Loveland; mkm7200; Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nikki Martin; NSK Problem Well Supv; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Delbridge, Rena E (LAS); Renan Yanish; Richard Cool; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Skutca, Joseph E (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Stephanie Klemmer; Stephen Hennigan; Sternicki, Oliver R; Moothart, Steve R (DNR); Steve Quinn; Suzanne Gibson; Sheffield@aoga.org; Ted Kramer; Davidson, Temple (DNR); Teresa Imm; Thor Cutler, Tim Jones; Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Umekwe, Maduabuchi P (DNR); Vinnie Catalano; Weston Nash; Whitney Pettus; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Assmann, Aaron A; Bajsarowicz, Caroline J; Brian Gross; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Don Shaw; Eric Lidji; Garrett Haag; Smith, Graham O (DNR); Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Holly Pearen; Jamie M. Long; Jason Bergerson; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Franger, James M (DNR); Morgan, Kirk A (DNR); Umekwe, Maduabuchi P (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); Tostevin, Breck C (LAW); Wayne Wooster, William Van Dyke Subject: CO 44.75 and CO 725.001 Attachments: co74 001.pdf, co44.75.pdf Please see attached. Docket No. CO-16-007 Docket No. AIO-16-011 Request for Reconsideration of Conservation Order No. 725 and Area Injection Order No. 39, Kuparuk River -Torok Oil Pool Conservation Order No. 44.75 Docket No. CO-16-017 MGS A44-02 Middle Ground Shoal Field MGS E, F and G Oil Pools Jodi/ J. Cotom6ie AO(jCC Syecia1Assistant _Atska oil and(�as Conservation Commission 333 West 7"' Avenue Anchor -age, Alaska 99501 Office: (907) 793-1221 _)Fax: (907) 276-7-542 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 Jody Colombie at 907.793.1221 or iody.colombie@alaska.ciov. r� • Jack Hakkila Bernie Karl P.O. Box 190083 K&K Recycling Inc. Anchorage, AK 99519 P.O. Box 58055 Fairbanks, AK 99711 Penny Vadla George Vaught, Jr. 399 W. Riverview Ave. P.O. Box 13557 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Richard Wagner Juanita Lovett P.O. Box 60868 Hilcorp Alaska, LLC Fairbanks, AK 99706 by Courier Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 THE STATE 'ALASKA GOVERNOR BILL WALKER Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL CONSERVATION ORDER NO. 725.002 Mr. Marc Lemons Manager, GKA Base Prod. & Optimization ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: CO17-010 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Request for administrative approval to remove requirement for an annual reservoir review meeting For Kuparuk River -Torok Oil Pool Kuparuk River Unit Kuparuk River Field Kuparuk River -Torok Oil Pool Dear Mr. Lemons: March 31, 2017, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to revoke Rule 8(b) of Conservation Order No. 725 (CO 725) to remove the requirement to hold a technical review meeting by June I" of each year to discuss the annual reservoir surveillance report for the Kuparuk River -Torok Oil Pool. In accordance with Rule 12 of CO 725, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request for revoke Rule 8(b). Because the AOGCC has the authority to ask for a meeting with CPAI to discuss annual reservoir surveillance reports regardless of any specific rule in the for a given pool, there is no need for a specific rule in CO 725. Now therefore it is ordered that Rule 8(b) be removed from CO 725 and the rest of Rule 7 is restated as follows: Rule 8 Annual Reservoir Review (Revised this administrative approval) An annual reservoir surveillance report must be filed by April lst of each year and include future development plans, reservoir depletion plans, and surveillance information for the prior calendar year, including: a. The voidage balance, by month, of produced fluids and injected fluids and the cumulative status for each producing interval; b. A reservoir pressure map at datum, and a summary and analysis of the reservoir pressure surveys within the pool; c. The results and, where appropriate, an analysis of production and injection log surveys, tracer surveys, observation well surveys, and any other special monitoring; CO 725.002 May 10, 2017 Page 2 of 2 d. A review of pool production allocation factors and issues over the prior year; e. A review of the progress of the enhanced recovery project; and f. A reservoir management summary, including results of any reservoir simulation studies. DONE at Anchorage, Alaska and dated May 10, 2017. I 4CathyFoerster Hollis French Chair, Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on aweekend or state holiday. Tl IE' STA'l F "'ALASKA GOVERNOR BILL NVA1_KFP ADMINISTRATIVE APPROVAL CONSERVATION ORDER NO.725.002 Mr. Marc Lemons Manager, GKA Base Prod. & Optimization ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: CO17-010 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 aogcc.alaska.gov Request for administrative approval to remove requirement for an annual reservoir review meeting For Kuparuk River -Torok Oil Pool Kuparuk River Unit Kuparuk River Field Kuparuk River -Torok Oil Pool Dear Mr. Lemons: March 31, 2017, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to revoke Rule 8(b) of Conservation Order No. 725 (CO 725) to remove the requirement to hold a technical review meeting by June 1" of each year to discuss the annual reservoir surveillance report for the Kuparuk River -Torok Oil Pool. In accordance with Rule 12 of CO 725, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request for revoke Rule 8(b). Because the AOGCC has the authority to ask for a meeting with CPAI to discuss annual reservoir surveillance reports regardless of any specific rule in the for a given pool, there is no need for a specific rule in CO 725. Now therefore it is ordered that Rule 8(b) be removed from CO 725 and the rest of Rule 7 is restated as follows: Rule 8 Annual Reservoir Review (Revised this administrative approval) An annual reservoir surveillance report must be filed by April 1" of each year and include future development plans, reservoir depletion plans, and surveillance information for the prior calendar year, including: a. The voidage balance, by month, of produced fluids and injected fluids and the cumulative status for each producing interval; b. A reservoir pressure map at datum, and a summary and analysis of the reservoir pressure surveys within the pool; c. The results and, where appropriate, an analysis of production and injection log surveys, tracer surveys, observation well surveys, and any other special monitoring; CO 725.002 May 10, 2017 Page 2 of 2 d. A review of pool production allocation factors and issues over the prior year; e. A review of the progress of the enhanced recovery project; and f. A reservoir management summary, including results of any reservoir simulation studies. DONE at Anchorage, Alaska and dated May 10, 2017. //signature on file// //signature on file// Cathy P. Foerster Hollis French Chair, Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to nin is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Bernie Karl K&K Recycling Inc. Gordon Severson Penny Vadla P.O. Box 58055 3201 Westmar Cir. 399 W. Riverview Ave. Fairbanks, AK 99711-0055 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 George Vaught, Jr. Darwin Waldsmith Richard Wagner P.O. Box 13557 P.O. Box 39309 P.O. Box 60868 Denver, CO 80201-3557 Ninilchik, AK 99639-0309 Fairbanks, AK 99706-0868 USCL �� 2.- 2o, -( Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Wednesday, May 10, 2017 1:00 PM To: DOA AOGCC Prudhoe Bay; 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); French, Hollis (DOA); Frystacky, Michal (DOA); Guhl, Meredith D (DOA); Kair, Michael N (DOA); Link, Liz M (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Quick, Michael J (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); AK, GWO Projects Well Integrity; AKDCWellIntegrityCoordinator, Alan Bailey; Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew VanderJack; Ann Danielson; Anna Raff; Barbara F Fullmer, bbritch; bbohrer@ap.org; Ben Boettger; Bill Bredar; Bob Shavelson; Brandon Viator; Brian Havelock; Bruce Webb; Caleb Conrad; Candi English; Cocklan-Vendl, Mary E; Colleen Miller; Connie Downing; Crandall, Krissell; D Lawrence; Dale Hoffman; Darci Horner; Dave Harbour; David Boelens; David Duffy; David House; David McCaleb; David McCraine; David Tetta; ddonkel@cfl.rr.com; DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elizabeth Harball; Elowe, Kristin; Elwood Brehmer; Evan Osborne; Evans, John R (LDZX); George Pollock; Gordon Pospisil; Greeley, Destin M (DOR); Gretchen Stoddard; gspfoff, Hunter Cox; Hurst, Rona D (DNR); Hyun, James J (DNR); Jacki Rose; Jason Brune; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jill Simek; Jim Watt; Jim White; Joe Lastufka; Radio Kenai; Burdick, John D (DNR); Easton, John R (DNR); Larsen, John M (DOR); John Stuart; Jon Goltz; Chmielowski, Josef (DNR); Juanita Lovett; Judy Stanek; Kari Moriarty; Kasper Kowalewski; Kazeem Adegbola; Keith Torrance; Keith Wiles; Kelly Sperback; Frank, Kevin J (DNR); Kruse, Rebecca D (DNR); Gregersen, Laura S (DNR); Leslie Smith; Lori Nelson; Louisiana Cutler; Luke Keller, Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Mealear Tauch; Michael Bill; Michael Calkins; Michael Moora; MJ Loveland; mkm7200; Motteram, Luke A; Mueller, Marta R (DNR); Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nikki Martin; NSK Problem Well Supv; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Renan Yanish; Richard Cool; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shahla Farzan; Shannon Donnelly; Sharon Yarawsky; Skutca, Joseph E (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Stephanie Klemmer; Stephen Hennigan; Sternicki, Oliver R; Moothart, Steve R (DNR); Steve Quinn; Suzanne Gibson; sheffield@aoga.org; Ted Kramer, Teresa Imm; Thor Cutler; Tim Jones; Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Umekwe, Maduabuchi P (DNR); Vinnie Catalano; Well Integrity; Well Integrity; Weston Nash; Whitney Pettus; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Bajsarowicz, Caroline J; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Catie Quinn; Corey Munk; Don Shaw; Eppie Hogan; Eric Lidji; Garrett Haag; Smith, Graham O (DNR); Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Fair, Holly S (DNR); Jamie M. Long; Jason Bergerson; Jesse Chielowski; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck, Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Franger, James M (DNR); Morgan, Kirk A (DNR); Umekwe, Maduabuchi P (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); Tostevin, Breck C (LAW); Wayne Wooster, William Van Dyke Subject: co275-002 (CPA) KRU Attachments: co275.002.pdf Re: Docket Number: CO17-010 Request for administrative approval to remove requirement for an annual reservoir review meeting For Kuparuk River -Torok Oil Pool Kuparuk River Unit Kuparuk River Field Kuparuk River -Torok Oil Pool Jody J. Co(ombie AOGCC Specia(Assistant Alaska Oil and Gas Conservation Commission 333 West 7" Avenue Anchorage, Alaska 995oi Office: (907) 793-1221 ,Fax: (907) 276-7542 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 Jody Colombie at 907.793.1221 or jodv.colombie@alaska.gov. INDEXES ConocoPhillips Alaska, Inc. Marc Lemons Manager, GKA Base Prod. & Optimization North Slope Operations & Development ConocoPhillips Alaska, Inc. PO Box 100360 Anchoage, Alaska ECE'VED Phone: (907) 263 4027 10-0360 March 31, 2017 MAR 31 2017 Commissioner Cathy Foerster A®GCC Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Dear Commissioner Foerster, ConocoPhillips Alaska, Inc. (CPA[), as Operator of the Kuparuk River Unit, respectfully requests an administrative action by the Commission to waive the requirement for a technical review meeting for the Kuparuk River -Torok Oil Pool under Rule 8(b) of Conservation Order 725. The rule is stated as follows: `By June 1st of each year, the operator shall schedule and conduct a technical review meeting with the AOGCC to discuss the annual reservoir surveillance report and items that may require action within the coming year. " This rule is unique to the Kuparuk River -Torok Oil Pool, and we are seeking uniform treatment of each oil pool within the Kuparuk River Unit. CPAI will continue to provide an Annual Surveillance Report, summarizing all information that would be covered in the technical review meeting, and we will be happy to meet with the Commission if it wishes to discuss any matters covered in the Report. This requested waiver is limited to the formal requirement to schedule and conduct a technical review meeting each year. Please feel free to contact Lynn Aleshire at 265-6525 regarding this request. Sincerely, Marc Lemons Manager, GKA Base Prod. & Optimization 0 0 0 • September 1st, 2016 Alaska Oil and Gas Conservation Commission 333 W. 7th Ave #100 Anchorage, Alaska, 99501-3539 Kazeem A. Adegbola Manager, GKA Development North Slope Operations and Development ConocoPhillips Alaska, Inc. ATO-1326 700 G Street Anchorage, AK 99501 phone 907.263.4027 It J RE: Supplement to Request for Reconsideration Conservation Order No. 725, Kuparuk River -Torok Oil Pool, North Slope, AK Dear Commissioners: SEP 0 12016 ConocoPhillips Alaska, Inc. ("ConocoPhillips") respectfully submits this supplement to our request for reconsideration, dated August 10, of the Conservation Order No. 725 ("CO"), dated July 22nd, 2016. The CO, following a common format seen in other conservation orders, states that "regular production" began during the 3S-19 well testing time period. Specifically, the CO provides in relevant part on page 6: Regular production of the proposed Moraine Oil Pool within the Kuparuk River Unit began in 2013 from KRU 3S-19. The identification of a date on which regular production began matters because recent tax law changes in HB 247 link the gross value at the point of production to the date on which "regular production" begins. The bill was signed into law June 28, 2016, after the hearing on CO 725 had already occurred. Because it is not uncommon for AOGCC conservation orders to identify the date on which regular production begins, the significance of the language in CO 725 under the new tax law was not immediately apparent. These circumstances provide good cause for reconsidering the order outside the 20 days normally allowed. The 3S-19 production was not "regular production" because that term is defined in AS 31.05.170(14) to mean "continuing production of oil or gas from a well into production facilities and transportation to market, but does not include short term testing, evaluation, or experimental pilot production[.]" Production from 3S-19 was non -continuous and part of an evaluation of the Moraine Reservoir to determine the productivity and watercut of the interval. Initially, the 3S-19 well was an existing Kuparuk Reservoir producer that required a rig workover to bring the well back on production. The workover scope was modified to also test the Moraine Reservoir prior to utilizing the wellbore for Kuparuk Reservoir production. After the workover was completed, the Moraine interval was hydraulically stimulated and produced under tract operations as follows: February 20 - April 4, 2013 (then shut-in for a pressure buildup analysis). July 29, 2013 - March 10, 2014. April 12 - May 18, 2014. CPAI Request for ReconsideraPon f Conservation Order No. 725 and Area Injection Order No. 39 Page 2 of 2 June 17 - November 14, 2014. Each time the well was shut-in in 2014, pressure buildup analyses were performed before starting production again. The frequency of the pressure build analyses stemmed from the difficulties in collecting representative data. Additional focus was applied to the production characteristics of the interval due to the tendency of the formation to produce fill and due to the inconsistency of the liquid and watercut trends. The Moraine interval was on production for a couple of days in early June 2015, which was the final production from the interval, before the well was configured back to Kuparuk Reservoir production in late June 2015. The Moraine Reservoir production phase of the 3S-19 served as an opportunity to further characterize the fluid properties and flow potential to determine the economic viability of a dedicated horizontal producer. Given the discontinuous nature of the 3S-19 Moraine production, and the purpose of producing the well in order to evaluate the reservoir, ConocoPhillips submits that the production should not be characterized as "regular" production. If the AOGCC declines to deem these circumstances as good cause for reconsideration outside the normal 20-day period, then ConocoPhillips asks in the alternative that AOGCC exercise its discretion to administratively amend the order to fix an error. Please contact Kasper Kowalewski (265-1363) if you have questions or require clarification of this request for reconsideration. Regards, Kazeem Adegbola Manager, GKA Development • 5 0 ConooCoPhillips August loth, 2016 Alaska Oil and Gas Conservation Commission 333 W. 7th Ave #100 Anchorage, Alaska, 99501-3539 2G1 Kazeem A. Adegbola f`e X..F Manager, GKA Development North Slope Operations and Development ConocoPhillips Alaska, Inc. ATO-1326 700 G Street Anchorage, AK 99501 phone 907.263.4027 RE: Request for Reconsideration Conservation Order No. 725, Kuparuk River -Torok Oil Pool, North Slope, AK Area Injection Order No. 39, Kuparuk River -Torok Oil Pool, North Slope, AK Dear Commissioners: ConocoPhillips Alaska, Inc. ("ConocoPhillips") respectfully requests reconsideration of three discrete parts of the recent Kuparuk River — Torok orders: Conservation Order No. 725 ("CO") and Area Injection Order No. 39 ("AIO"), each dated July 22"d, 2016. While we appreciate the Commission's timely issuance of the orders requested by ConocoPhillips, we see three matters that in our judgment should be addressed on reconsideration. Five -Year Expiration Each of the orders expires automatically in five years unless some other action is taken. The language in the AIO addresses a potential extension, but the language in the CO does not. Specifically, the CO provides in relevant part on page 15: This order shall expire if ConocoPhillips Alaska Inc. ceases to be the Designated Operator for the Kuparuk River Unit or five years after the effective date shown below, whichever occurs first, unless prior to the expiration date CPAI requests that the order be extended. And the AIO provides in relevant part on page 13: This order shall expire if ConocoPhillips Alaska Inc. ceases to be the Designated Operator for the Kuparuk River Unit or five years after the effective date shown below, whichever occurs first, unless prior to the expiration date CPAI requests that the order be extended. Any such request shall include: a. A review of the existing rules in the order and an analysis whether or not those rules should be retained, amended, or repealed; 0 0 CPAI Request for Reconsideration of Conservation Order No. 725 and Area Injection Order No. 39 Page 2 of 2 b. A review of, and discussion on, whether or not the affected area of the order should be revised; and c. A discussion of, and justification for, proposed new rules or revisions to existing rules. To ConocoPhillips' knowledge, this language has not appeared in any prior conservation order, and similar language has appeared in only one amendment to an area injection order. We are aware that the Commission has, in a recent public notice, proposed a new regulation that would make all orders automatically expire in five years. Because this issue will be subject to public comment as part of the rulemaking process that is underway, ConocoPhillips urges the Commission to eliminate the expiration language from the two orders as issued here, and allow these two orders to be treated as all other orders will be treated under a possible new rule the Commission adopts in the future. ConocoPhillips plans to comment on the proposed automatic expiration rule. We do not yet have our comments prepared, but we do think there may be a better way to address the Commission's objective than to have all rules expire automatically after five years. We believe such a rule would impose a heavy burden on both the regulatory agency and the regulated operators, and would be unnecessary as a universal rule. The Commission may already have authority under existing regulations, including 20 AAC 25.460, .520 and .540, to amend orders on a case -by -case basis as circumstances warrant, with the benefit of annual and monthly reports from the operators to help determine when a fresh look may be required. Additionally, the operator and any affected owner, or other interested party has the right to request amendment of an area injection order or conservation order at any time through existing AOGCC processes. See, e.g., 20 AAC 25.520(a) & (c); 20 AAC 25.540(a)-(b). In case of automatic expiration, which we oppose, we see a high risk of unnecessary problems if the steps needed to avoid expiration are delayed, opposed, or otherwise impaired. In such a case, the pool ceases to exist as a regulatory matter, putting the operator in a position of possibly having to cease otherwise complaint drilling operations, injection, and possibly even production to the detriment of the State as a whole. This level of uncertainty and potential instability will not reduce waste, protect correlative rights or maximize ultimate recovery. Instead, automatic expiration and additional administrative process will drive up costs, and could potentially affect project economics. We believe a less burdensome and lower risk approach may be feasible, and we intend to work constructively with the Commission on the issue. If we find a better way, it would not be sensible to have the CO and AIO for the Kuparuk River — Torok pool be burdened with an automatic five-year expiration due to orders that supersede the generally applicable rules. ConocoPhillips requests that the automatic five-year expiration of the AIO and CO be removed from both the AIO and CO. Pre -production Conclusion 12 in the CO includes a statement about pre -production of injector wells that ConocoPhillips asks to be deleted. The full text of the conclusion (with a strike -through line through the language we propose to be deleted) is as follows: A gas -oil ratio (GOR) limitation waiver is appropriate because the Kuparuk River — Torok Oil Pool will be developed as a waterflood and water -alternating -gas enhanced recovery project. Once pressure maintenance operations commence, GORs should not exceed the limits imposed by 20 AAC 25.240(a). I-In,we,ver, hefnre the pressure ensure aaden, rote reservoir v oidage to a GGFnrrm dat at ieGtiG During this neried there may he ell that eXGeed the GOR limits 0 • CPAI Request for Reconsideration of Conservation Order No. 725 and Area Injection Order No. 39 Page 3 of 2 We have no objection to the language in Rule 7 on gas -oil ratios; our concern is just with some of the language in Conclusion 12. While we may pre -produce injectors, it's not certain that we will always wish to do so, and we are concerned that the language in Conclusion 12 could in the future be interpreted as a commitment to pre -production, which ConocoPhillips did not intend to make. To avoid the potential for future dispute we ask that the language, which we believe is unnecessary, be deleted. Annular Pressure Rule Rule 9(d) in the CO requires submittal of an Application for Sundry Approval (Form 10-403) for any development well having sustained pressure that exceeds the limits set in Rule 9(c). ConocoPhillips requests that the Commission revise the CO to provide that the AOGCC "may" require submittal, but such a submittal is not automatically required. ConocoPhillips is already required to provide notice under Rule 9(c) to the AOGCC of sustained inner annulus pressures exceeding 2000 psig, and sustained outer annulus pressures exceeding 1000 psig. This notice together with a provision that provides the AOGCC with the right to request the filing of a sundry will provide the appropriate level of oversight. ConocoPhillips requests the following rule 9(d) be substituted for the current Rule 9(d): The AOGCC may require the operator to submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action or increased surveillance for any development well having sustained pressure that exceeds a limit set out in paragraph (c) of this rule. The AOGCC may approve the operator's proposal or require other actions or surveillance, including a mechanical integrity test or other approved diagnostic tests. The operator shall give sufficient notice of the testing schedule to allow the AOGCC to witness the test. ConocoPhillips requests this change to prevent well downtime and to facilitate routine well work. A blanket 10-403 sundry requirement could lead to multiple well work mobilizations, and could result in delay of well intervention work. A 10-403 sundry submittal requires approval from the AOGCC prior to proceeding with well operation and repair work for sustained casing pressure. The CO already requires that the AOGCC be notified of sustained pressure issues in Rule 9(c), and also requires that a sundry be obtained in situations in which sustained inner or outer annulus pressure exceeds 45% of the burst pressure rating. Additionally, ConocoPhillips' request for reconsideration is consistent with the CO provision approved in CO #645 Rule 9(d). For the reasons set forth above, ConocoPhillips requests that the AOGCC reconsider and revise its ruling on the CO and AIO. Please contact Kasper Kowalewski (265-1363) if you have questions or require clarification of this request for reconsideration. Regards, 41M4 V Kazeem Adegbola Manager, GKA Development 0 ConocoPhillips May 24"', 2016 Commissioners Catherine Foerster and Daniel Seamount Alaska Oil and Gas Conservation Commission 333 W. 7th Ave #100 Anchorage, Alaska, 99501-3539 MAY 24 ?Q16 /k Kazeem A. Adegbola Manager, GKA Development North Slope Operations and Development ConocoPhillips Alaska, Inc. ATO-1326 700 G Street Anchorage, AK 99501 phone 907.263.4027 RE: Application for Pool Rules Moraine Oil Pool, North Slope, AK Application for Area Injection Order for Moraine Oil Pool, North Slope, AK Dear Commissioners: On May 10"', 2016 the Alaska Oil and Gas Conservation Commission ("Commission") held a hearing on ConocoPhillips Alaska, Inc.'s applications for 1) a Conservation Order to classify the Moraine Oil Pool and to prescribe pool rules, and 2) an Area Injection Order ("AIO") for the proposed Moraine Oil Pool. This letter provides additional information that the Commissioners requested at the hearing. Ownership for leases ADL392371 and ADL392374 The Commissioners requested the ownership (including royalty) information on leases ADL392371 and ADL392374, which are not presently included in the Kuparuk River Unit ("KRU"). All KRU leases within the proposed Moraine Oil Pool boundary have aligned ownership as follows: ConocoPhillips Alaska, Inc. 55.402367% BP Exploration (Alaska) Inc 39.282233% Chevron U.S.A. Inc. 4.950600% ExxonMobil Alaska Production Inc. 0.364800% The 2 tracts outside the KRU (ADL 392371 and ADL 392374) are each owned as follows: ConocoPhillips Alaska, Inc. 55.40237% BP Exploration (Alaska) Inc 39.28223% Chevron U.S.A. Inc. 4.95060% ExxonMobil Alaska Production Inc. 0.36480% The different number of decimal places is attributable to a limitation on government forms. For all leases, within the proposed pool boundary, the lessor is the State of Alaska and the royalty on each tract is displayed on Attachment 1. • • CPAI Supplement to Application for Moraine Pool Rules and Application for Moraine Oil Pool Area Injection Order May 2016 Page 2 of 11 Surveillance program The Commissioners requested details on the surveillance plan to identify any problems related to containment of native and injected fluids. The surveillance plan for the Moraine Oil Pool wells and offset wells will be as follows: - For injection wells, the tubing -casing annulus pressure and injection rate of each injection well will be checked at least weekly to confirm continued mechanical integrity. ConocoPhillips Alaska, Inc. ("CPAI") will record wellhead pressures and injection rates daily. CPAI will limit the outer annulus pressure to 1000 psi. - For development wells (producers), CPAI will monitor each development well daily to check for sustained pressure, except if prevented by extreme weather conditions, emergency situations, or similar unavoidable circumstances. - CPAI will notify the Commission within three working days after CPAI identifies a well as having (a) sustained inner annulus pressure that exceeds 2000 psig or (b) sustained outer annulus pressure that exceeds 1000 psig. In addition to the surveillance plan listed above, CPAI will follow the ConocoPhillips Subsurface Containment Assurance ("SCA") standard, which was developed in 2013. The SCA applies company- wide to all ConocoPhillips operated assets. It provides a framework and approach to mitigate the risk associated with loss of injected or produced fluids out of targeted reservoir zones or wellbores. This program involves regular engagement from ConocoPhillips' corporate experts and local multidisciplinary technical staff in Alaska in five key elements: 1) wells, 2) reservoir & overburden characterization, 3) field management/surveillance, 4) operations, and 5) the response system. This corporate standard has an in - place audit system which allows for continuous improvement. It also requires and tracks containment training for all pertinent CPAI staff. The surveillance and assurance implementations listed above will supplement the confinement analysis performed on the Proposed Moraine Pool, which is the basis for the proposed maximum injection pressure gradient. The confinement assurance analysis included a geomechanical analysis of core collected across the confinement interval and proposed pool in the Moraine 1, which was used to calibrate the calculated rock strength of the proposed pool and overburden. This analysis yielded an overburden pressure gradient of 0.72 psi/ft and an estimated overburden fracture gradient of 0.82 psi/ft. The proposed Moraine Oil Pool maximum injection gradient is 0.67 psi/ft. In conclusion, the integration of a rigorously calibrated rock strength model and a thorough containment assurance plan is the direct result of CPAI's experiences from the last several years. Mechanical integrity of existing 3S wells The Commission requested information on the mechanical integrity status of the existing 3S wells in anticipation of hydraulic stimulation of the Moraine Oil Pool wells. Attachment 2 highlights the locations of the existing 3S wells and the initially planned Moraine Oil Pool wells during the second phase of development. Currently the wells with identified tubing integrity challenges on the 3S drill site are 3S-15 and 3S-26. No outer annulus leaks have been identified on the 3S wells. In relation to the cement integrity of the 3S Kuparuk wells, Table-1 below lists the estimated top of cement ("TOC") of the production casing in each well and the depth of the production shoe for each well. There are no existing wells within one -quarter mile of the initially planned injection wells. Specific approvals for any new injection wells or existing wells to be converted to injection service will be obtained pursuant to 20 AAC 25.005, 25.280 and 25.507, or any applicable successor regulation. 0 • CPAI Supplement to Application for Moraine Pool Rules and Application for Moraine Oil Pool Area Injection Order May 2016 Page 3 of 11 Well Shoe depth MD (ft) Estimated TOC MD (ft) Estimated Top Moraine MD (ft) Estimated length of Cement (ft) 3S-03 7960 6835 6782 1125 3S-06A 8569 7205 7364 1364 3S-07 6623 5585 5708 1038 3S-08C 8795 7696 7473 1099 3S-09 9639 8232 8213 1407 3S-10 8113 7003 7118 1110 3S-14 6880 5510 5801 1370 3S-15 8404 7296 7347 1108 3S-16 5907 5017 5264 890 3S-17A 8938 7593 7531 1345 3S-18 6887 5848 5930 1039 3S-19 10027 8900 8648 1127 3S-21 8509 7719 8466 790 3S-22 8412 7070 7089 1342 3S-23A 10472 9471 8523 1001 3S-24A 11255 7932 11327 3323 3S-26 9389 5685 7481 3704 Table 1 — 3S Kuparuk Well Production Casing Shoe Depths and Estimated Top of Cement In addition to the table above, the comments related to the cementing operations of each of the wells are listed below: - 3S-03: Unable to reciprocate pipe & little to no returns throughout job - 3S-06: Unable to reciprocate pipe during job - 3S-07: Good circulation throughout job - 3S-08C: Good circulation throughout job, casing stuck before pumping cement - 3S-09: No comments available - 3S-10: Returns throughout job, could not reciprocate pipe during job - 3S-14: Good circulation throughout job - no losses - 3S-15: Did not have circulation prior or after cement job, lost 928 bbl before & 431.5 bbl while pumping cement - 3S-16: Full returns throughout job - 3S-17A: Lost returns & unable to move pipe during cement job - 3S-18: Good circulation throughout job - 3S-19: Good circulation throughout job - no losses - 3S-21: Had very slight circulation thru out job - 3S-22: Good circulation throughout job - 3S-23A: 10-15% returns during job - 3S-24A: Full returns throughout job - 3S-26: No comments available Consideration of adopting the Kuparuk sundry matrix for the Moraine Oil Pool The Commissioners requested that CPAI consider the use of the Kuparuk sundry matrix for the Moraine Oil Pool, which is a broader set of exemptions from the exemptions listed in the proposed Rule #7 of the "Application for Pool Rules Moraine Oil Pool" on page 26. CPAI Supplement to Application for Moraine Pool Rules and Application for Moraine Oil Pool Are Injection Order May 2016 Page 4 of 11 CPAI requests adoption of the Kuparuk sundry matrix, "Well Work Operations and Sund Notice/Reporting Requirements for Pools Subject to Sundry Waiver Rules July 29'h, 200 ", (Attachment 3 to this letter) in lieu of the proposed exemptions listed in the proposed Rule #7 of the "A plication for Pool Rules Moraine Oil Pool' on page 26. Consideration of conducting cement evaluation logging on all Moraine Oil Pool injectors The Commissioners requested that CPAI consider a requirement to conduct and provide cement evaluation logs in all injectors if the packer variance is granted (proposed rule #2 on pa e 20 of the "Application for Area Injection Order for Moraine Oil Pool'). CPAI has no objection to a requirement to conduct cement evaluation logging of all Mori fine Oil Pool injectors and to provide the logs to the Commission. Please contact Kasper Kowalewski (265-1363) if you have questions or require clarifica on of the information supplied in this letter or in the applications. Regards, Kazeem degbola Manager, GKA Development CPA[ Supplement to Application for Moraine Pool Rules and Application for Moraine Oil Pool May 2016 Page 5 of 11 ATTACHMENTS Injection Order CPAI Supplement to Application for Moraine Pool Rules and Application for Moraine Oil Pool Area Injection Order May 2016 Page 6 of 11 ATTACHMENT 1 : PLAT OF PROPOSED MORAINE OIL POOL WITH ROYALTY OF EACH TRACT DISPLAYED AOL391 ADL389955 T06ADU An -low AW37001 ADL389960 ADL38MO ADU89958 __Al i A013899.'i4 ADUNW7 00 AD1389M AD AD13 Oooguruk Unk ADL389952 ADL38M 30% NPS 12.5% 1 ADL55M ADL356032 L306501 ADMO38 P6.667%1 i4Dm I 23My16 ConocoPhillips Alaska Irc. MoraineArea Injection Order N S Surface Rights and Leases 0 ass 13 1.96 2b B Rf 1N PP 2% AOL355030 24 125% '" 3R 23 AW 73 301 30% NPS 125% ADL025512 j 513 ADLO25522 i i -- 3N 125% ADLOM21 -- 12.5% ADWM23 ADL025524 1 1 i - 1392113 Ku ADLO26531 31 y30 ADL434 12.5% 12.5% 12.5% RiV U H AD 5631 AMD ADLO25528 ADL380108 ADLO25532 .5% 35 ADL025547 3B ADL3sao�7 12.5% 12.5% 125% 125% aD1m5632 - 5s33 �90506 ADLD25544 ADL380107 ADLD25546 3G �391913 3 ADL392374 2V+! ADL391912 16.66667% 5% ADLM043 Placer AD11125551 � AOL02% Unit 21.1 i$I AD to �DL39102 21 2X t39160 ADL39150 16.66667% 12.5% 12.6 A0110 AD 1 AD1392371 ADLO25M ADLD 7 �' Wel P ad Moraine A10 i A Unit Boundary ADL391549 ADt39262s AK Leases AM25571 570 ADLD256 ❑ OTHER AD t39�03 213 ❑ C PAI.4 • 0 CPAI Supplement to Application for Moraine Pool Rules and Application for Moraine Oil Pool Area Injection Order May 2016 Page 7of11 ATTACHMENT 2: LOCATION OF EXISTING 3S WELLS AND MORAINE PHASE-2 PLANNED WELLS E 1630000F I� — --- Coasrine a Unit Boundary o } Lease Ebundary s AIO and Pool Area ........ __.._._.___.._..__....... t { �( i it Dan Site Pads iti Phase 2 Wells 6000000E N i Top Mmm oN Pool Pwwnoon • 3S-613. 3S-06 3S-10 • MORAINE 1 i 3S4)6A • 3S-09 3%1 3S-14 • 3S 17A 3S-07 3S-18 • • + • 3S-26 •3S-19 PAMJN -* •=JODS 35 3S23A+ 3S• 3S-16-22 3S-08Bf 3S-OSA • • • 3S-08C 3S-23 3!�M 3S-08 599000OF N I 3S-24A 3S-24 •• 598000OF N 0 1 MILE 6000000E N N 5980000E N CPAI Supplement to Application for Moraine Pool Rules and Application for Moraine Oil Pool Area Injection Order May 2016 Page 8 of 11 ATTACHMENT 3: WELL WORK OPERATIONS AND SUNDRY NOTICE/REPORTING REQUIREMENTS FOR POOLS SUBJECT TO SUNDRY WAIVER RULES JULY 29TH, 2005 DEVELOPMENT [PRODUCTION) WELLS No Forms Reauired 1 Form Re uired 2 Forms Required -10403 Not Required -10404 Not Required -10403 Not Required -10404 / 407 or other form Required -10-403 Required -10-404 / 407 or other form Required Thru-tubing Operations (D) Thru-tubing Operations (D) Thru-tubing Operations (D) • Fill tag • Permanent cement or mechanical plugs that • Perforate anew pool (D) • .Set & pull retrievable plugs do not completely abandon a zone. (D) • ' Change GLV's • Cutting off tailpipes. (D) • Dummy & gauge ring runs • Perforate new intervals within a pool (D) • Pull & rerun SSSV's • Patches (D) SPECIAL (D) • Pressure surveys — unless required by some specific approval On a case -by -case basis, a 10-403 will be • Temperature surveys —unless required b - required for a particular well or operation some specific approval if the Commission requests it. • Caliper surveys If a well is operating under a sundry • Reperforating existing intervals approval, a 10-403 may be required to • Bottom hole samples perform work. The operator should • Spinner surveys consult with the AOGCC to determine if • Logs — CNL, TDT, CO, CCL, CBL and a 10-403 is needed. Other Types — Unless required by some specific approval • Pump changes. • Packoff GLM (POGLM) Attachment Incorporated by reference into Conservation Orders 261 A, 297 A, 341 D Rule 14, 347 A, 351 A and 556 • • CPAI Supplement to Application for Moraine Pool Rules and Application for Moraine Oil Pool Area Injection Order May 2016 Page 9 of 11 ATTACHMENT 3 CONT.: WELL WORK OPERATIONS AND SUNDRY NOTICE/REPORTING REQUIREMENTS FOR POOLS SUBJECT TO SUNDRY WAIVER RULES JULY 29TH, 2005 DEVELOPMENT [PRODUCTION] WELLS ,.T_ r_ __ bs..,.:_—A i Rnrm Reanireli 2 Forms Required IVV rusuu n uucns -10-403 Not Required - - ---- --- ----- -10.403 Not Required -10-403 Required -10404 Not Beguired -10-4041407 or other form Required -10-4041407 or other form Required Pumping Operations, including using coil.(D) Pumping Operations, including using coil. Pumping Operations, including using coil • .Tubing scale removal • Stimulations (frac or acid) (D) • Remedial cementing operations • ' Sludge removal • Remedial cementing operations (including but not limited to) • Freeze protection o Conductor Fill (D) o Casing shoes (outer annulus) (D) Ice plug removal • Squeezes/plugs to control fluid • Repair casing • Inhibitor squeezes movement in zone (D) (including but not limited to) • Hot Oil o mechanical repairs (D) + Tubing acid jobs o "pumping" repairs (cement or gel squeezes) (D) • Fill clean out Other Operations (D) Other Operations Other Operations • Xmas tree & valve replacement • Seal welding on bradenheads (D) • Convert producer (D) to injector • Diagnostic & pressure testing — unless • Major welding repairs on wellheads required by some specific approval (D) • Conductor "cutaways" and surface casing welding repairs (D) • Annular disposal (D) (Reported on form 10423 RiglCoil Operations Rig/Coil Operations + Alteration of mechanical completion • Repair Casing (including but not limited to) (including but not limited to) o Pulling tubing, milling packers (D) o Mechanical repairs (D) o Install velocity strings (D) (scab liners, tiebacks, etc) Attachment Incomorated by reference into Conservation Orders 261 A, 297 A, 341 D Rule 14, 347 A, 351 A and 556 • CPAI Supplement to Application for Moraine Pool Rules and Application for Moraine Oil Pool Area Injection Order May 2016 Page 10 of 11 ATTACHMENT 3 CONT.: WELL WORK OPERATIONS AND SUNDRY NOTICE/REPORTING REQUIREMENTS FOR POOLS SUBJECT TO SUNDRY WAIVER RULES JULY 29TH, 2005 SERVICE [INJECTION] WELLS ,., :..-a i Pt%rm Romireri 2 Forms Reauired 1,4V 1'Vlllla ! - ulaw -10-403 Not Required -10-404 Not Required - - ----- --- ----- -10-403 Not Required -10404 / 407 or other form Required -10-403 Required -10404 / 407 or other form Required Thru-tubing Operations (S) Thru-tubing Operations (S) Thru-tubing Operations (S) • Fill tag • Perforate new interval within a pool (S) • Perforate anew pool. (S) • Set & pull retrievable plugs • Permanent cement or mechanical • ' Change GLV's I ' plugs that do not completely abandon • Dummy & gauge ring runs a zone (S) • Pull ,& rerun SSSV's • Patches (S) • Cutting off tailpipes. (S) • Pressure surveys — unless required by some specific approval • Temperature surveys — unless required by SPECIAL (S) some specific approval • Caliper surveys On a case -by -case basis, a 10-403 will be • existing intervals tin Reperforating existin required for a particular well or operation • Bottom hole p if the Commission requests it. • Spinner surveys • Logs —CNL, TDT, CO, CCL, CBL and If a well is operating under a sundry Other Types — Unless required by some approval, a 10-403 may be required to specific approval perform work. The operator should consult with the AOGCC to determine if a 10-403 is needed. If operations in this column are planned on a A 10-403 should be submitted for any Please note that authorization from EPA disposal well, the operator should contact th perforating (new or reperf) operations on a Region 10 may be necessary to perform an AOGCC to determine if a 10-403 is needed. IClass II disposal well. work on a Class I disposal well. Attachment Incorporated by reference into Conservation Orders 261 A, 297 A, 341 D Rule 14, 347 A, 351 A and 556 is • CPAI Supplement to Application for Moraine Pool Rules and Application for Moraine Oil Pool Area Injection Order May 2016 Page 11 of 11 ATTACHMENT 3 CONT.: WELL WORT( OPERATIONS AND SUNDRY NOTICE/REPORTING REQUIREMENTS FOR POOLS SUBJECT TO SUNDRY WAIVER RULES JULY 29TH, 2005 SERVICE [INJECTION) WELLS Nn Fnrmc Rewired 1 Form Reauired 2 Forms Required -10403 Not Required -10-404 Not R uired -10403 Not Required -10404 / 407 or other form Required -10403 Required -10-404 / 407 or other form R2guired Pumping Operations, including using coil.(S) Pumping Operations, including using coil. Pumping Operations, including using coil. • -Tubing scale removal + Remedial cementing operations • Stimulations (frae or acid) (S) • ' Sludge removal o Conductor Fill (S) • Remedial cementing operations • Freeze protection • Squeezes/plugs to control fluid (including but not limited to) + Ice plug removal movement in zone (S) o Casing shoes (outer annulus) (S) • High pressure breakdown or inhibitor • Repair casing squeezes, excluding frac or acid jobs (including but not limited to) • Hot Oil o mechanical repairs (S) • Tubing acid jobs o "pumping" repairs (cement or • Fill clean out gel squeezes) (S) Other Operations (S) Other Operations Other Operations • Xmas tree & valve replacement • Injection well MIT (on MIT form) (S) • Major welding repairs on wellheads (S • Diagnostic & pressure testing — unless • Initial conversion from water injector • Conductor "cutaways" and surface required by some specific approval to WAG injector (S) casing welding repairs (S) • Convert from injector to producer if for • Annular disposal (S) more than 30 days. (S) (Reported on form 10423) + Seal welding on bradenheads (S) Attachment Incorporated by reference into Conservation Orders 261 A, 297 A, 341 D Rule 14, 347 A, 351 A and 556 i t 0 0 CJ C 1 ALASKA OIL AND GAS CONSERVATION COMMISSION 2 3 Before Commissioners: Cathy Foerster, Chair 4 Daniel T. Seamount 5 6 In the Matter of the Application of ) 7 ConocoPhillips Alaska, Inc., to establish ) 8 pool rules and authorize enhanced recovery ) 9 operations on an area injection basis to ) 10 govern the development of the proposed ) 11 Moraine Oil Pool in the Kuparuk River Field. ) 12 ) 13 Docket No.: CO 16-007 and AIO 16-011 14 ALASKA OIL and GAS CONSERVATION COMMISSION 15 Anchorage, Alaska 16 May 10, 2016 17 9:00 o'clock a.m. 18 PUBLIC HEARING 19 BEFORE: Cathy Foerster, Chair 20 Daniel T. Seamount rl 1 TABLE OF CONTENTS 2 Opening remarks by Chair Foerster 03 3 Remarks by Mr. Braun 06 4 Remarks by Mr. Kowalewski 09 5 Remarks by Ms. Umlauf 21 6 Remarks by Mr. Lewis 37 2 0 • 1 P R O C E E D I N G S 2 9:02:33 3 (On record - 9:00 a.m.) 4 CHAIR FOERSTER: I'll call this hearing to 5 order. Today is May 10, 2016, the time is 9:00 a.m. 6 We are at the offices of the Alaska Oil and Gas 7 Conservation Commission, 333 West Seventh Avenue, 8 Anchorage, Alaska. To my left is Commissioner Dan 9 Seamount and I'm Cathy Foerster. 10 We're hearing today testimony from 11 ConocoPhillips on docket number CO 16-007 and AIO 16- 12 011, the Moraine Pool, Kuparuk River Field Pool Rules 13 and Area Injection. Conoco by application received 14 March 31st, 2016 requests that the AOGCC issue orders 15 under 20 AAC 25.520 and 20 AAC 25.460 to establish pool 16 rules and authorize enhanced recovery operations on an 17 area injection basis to govern the development of the 18 proposed Moraine oil pool in the Kuparuk River field. 19 Computer Matrix will be recording today's 20 proceedings and you can get a copy of the transcript 21 from them. 22 It appears that ConocoPhillips is the only 23 entity signed up to testify. Is there anyone else not 24 representing ConocoPhillips that wants to testify 25 today? 3 1 (No comments) 2 CHAIR FOERSTER: All right. Okay. If that's 3 the case then we probably don't have to read the 4 misbehaver's rules so I won't. 5 I'll remind you to make sure the little green 6 light on your microphones are on and that you speak 7 into the microphones so that Computer Matrix can 8 capture what you way for the transcript and so people 9 in the back of the room can hear you. And as you 10 refer to slides please title them or refer to the -- if 11 they're numbered say we're looking at slide number X so 12 that 10 years from now when someone comes back and 13 looks at the record they can follow what you said and 14 refer to the documents that we have and refer to the 15 documents that we have. 16 All right. Dan, do you have anything to add? 17 COMMISSIONER SEAMOUNT: I have nothing at this 18 time, Madam Chair. 19 CHAIR FOERSTER: Okay. Well, then are all four 20 of you going to testify? 21 UNIDENTIFIED VOICE: Yes. 22 CHAIR FOERSTER: Is there anyone else from 23 Conoco that's intending to testify? 24 UNIDENTIFIED VOICE: If necessary. rd 1 for efficiency why don't I just swear you all in right 2 now. So please raise your right hand. And as I -- I'm 3 going to ask the swear or affirm question and then I'd 4 like each one of you one at a time to lean into the 5 microphone and say my name is so and so and I do. 6 Okay. Simple. 7 (Oath administered) 8 MR. KOWALEWSKI: My name is Kasper Kowalewski. 9 I do. 10 MR. BRAUN: My name is Michael Braun. I do. it MR. LEWIS: My name is Adam Lewis. I do. 12 MS. UMLAUF: My name is Kelly Umlauf. I do. 13 CHAIR FOERSTER: Okay. Thank you. So do any 14 of you want to be recognized as experts in an area such 15 as geology or reservoir engineering? 16 MR. BRAUN: Yes, we do. 17 CHAIR FOERSTER: Okay. When you start your 18 testimony that'll be a good time to -- I'm assuming you 19 -- if you don't you're going to be the lead off, you're 20 going to do the introduction and closings? 21 MR. BRAUN: I will. 22 CHAIR FOERSTER: And -- okay. Then let's start 23 with you. Give us your name and who you represent and 24 what area you want to be recognized as an expert in and 25 what those qualifications that make us see you as an 5 1 expert are. 2 MR. BRAUN: Okay. My name is Michael Braun. 3 So on behalf of ConocoPhillips, Incorporated who is the 4 Kuparuk River unit or KRU operator, Kasper Kowalewski, 5 Adam Lewis and Kelly Umlauf will testify with me as 6 witnesses as it -relates to the application of the 7 Moraine pool rules and Moraine pool area injection 8 order. Like we mentioned already we also have 9 additional experts in the room that may testify. 10 I'm a petroleum engineer with about 15 years of 11 industry experience. I joined ConocoPhillips Alaska in 12 November, 2007 after relocating from Argentina where I 13 worked five years as a production engineer and three 14 years as a reservoir engineer for several conventional 15 oil fields. After joining ConocoPhillips I worked as a 16 petroleum engineer for the Tarn field development and 17 since April, 2010 I have been leading the Kuparuk core 18 chipping drilling program. And since last October I 19 also have additional responsibilities which include a 20 supervision of the production engineering and 21 development of the central processing facility number 3 22 area in the Kuparuk field. So I hold a degree in 23 petroleum engineering, masters from the Instituto 24 Tecnologico de Buenos Aires, also known as ITBA. And I 25 would like to be qualified as an expert witness in 0 1 petroleum engineer. 2 CHAIR FOERSTER: Where did you get your 3 bachelor's degree, from the same place? 4 MR. BRAUN: Same place. 5 CHAIR FOERSTER: Okay. Commissioner Seamount, 6 do you have any questions? 7 COMMISSIONER SEAMOUNT: I have no questions, 8 comments or objections. 9 CHAIR FOERSTER: Okay. Nor do I. So we will 10 accept you as an expert in petroleum engineering and 11 you may proceed with your testimony. 12 MR. BRAUN: Thank you. So with that I'll 13 transition over to Kasper. 14 MR. KOWALEWSKI: Hello, Commissioners. My name 15 is Kasper Kowalewski. I also request to testify as a 16 petroleum engineering expert. 17 CHAIR FOERSTER: Okay. What are your 18 qualifications? 19 MR. KOWALEWSKI: I'm a petroleum engineer for 20 ConocoPhillips Alaska. My current role, I have 21 responsibilities for the Moraine development team as 22 well as the surveillance at three Kuparuk drill sites. 23 In relation to my background, I have a bachelor of 24 science in petroleum engineering from the University of 25 Alaska Fairbanks. I started working for ConocoPhillips 7 1 based in Anchorage, Alaska in 2009. I have seven years 2 of experience. Since starting in 2009 I've been based 3 in Houston, Texas as well as in Warsaw, Poland before 4 returning back to Anchorage in 2013. For the first 5 four years of my career I was a drilling engineer, for 6 the last three years I've been a petroleum engineer. 7 And for this particular role in the Moraine development 8 team, I've been part of it for the last six months. 9 CHAIR FOERSTER: Commissioner Seamount, do you 10 have any questions? 11 COMMISSIONER SEAMOUNT: What did you do in 12 Warsaw, Mr. Kowalewski? 13 MR. KOWALEWSKI: I was the lead drilling 14 engineer for our shale exploration out there. 15 COMMISSIONER SEAMOUNT: And how does shale look 16 in Poland right now? 17 MR. KOWALEWSKI: I think right now it doesn't 18 look too good anywhere unfortunately. 19 COMMISSIONER SEAMOUNT: And why is that? 20 MR.K: Well, the commodity prices. But 21 specifically for Poland in -- unfortunately we just 22 weren't able to get the type of resource we were 23 looking for. 24 COMMISSIONER SEAMOUNT: Huh. Okay. Well, I 25 have no objections or comments or other questions for • 1 Mr. Kowalewski. 2 CHAIR FOERSTER: And I have no questions or 3 objections so we'll recognize you as an expert in 4 petroleum engineering as well. 5 MR. KOWALEWSKI: Okay. Thank you. 6 KASPER KOWALEWSKI 7 previously sworn, called as a witness on behalf of 8 ConocoPhillips Alaska, testified as follows on: 9 DIRECT EXAMINATION 10 MR. KOWALEWSKI: With my brief comments I'll be it -- I'll speak a little bit to the intro of the project 12 as well as the overall Moraine oil pool that's 13 requested. 14 Thank you, Commissioners, for granting us on 15 behalf of ConocoPhillips Alaska, the opportunity to 16 speak today about the Moraine oil pool. Prior to 17 covering the material we'd like to recognize the AOGCC 18 staff. We are very fortunate with how patient and 19 responsive they were throughout the process. On 20 several different occasions the AOGCC staff met with 21 our group to provide feedback as well as review our 22 material which paid dividends in streamlining the 23 process on our end. 24 As a reference we've supplied the Palm 1 type 25 log, an acronym page, a copy of the slides that we're 0 • • 1 going to present as well as a copy of the submitted AIO 2 as well as the Moraine oil pool applications. As 3 required by the regulations a copy of the AIO was 4 provided to the surface owners as well as the operators 5 of the land within a quarter mile radius of the 6 proposed injection area. 7 As a reference for the Commissioners as well as 8 for the audience we have a total of 47 slides which 9 will take roughly an hour and a half to cover. 10 Here on slide number 2 the definitions of the 11 acronyms in the presentation are listed. In case there 12 are any questions related to the acronyms please let us 13 know. 14 Slide number 3 is a brief description of the 15 objective of the presentation as well as the agenda. 16 The objective of our presentation is to supply the 17 AOGCC with the information necessary to approve 18 ConocoPhillips Alaska's Moraine oil pool application 19 with the proposed pool rules as well as the area 20 injection order for the Moraine oil pool with the 21 proposed AIO rules. 22 For the agenda I will cover a brief background 23 on the Moraine reservoir as well as the requested 24 aerial extent of the Moraine oil pool. After that 25 Kelly will discuss the geology of the reservoir as well 10 1 as further describe the Moraine oil pool. At the 2 conclusion of Kelly's section Adam will discuss the 3 Moraine oil pool resource as well as the recovery 4 expectations. At the conclusion of Adam's section I 5 will talk about the operations and containment 6 assurance details. At the conclusion of the 7 presentation I will cover the proposed Moraine oil pool 8 rules as well as the proposed AIO rules. 9 Slide number 4 is an illustration of the 10 proposed Moraine oil pool as well as the wells that it pertain to the history of the oil pool. What I'll do 12 is I'll focus on the figure here on the right initially 13 and then I'll go into the history of the wells as 14 listed here on the left. 15 So on the right, it's a little bit hard to see, 16 but these blue dots that are predominantly on the left 17 side of the figure, they're the significant Moraine 18 wells which we do list several of them here in the 19 timeline. The proposed oil pool is outlined in this 20 yellowish color, on your slides it'll be red, and it's 21 right in the central portion of the figure. Also on 22 the figure there are blue lines on your slides, here 23 they're a little bit more reddish, are the unit 24 boundaries. So in our case the focus is the KRU 25 boundary which it overlaps this section of the proposed 11 • • 1 Moraine oil pool on the western portion. You can see 2 it a little bit more on the eastern portion on this 3 side. So in other words this section over here, these 4 leases, we are not requesting to be part of the Moraine 5 oil pool, but that is part of the KRU. 6 You'll notice that there are two leases that 7 are included in the proposed Moraine oil pool area, 8 however they are not included in the KRU. I'll discuss 9 those a little bit more in the next slide. 10 Right now I'll discuss some of the wells and 11 the history of the Moraine reservoir. I'll start with 12 the Colville 1 which was drilled in 1965 to assess the 13 reservoir. The location of the well is the bottom left 14 of center of the figure, so it's right here, Colville 15 1. Unfortunately there was no testing of the reservoir 16 at that point so we don't have any flow data from that 17 well. Later in the 1980's two additional wells were 18 drilled, Colville Delta 2 and the Colville Delta 3 to 19 further assess the reservoir. These wells are in the 20 upper left portion of the figure, right under the 21 Oooguruk text, it's right there. So that's the 22 Colville Delta 2 and then a little bit lower to the 23 left is the Colville Delta 3. Both of these wells were 24 initially unstimulated and had insignificant rates. In 25 the 1990's ARCO, Alaska, Incorporated drilled two 12 1 exploratory wells, the Kalbik 1 and the Kalbik 2. 2 These two wells again located on the left upper portion 3 of the figure are right under the Oooguruk text. 4 There's the Kalbik 1 and then a little bit to the left 5 and lower is the Kalbik 2. The unstimulated results of 6 the Kalbik 1 and insignificant oil rates, the well was 7 produced for a little bit less than a day, mostly water 8 production. 9 Before I go into these wells that were drilled 10 in the 2000's, the early reservoir history of the 11 Moraine is that it wasn't targeted -- it was a 12 periphery reservoir that was targeted by operators only 13 if they were drilling deeper zones so that's why 14 there's not that much data for the time period early in 15 the 2000's. 16 So on to the 2000's, more specifically 2010 to 17 2012. Pioneer Natural Resources, Alaska, Incorporated 18 drilled three producers in the upper Moraine member and 19 completed them as well in that section. And again 20 these wells are in the upper left-hand portion, in this 21 case it's in the adjacent unit, the Oooguruk unit and 22 it's the ODST 46, the ODST 45A as well as the ODST 47. 23 These wells produced between 350 to 600 barrels of oil 24 per day initially, with initial watercuts between 10 to 25 55 percent. ConocoPhillips then in 2013 recompleted 13 1 the 3S-19. 3S-19 is left of center of the figure, 2 right here. It was originally a Kuparuk sea -sand 3 producer so it was recompleted with the hydraulic 4 stimulation in the upper member of the Moraine and it 5 produced rates between 250 to 300 barrels of oil per 6 day. In 2015 ConocoPhillips drilled the Moraine 1 well 7 to further analyze the reservoir. To further analyze 8 the reservoir we collected core, fluid samples as well 9 as logs. The Core 1 is just above the 3S-19 in the 10 figure. 11 During that same time period as the Moraine 1 12 was drilled and cored we also drilled the 3S-620 which 13 was a horizontal producer in the Moraine. The lateral 14 extent of the 3S-620 was 4,200 feet approximately. We 15 hydraulically stimulated that well with an eight stage 16 frack. The initial production was 1,600 barrels of oil 17 per day with roughly 75 percent watercut. That 3S-620 18 is just to the right of the Moraine 1. 19 For the pressure support of the 3S-620 we are 20 currently drilling the 3S-613, the planned injector for 21 the 620. It'll be the left of the Moraine 1 and we 22 just spud the well April 16th and we are in the process 23 of actually drilling that well. We're expecting for 24 that well to be prepared for injection in July of 2016. 25 Before I move on to the next topic with Moraine 14 1 1 one of the most pivotal parts of that well is that we 2 were able to core the overburden for the geomechanical 3 testing and reservoir containment study. So from the 4 standpoint of the assessment for the AIO the core -- 5 the Moraine 1 core played a very large role in that. 6 One last well to note on this slide before I 7 transition to the next is the Palm 1. The Palm 1 which 8 left of center of the figure is used as our type log 9 for the Moraine oil pool. 10 COMMISSIONER SEAMOUNT: Mr. Kowalewski, on that 11 last slide you discussed test results and I -- am I to 12 assume that all these test results are of just the 13 Moraine interval? 14 MR. KOWALEWSKI: Yes, they are. 15 COMMISSIONER SEAMOUNT: And some of these wells 16 did better on -- in other zones; is that correct? 17 MR. KOWALEWSKI: In other zones not including 18 the Moraine; is that what you're asking? 19 COMMISSIONER SEAMOUNT: Yes. 20 MR. KOWALEWSKI: I couldn't speak to that. The 21 -- we're -- we have information on the Moraine 22 production rates, I can certainly look up the rates of 23 the additional formations, but I currently don't have 24 that available. 25 COMMISSIONER SEAMOUNT: Okay. If you look in 15 1 the area -- it's the northwest under Oooguruk there 2 were quite a few tests run and with varying results, is 3 there any reason why the results were so varying? 4 MR. KOWALEWSKI: So the location of the 5 wellbores, was it fractured or was it not fractured, a 6 lot of that will have an impact on the flow results of 7 the wells. 8 COMMISSIONER SEAMOUNT: How big were the 9 fractures? 10 MR. KOWALEWSKI: So for -- the wells that were 11 fractured would be the Colville Delta 3 and it was a 12 pretty small fracture relatively speaking to the modern 13 fracks. The Pioneer wells, they were also fracked. I 14 don't have the numbers with me to say what kind of the 15 fracture (indiscernible) was. However I can collect 16 that for you if you'd like that. 17 CHAIR FOERSTER: Is that something you want? 18 We probably have it ourselves. 19 COMMISSIONER SEAMOUNT: No, I guess we don't 20 need it, we'll get it ourselves. 21 MR. KOWALEWSKI: All right. Anymore questions 22 or should I go to the next slide? 23 (No comments) 24 MR. KOWALEWSKI: All right. So here on slide 25 number 5 the proposed area to be covered by the Moraine 16 1 oil pool is shown. Our leases are indicated in the 2 yellow which on the slide is coming out a little bit 3 more like the white color, and the Moraine oil pool 4 that we're proposing for the aerial extents, it is a 5 little bit more of a red color on your slides that 6 we've printed out, on this particular presentation it's 7 coming out more like a yellow color, and again it's in 8 the center of the slide. Again the KRU is the bluish 9 color and like I mentioned on the previous slide, on 10 the western portion we're overlapping the KRU, on the 11 eastern portion we're not. So these leases right here 12 are not a request to be part of the Moraine oil Pool, 13 for the Moraine oil pool the entire area is included in 14 the KRU except for a caveat for these two leases down 15 here that are left of center, bottom left of center in 16 the figure. These two leases, ADL 392374 and ADL 17 392371, they are currently not in the KRU however 18 historically they have been included in the KRU. In 19 1984 they were part of the KRU when the Environmental 20 Protection Agency adopted the aquifer exemption for the 21 KRU. They were also part of the KRU in 1986 when the 22 Commission incorporated the Kuparuk River unit aquifer 23 exemption on the PA. ConocoPhillips Alaska plans to 24 apply to the Department of Natural Resources for KRU 25 expansion to include these two leases before we do any 17 1 sort of development in them. So in other words we're 2 not going to drill any injectors for the Moraine or 3 producers for the Moraine until the KRU's expanded to 4 include these two leases. 5 CHAIR FOERSTER: What's the ownership of those 6 two leases? 7 MR. KOWALEWSKI: The ownership is the same, 8 it's -- excuse me, ConocoPhillips is the operator, but 9 it's the same as the rest of the KRU. 10 CHAIR FOERSTER: Okay. And the royalty owner 11 is the state? 12 MR. KOWALEWSKI: Uh-huh. 13 CHAIR FOERSTER: So there wouldn't -- there's 14 no cost differential or..... 15 MR. KOWALEWSKI: There's not. 16 CHAIR FOERSTER: .....royalty rate or anything 17 like that different? 18 MR. KOWALEWSKI: I don't believe there is, I'd 19 have to check. We purchased them in 2013. I believe 20 it should be exactly the same, but I'd have to confirm. 21 CHAIR FOERSTER: Okay. That's a question I'd 22 like an answer to. So I'm going to give you an 23 assignment. Somebody from Conoco, there are a lot of 24 people who aren't talking, maybe you can assign one of 25 them to take down questions that we..... 1 UNIDENTIFIED VOICE: (Indiscernible - away from 2 microphone)..... 3 CHAIR FOERSTER: Okay. So if we ask a question 4 that you don't have an answer for right now write it 5 down and at the end of the hearing we'll make a 6 decision to leave the record open for a number of days 7 so that you can get those questions answered. Okay. 8 All right. Please proceed. 9 MR. KOWALEWSKI: Thank you. So here on slide 10 number 6 I'll hand it to Kelly. 11 MS. UMLAUF: Hi, there. 12 CHAIR FOERSTER: Ms. Umlauf, would you like to 13 be recognized as an expert? 14 MS. UMLAUF: I would in geology, please. 15 CHAIR FOERSTER: All right. So your name and 16 who you represent and your credentials. 17 MS. UMLAUF: So my name is Kelly Umlauf, I've 18 been a petroleum geologist for about five years. I 19 started my career with ConocoPhillips in June of 2011. 20 I have both a bachelor's of science from the University 21 of Michigan and a master's of science from the 22 University of Arizona, both in geoscience. In 23 particular I've been working North Slope geology since 24 February of 2014 and before working in Alaska I was 25 employed in our ConocoPhillips, Houston office working 19 1 new venture exploration and an assignment in the Lower 2 48 reservoir -- unconventional reservoir exploration. 3 And I wish to be certified as an expert witness in 4 geology. 5 CHAIR FOERSTER: Commissioner Seamount, do you 6 have any questions? 7 COMMISSIONER SEAMOUNT: Your last name is 8 pronounced Umlauf? 9 MS. UMLAUF: Correct. Like Umlaut except with 10 an F at the end. 11 COMMISSIONER SEAMOUNT: Umlauf. Okay. Thank 12 you. 13 MS. UMLAUF: Uh-huh. 14 COMMISSIONER SEAMOUNT: No, I have no 15 questions, comments or objections to designating Mr. 16 Umlauf as an expert witness in petroleum geology. 17 CHAIR FOERSTER: Okay. Nor do I. So we 18 recognize you as an expert and you may proceed with 19 your testimony. 20 (Off record comments) 21 CHAIR FOERSTER: All right. Please -- that was 22 a joke so please proceed. 23 KELLY UMLAUF 24 previously sworn, called as a witness on behalf of 25 ConocoPhillips Alaska, testified as follows on: 20 1 DIRECT EXAMINATION 2 MS. UMLAUF: Okay. So starting on slide 7 here 3 we've got the geologic overview for the proposed 4 Moraine oil pool and the Moraine oil pool is defined as 5 the accumulation of hydrocarbons common to and 6 correlating with the interval between 5,630 feet 7 measured depth and 6,043 feet measured depth and that's 8 noted there on that Palm 1 well. So Palm 1 will be our 9 type log and that's there to the left of the screen, 10 you also have a copy with you. And as you may recall it Palm 1 is very near the 3S pad there from the opening 12 slide from Kasper. 13 So most of our well log images will look very 14 similar to what we've got here so I'm just going to 15 take the time now to kind of describe what you're 16 looking at. And I'll just move from left to right. 17 So in the first column there is gamma ray going 18 from zero 200 gamma ray API units and the curve is in 19 the black line on your slides, followed by TVD subsea 20 in feet, measured depth in feet. I have four curves in 21 resistivity posted going from one to 100 ohm meters, 22 they pretty much overlap each other, but you can see 23 the color distinction there on the heading. 24 The next column is neutron porosity going from 25 60 to zero porosity units as well as density from 1.65 21 1 to 2.65 grams per centimeter cubed, followed by member 2 divisions and then formation divisions. 3 So we'll start our way working up section. So 4 below the Moraine oil pool is the high reactive zone 5 which is commonly referred to as the HRZ. It's a thick 6 deposit of marine mudstones and it forms the lower 7 confining interval for the Moraine oil pool. The 8 entire Torok extends from the top HRZ marker which are 9 -- the markers are here by these red or orange lines 10 depending on where you're looking. So the Torok it formation goes from the top HRZ to the top Torok marker 12 with the Moraine oil pool going from the top HRZ marker 13 to the top Moraine marker there. As you can see from 14 the stratigraphic column there on the right hand side, 15 the Torok is cretaceous in age and I've got that 16 circled there just to kind of -- so it can catch your 17 eye. We interpret the Moraine oil pool to be within 18 the lower portion of the Torok formation and the 19 Moraine oil pool deposits in particular are probably 20 mid cretaceous, sloped to base and floor turbidite 21 deposits. And using well data we divide the Moraine 22 oil pool into two members, we call them the upper and 23 lower Moraine members. And that's denoted there in 24 that member column. With seismic data alone it's very 25 difficult to differentiate these two internal member 22 1 divisions. 2 The Moraine oil pool deposits, turbidite 3 deposits, are capped by a continuation of the Torok 4 formation which is a thick prograding sequence of slope 5 deposits consisting of siltstones and mudstones. The 6 Torok formation above the Moraine oil pool consists of 7 the upper confining interval of the proposed pool. 8 And lastly generally above the Torok formation 9 in our area is the Hue shale which is comprised of 10 Moraine claystones and tuffaceous mudstones. And the 11 base Hue shale starts there at the top Torok marker. 12 And the Moraine oil play exists thanks to a combination 13 trap with both a stratigraphic and a structural 14 component and I'll talk about that in a little bit on 15 coming slides. 16 COMMISSIONER SEAMOUNT: Ms. Umlauf..... 17 MS. UMLAUF: Yeah. 18 COMMISSIONER SEAMOUNT: .....is this proposed 19 Moraine oil pool, is it the same as the Oooguruk Torok 20 oil pool that Caliss produces as in pressure 21 communication? 22 MS. UMLAUF: So it's slightly different than 23 the Oooguruk Torok oil pool..... 24 COMMISSIONER SEAMOUNT: Okay. 25 MS. UMLAUF: .....is that what it's called, so 23 1 we incorporate something called the lower Moraine which 2 is more obvious in -- over the Kuparuk River unit. And 3 I'll kind of get into some of the pressure 4 communication in the coming slides, but just to kind of 5 give you an answer, probably near the lease line it 6 would be, but it's a different kind of depositional 7 siting where there's lots of sources coming down so not 8 all the sand bodies would be in communication. 9 COMMISSIONER SEAMOUNT: Okay. Good answer. 10 MS. UMLAUF: So here on slide eight on the far 11 left-hand side of the screen is a zoomed in image of 12 the Moraine oil pool log data with the same layout as 13 the previous slide just closer up. And right away 14 you'll notice several coursing upward sequences and 15 they're very subtle so they're basically the length -- 16 the size of my laser dot there, just really tiny and 17 several little ones in there. And there's pretty much 18 a lack of major block signatures, things you might 19 interpret to be channels for example. And considering 20 these observations we interpret much of the Moraine oil 21 pool section to be thinly bedded turbidite deposits, 22 interbedded -- with interbedded sandstones, siltstones 23 and mudstones. We interpret that a shelf edge delta 24 supplied sediment which was transported down several 25 slope gullies, that's kind of referring to what I 24 1 mentioned earlier, and so as the sediment comes down in 2 those slope gullies it goes out into the basin slope 3 and the basin floor. 4 Illustrating the gross depositional diagram is 5 a 3D block diagram there in the lower right hand corner 6 of the screen. It's from work modified by -- excuse 7 me, it's from -- it's modified from work published by 8 Ford in 2002. So the block diagram illustrates a delta 9 sediment source that supplies sediment to multiple 10 slope gullies there out into the basin. And as you can 11 see in this model it's more of a line source 12 depositional model instead of the traditional point 13 source model as we often see in the literature for 14 turbidite. So that means there's multiple sediment 15 sources moving out into the basin instead of just one 16 big canyon or maybe two big canyons. So in the -- the 17 line source style of deposition explains much more of 18 our observations that we see in the log data including 19 the lack of major blocky signatures like I mentioned 20 earlier. 21 Now highlighted there on the -- with the gray 22 so the curly bracket and the accompanying star on that 23 same figure is the interpreted setting within the 24 depositional environment I just described for deposits 25 that are in the Kuparuk River unit for the Moraine oil 25 1 pool outline. 2 The beds for the Moraine oil pool are 3 interpreted to be locally continuous sheet like 4 deposits developing layered low complexes due to the 5 unconfined nature of the flow moving out and away from 6 the slope gullies. And in our area of interest we are 7 at a distance from the paleo shelf and the paleo slope 8 interface, probably penetrating a little bit more 9 distal turbidite deposits. Based on core and log data 10 individual beds range in thickness from less than an 11 inch to a few feet. The reservoir is mostly very fine 12 grained sand or silt and the beds are interpreted to be 13 laterally continuous on a local scale, roughly 100 to 14 2,000 feet. It's very difficult to correlate 15 individual beds or packages between wells. And as one 16 might predict given the depositional environment we 17 expect poor vertical permeability through the Moraine 18 oil pool due to the interbedded mudstones that are also 19 apparent on log and -- core and log data as you'll get 20 a chance to see here in a couple of slides. 21 Slide nine explains in more detail the rock 22 properties of the Moraine oil pool and for your 23 reference that same 3D block diagram is -- from the 24 previous slide is there on the lower right-hand side of 25 the screen. Included in this slide is an outcrop photo 26 1 on the left to kind of help you better visualize what 2 distal tubidites might look like in outcrops. So this 3 is a photo that's interpreted to be a series of distal 4 turbidite deposits much like what we might expect for 5 the Moraine oil pool. And for scale if you look at 6 that lower most prominent bed here up to the upper most 7 prominent bed that's about 10 to 15 feet. 8 For the Moraine oil pool the sandstones are 9 typically comprised of 50 to 70 percent quartz, 1 to 10 10 percent feldspar, 15 to 30 percent lithic fragments 11 which are dominantly metamorphic with minor detrital 12 clay and organic debris and that will classify it more 13 as a (indiscernible). The mudstones are dominated by 14 clay minerals, mainly illite with minor amounts of 15 smectite, chlorite and kaolinite. Based on core data 16 gross sand content increases up section from 30 -- 17 well, sand content varies between 30 and 60 percent and 18 sand content increases generally up section from the 19 lower Moraine member up to the upper Moraine member. 20 Porosity values from core data range from 15 to 28 21 percent with an average of 19 percent. Air 22 permeability values also from core data range from half 23 a millidarcy to 93 millidarcies with an average of 24 about five millidarcies. Water saturation values range 25 from 30 to 85 percent. And for a local comparison the 27 1 Moraine oil pool deposits are analogous to peripheral 2 Tarn deposits in terms of net to gross. 3 You know and luckily we have a better 4 understand of the Moraine oil play thanks to the core 5 we collected last year on Moraine 1. And on the next 6 slide I'll give you -- you'll see a closeup of that 7 core and you can see the individual beds. 8 COMMISSIONER SEAMOUNT: Where was that picture 9 taken in California? 10 MS. UMLAUF: You know, I'm not sure. That's a 11 photo taken by Dr. Brian Romans of Virginia Tech. And 12 I know it's of the Great Valley group in California, 13 but I'm not quite sure. 14 COMMISSIONER SEAMOUNT: I wonder if the beach 15 is just to the left. 16 MS. UMLAUF: Yeah, could be. 17 COMMISSIONER SEAMOUNT: I think I've been 18 there. 19 UNIDENTIFIED VOICE: (Indiscernible) on the 20 road. 21 COMMISSIONER SEAMOUNT: Yeah, you have to walk 22 across the road to the beach. 23 MS. UMLAUF: So slide 10 is pretty much the 24 same as the previous slide except now we have a closeup 25 view of the reservoir. This photo on the left is from 1 Moraine 1, it's approximately 18 feet of core. And, 2 you know, when shown under UV light as it is here you 3 can start to see the thin, interbedded deposits of 4 sandstone, siltstone and mudstone. It shows up better 5 on your slides I hope. And this core is available for 6 Commissioners and the AOGCC technical staff to view if 7 you're interested in seeing more of the reservoir, just 8 contact Kasper after the hearing and we can arrange for 9 a viewing. But you can get -- from the photo you can 10 start to get a feel for the variability and rock it properties, you know, the thicknesses of the individual 12 beds there and how vertical permeability is probably 13 low due to the interbedded mudstones. Also in this 14 photograph you'll notice one foot pieces of whole core 15 are missing and those samples were collected for 16 geomechanical work that Kasper will discuss in more 17 detail later in the presentation. 18 Now considering a region view slide 11 is a 19 structural map for the top of the pool. The 20 corresponding marker is highlighted by that dark gold 21 line on Palm 1 there to the left. On your slide hot 22 colors are highs and cooler colors are lows. The top 23 of the pool ranges in depth between 4,940 feet below 24 sea level and 5,880 feet below sea level and it 25 generally dips to the southeast. 29 1 This structure map also illustrates the general 2 flexure over the Colville high and the Colville high is 3 a broad, southeast plunging anticline that developed 4 much of its current configuration after the deposition 5 of the Moraine oil pool. 6 That kind of leads us into the trapping 7 mechanism. So as has been eloquently stated by a 8 publication from Hudson, et al. in 2006, they describe 9 the Colville high as a much larger and broader 10 structure in the overall Moraine oil pool accumulation. 11 And therefore we interpret there's a significant amount 12 of stratigraphic trapping controlling the location of 13 the oil accumulation along the Colville high. This 14 interpretation of a combined trap is also consistent 15 with the interpretive depositional environment where a 16 turbidite rich reservoir is bounded along the edges by 17 the paleo slope to the west which in our case is right 18 about here and distal mudstone deposits to the south 19 and east as you might remember from that 3D block 20 diagram there as you get away from the sediment 21 sources. 22 And recalling from the opening geologic slide, 23 slide seven, the Moraine oil pool is capped by 24 prograding slope deposits of mudstones and siltstones 25 that makeup the rest of the Torok formation. Also 30 1 shown on this map in bold black lines are the 2 interpretive faults from seismic data projected through 3 the Moraine oil pool from offset on the HRZ. And the 4 HRZ if you remember there on the log is below the 5 Moraine oil pool. You know, however only a subset of 6 these faults offset the top of the pool. We interpret 7 offset in the HRZ to define fault locations because 8 it's a reliable seismic event, with the understanding 9 that not all these faults propagate up to the pool and 10 to the top of the pool. But with that in mind the 11 general structure style suggests we have two dominant 12 sets of normal faults in the proposed development area. 13 So there's an early cretaceous and a west/northwest to 14 east/southeast striking set and there's a younger 15 cenozoic north/northeast, south/southwest striking set. 16 17 Many of the interpreted faults have very little 18 offset and just to reiterate, only a subset of these 19 faults offset the top of the pool. Based on our 20 current seismic data the faults that may offset the top 21 of the pool very quickly terminate into the lower Torok 22 formation. Even the largest amount of offset 23 interpreted which can be as much as 60 feet in the 24 north is not enough to completely offset the gross 25 thickness of the Moraine oil pool as you'll see in the 31 1 next slide. Due to the thinly bedded nature of the 2 reservoir and the amount of mudstone in the system, the 3 faults may disrupt bed continuity if present, but 4 should minimally impact intended development plans. 5 Similar styles of faulting and throw affect other 6 reservoirs in the Kuparuk River unit to a much greater 7 degree than we see here, but none of the faults in the 8 other reservoirs have significantly impeded 9 development. 10 Slide 12 shows the Moraine oil pool isochore 11 which is the interval highlighted there in yellow on 12 the Palm 1 image to the left on your slide. Hot colors 13 are thicks and cooler colors are thins. The total 14 proposed Moraine oil pool thickness varies from 60 to 15 640 feet and you can see how the Moraine oil pool 16 gradually thins towards the south and into the east 17 away from the paleo slope looking at that grid. You'll 18 also notice based on our current interpretation the 19 projected faults do not have a significant impact 20 during the time of deposition for the Moraine oil pool. 21 To reiterate there's a -- the gross thickness of the 22 total pool is much larger than the interpreted 23 (indiscernible) of these faults that may intersect the 24 Moraine oil pool. 25 Slide 13 has a structural well cross section 32 1 going from west to east, essentially from the 3S area 2 over to the 3A area which is outside of our proposed 3 area. And the logs shown here are gamma ray going from 4 zero to 180 gamma ray API units followed by TVD subsea 5 in feet, measured depth in feet and then resistivity 6 going from one to 100 ohm meters. Both the shallow 7 resistivity which is in gray and the deep resistivity 8 which is in black are posted here. Marker tops are the 9 solid black lines for the top and base pool, denoted 10 there is the top upper Moraine and the top HRZ with the 11 lower Moraine member marker as a dashed line in black. 12 And like we saw from the isochore the package thins to 13 the east away from the paleo slope. Indeed even as we 14 exit the boundary denoted by that red dashed line on 15 the image you can see how as you move out the upper 16 Moraine member is nearly indistinguishable from the 17 lower Moraine member. And there's also a thick package 18 above and below the Moraine oil pool trapping the 19 accumulation. 20 COMMISSIONER SEAMOUNT: Ms. Umlauf, it looks to 21 me like the upper Moraine and the lower Moraine 22 constitute the entire Torok formation; is that correct? 23 MS. UMLAUF: No, we don't believe that. 24 COMMISSIONER SEAMOUNT: You don't believe that? 25 MS. UMLAUF: No. So above here..... 33 • • 1 COMMISSIONER SEAMOUNT: Okay. So..... 2 MS. UMLAUF: .....if you were..... 3 COMMISSIONER SEAMOUNT: Okay. You go above 4 there and there's a shaley section of Torok. Okay. I 5 gotcha. 6 MS. UMLAUF: Yeah. Correct. So above that 7 upper Moraine marker there, that's all the rest of the 8 Torok formation and it's even out of view so if you 9 look back to your reference, Palm 1 image there, you 10 see it goes up to the Hue shale..... 11 COMMISSIONER SEAMOUNT: Okay. 12 MS. UMLAUF: .....which that's not visible on 13 this cross section. 14 So slide 14 has another structural well cross 15 section going from north to south, starting north of 16 the 3M area and then south towards 2T. The well layout 17 is the same as the previous slide. And again you'll 18 notice how the Moraine oil pool thins to the south away 19 from the paleo sediment sources. And even on log data 20 the upper Moraine member again here is nearly 21 indistinguishable from the upper -- the lower Moraine 22 member, excuse me, in the south towards 2T. Also like 23 we saw on the previous cross section there's still a 24 thick package above and below the Moraine oil pool 25 trapping the accumulation. in 1 I appreciate your attention and thank you for 2 your time. So as long as there's no further questions 3 I will pass the presentation over to Adam Lewis who 4 will discuss the resource and recovery which is 5 starting on slide 15. 6 COMMISSIONER SEAMOUNT: Have you done any 7 calculations on net pay in these wells? 8 MS. UMLAUF: We have. We are also in the 9 process of updating our net pay mess. 10 COMMISSIONER SEAMOUNT: What resistivity cutoff 11 -- do you use a resistivity cutoff? 12 MS. UMLAUF: No, we do not. 13 COMMISSIONER SEAMOUNT: Okay. How do you do it 14 then? 15 MS. UMLAUF: So for net pay we rely on 16 calculated logs. So we mostly look at total porosity 17 which is a calculated log as well as water saturation. 18 COMMISSIONER SEAMOUNT: Uh-huh. 19 MS. UMLAUF: And water saturation depending on 20 the model is somewhere between 50 and 75 percent of the 21 cutoff. And total porosity is greater than 15 percent 22 and that does a pretty good job identifying pay in this 23 area. But, you know, we're dealing with a very thin 24 bedded environment, you know, beds are seven..... 25 COMMISSIONER SEAMOUNT: Right. 35 1 MS. UMLAUF: .....so they're below the 2 resolution so you need to do some advanced -- I would 3 say advanced modeling. 4 COMMISSIONER SEAMOUNT: So do you see any 5 potential in the lower Moraine? 6 MS. UMLAUF: That's something we'd like to 7 evaluate. 8 COMMISSIONER SEAMOUNT: Okay. You're still in 9 the process? 10 MS. UMLAUF: Uh-huh. 11 COMMISSIONER SEAMOUNT: Okay. And I assume 12 you'd be using long horizontals of big frack jobs to 13 the lower Moraine? 14 MS. UMLAUF: Most likely. 15 COMMISSIONER SEAMOUNT: Okay. Thank you. 16 CHAIR FOERSTER: All right. So introduce 17 yourself, who you represent and what area you want to 18 be recognized as an expert in and what your credentials 19 are. 20 MR. LEWIS: Hello, Commissioners. My name is 21 Adam Lewis and I'm a reservoir engineer for 22 ConocoPhillips. I've been a reservoir engineer for 23 ConocoPhillips since 2007 working in Alaska in areas of 24 reservoir management, reservoir surveillance, 25 simulation and field development planning. I hold 36 1 bachelor of science degree and master of science degree 2 in petroleum engineering, both from Louisiana State 3 University. And I am known to this Commission, I've 4 testified as an expert witness before. 5 CHAIR FOERSTER: Commissioner Seamount, do you 6 have any questions? 7 COMMISSIONER SEAMOUNT: Where'd you go to 8 school, Mr. Lewis? 9 MR. LEWIS: Louisiana State University. 10 COMMISSIONER SEAMOUNT: Okay. I have no it further questions, comments or objections. 12 CHAIR FOERSTER: I have no comments, questions 13 or objections so please proceed and we'll recognize you 14 as a reservoir engineering expert. 15 MR. LEWIS: Thank you. 16 ADAM LEWIS 17 previously sworn, called as a witness on behalf of 18 ConocoPhillips Alaska, testified as follows on: 19 DIRECT EXAMINATION 20 MR. LEWIS: Moving on to slide 16. This slide 21 explains ConocoPhillips' development plans for the 22 Moraine oil pool. The figure on the left is a map 23 showing the existing well penetrations in the Moraine 24 oil pool and the surrounding wells in the Kuparuk oil 25 pool to the east. The Moraine oil pool boundary is 37 1 listed in red or is labeled in red on your slides, it's 2 a -- looks like a black line on these slides, but it's 3 been explained to the Commissioners before by Kelly and 4 Kasper. 5 The Moraine oil pool will be developed in a 6 phased development approach initiating from existing 7 infrastructure and this will allow us to apply 8 knowledge gained from previous development phases to 9 the new development as we move forward. The initial 10 targets for the Moraine will be access from the 3S 11 drill site and future targets may be accessed from a 12 new drill site to the northeast or southwest of 3S if 13 initial production is successful. The Moraine oil pool 14 will employ a horizontal line drive development 15 utilizing an immiscible water alternating gas or IWAG 16 flood. We'll preserve the option to convert to an MWAG 17 flood in the future or a rich gas flood to enhance 18 recovery further from the reservoir. More details 19 about the flood will be discussed shortly. 20 All the wells including the injectors will be 21 hydraulically stimulated to enhance productivity and 22 injectivity and also improve vertical conformance. 23 We'll discuss the completion design and well 24 stimulation details as it pertains to containment 25 assurance later in this presentation. 1 Most of our wells will trend to the northwest. 2 This is along the maximum principal stress direction as 3 we learned from 3S-19 Tiltmere that we acquired in 4 2013. The wells range from 3,000 to 8,000 feet in 5 length within the reservoir and will be arranged in end 6 to end rows to form a line drive pattern. They'll 7 alternate between producer rows and injector rows. And 8 the flood will be maintained with an IW of 9 approximately one. So that means we'll replace every 10 barrel of oil, water and gas that we produce from the 11 reservoir with an equivalent volume of fluid at 12 reservoir conditions. And this will maintain reservoir 13 pressure and optimize recovery in the field. 14 Moving on to slide 17. This slide explains in 15 further detail the development plan for the Moraine oil 16 pool. The map on the left shows the near term 17 development plans for ConocoPhillips in the Moraine oil 18 pool, highlighting the different phases of development 19 for the Moraine oil pool. These development plans may 20 shift as we acquire new information, but the near term 21 wells that we've mentioned already are highlight here 22 on the upper left corner. They include the 3S-613, the 23 3S-620 and then five additional phase two wells in the 24 northwest corner. Longer term development that's still 25 under evaluation again includes an additional drill W • • 1 site that would be accessing phase three resources, 2 phase four resources that could also be accessed from 3 Kuparuk wells or that additional drill site. 4 Initial studies would suggest that a 1,500 foot 5 well spacing is optimal assuming we get a modest 6 secondary response. That may change as we learn how 7 these wells respond to injection support. our initial 8 well pair, 3S-613 and 3S-620, will be critical in 9 determining well spacing and well length as we go 10 further in the Moraine development. 11 Going forward the primary uncertainties in the 12 development of the Moraine oil pool are the lateral 13 continuity of the thin sand beds, vertical connectivity 14 achieved by the fracture stimulation treatments and the 15 affective displaceable core volumes by our injection 16 wells. However we do have extended production test 17 results from both the 3S-19 and the 3S-620 wells that 18 do or at least are -- that are consistent, excuse me, 19 with laterally productive sands over the development 20 spacing of 1,500 to 2,500 feet. So this is the -- this 21 is -- all future development wells will be drilled 22 inside this well spacing. 23 The Moraine oil pool properties are summarized 24 in the table on the right. And for reference all these 25 properties are referenced 5,000 TVD subsea depth. 40 1 Initial reservoir pressure is approximately 2,260 psi, 2 the temperature's about 140 Fahrenheit and the gas/oil 3 ratio's about 425 scuffs per barrel. The saturation 4 pressure or the pressure at which gas liberates from 5 the oil is approximately 2,130 psi. This is just below 6 the initial reservoir pressure and this -- that data 7 combined with the viscosity data of two and a half 8 centipoise that was critical in determining that we 9 needed to implement a flood to improve recovery well 10 above primary depletion. We just don't expect much 11 from this reservoir on primary depletion with those 12 kind of oil properties. 13 The table on the lower right shows the 14 development plan summary as well as the oil in place 15 that we expect to access, the wells counts and the 16 expected recovery efficiency. The area around drill 17 site 3S we expect to access between a hundred and 500 18 million stocktank barrels of oil in place and require 19 10 to 40 wells to develop. An additional drill site 20 could access as much as 300 million stocktank barrels 21 in place and require an additional 14 to 28 wells to 22 develop. Both of these areas we expect to achieve 23 recovery factors in the order of 10 to 40 percent and 24 I'll explain where that range comes from here on the 25 next slide. 41 1 Now on to slide 18. This slide explains the 2 estimated recovery efficiency from the previous slide 3 as it refers to the Moraine oil pool with the various 4 drive mechanisms that will be utilized. The figure on 5 the top left refers to waterflood recovery and is shown 6 as a plot of waterflood recovery, as a percent of oil 7 in place versus the hydrocarbon core volumes of water 8 injected on the X axis. The plot on the lower left 9 refers to gas injection recovery efficiency and is 10 plotted as a incremental recovery from gas injection 11 above waterflood as a percent of oil in place versus 12 the hydrocarbon core volumes of total fluid, both water 13 and gas, injected. There are four scenarios on the 14 lower left plot, one for immiscible water alternating 15 gas and then for three varying -- and then three more 16 for three variations of Kuparuk MI. 17 So first at a very small physical scale we have 18 the USBM wettability test data. This is from the 19 Colville Delta 3 well and that indicates the waterflood 20 recovery can be expected to be in the range of 24 to 56 21 percent of original oil in place. This represents 22 approximately a 20 to 50 percent incremental over 23 primary depletion alone however since the Moraine is a 24 highly layered system with varying permeability and 25 poor vertical permeability, we can't expect this kind 42 1 of recovery efficiency to be encountered at the field 2 scale. So if you look on the top left this plot is a 3 model result from the simulation model constructed for 4 the Moraine oil pool and indicates that we can expect a 5 recovery efficiency of about 10 to 30 percent of 6 original oil in place from waterflood. This represents 7 a 5 to 25 percent incremental recovery from waterflood 8 over primary depletion alone. 9 Moving on to gas injection -- well, first let 10 me state that to achieve that high end of the recovery 11 range note that we would have to cycle the core volume 12 more than twice with the water. So certainly we don't 13 expect that in every single pattern, but our more 14 productive patterns might achieve those numbers. 15 Moving on to gas injection the figure on the 16 lower left indicates that IWAG would yield an 17 additional 1 to 5 percent of original oil in place 18 above waterflooding alone. While any level of rich gas 19 injection would yield up to 15 percent of original oil 20 in place. When you compare these numbers to Tarn and 21 Kuparuk we're very much in the same range. Tarn ranges 22 from 8 to 15 percent of oil in place from MWAG and 23 Kuparuk ranges from 2 to 10 percent of original oil in 24 place from MWAG. So basically what we're expecting is 25 that MWAG and IWAG will perform very similarly in the 43 • • 1 Moraine as they have in other fields that we operate. 2 So in conclusion for the recovery efficiency 3 we, ConocoPhillips, plan to implement an IWAG flood 4 with the option to convert to an MWAG flood in Moraine. 5 Basically we intend to inject the richest gas that we 6 have available and this will improve recovery 7 significantly over primary depletion for waterflooding 8 and gas injection will improve recovery efficiency 9 above waterflood substantially as well. And we..... 10 CHAIR FOERSTER: Why is the Tarn percentage -- 11 incremental percentage greater than the Kuparuk 12 incremental, timing? 13 MR. LEWIS: Timing and also oil quality and the 14 fact that the injectant for Tarn is actually more 15 miscible or better injectant than it needs to be since 16 we only have one blending source available. 17 CHAIR FOERSTER: Thank you. 18 MR. LEWIS: Okay. That's all I have on this 19 slide. Next slide, please. 20 Now on to slide 19. This slide explains the 21 regional pressure data collected from wells in the 22 Moraine oil pool and the plot on the bottom shows 23 pressure data that has been filtered to be most 24 applicable to this discussion. I've colored the data 25 points on your slides, not on the screen here, but I've 44 s 1 colored the data points in a blue and green to 2 represent those points believed to be on a regional 3 water gradient, those in blue, and a regional oil 4 gradient, those in green. This data comes from the 5 Ivik number 1 well, Oooguruk number 1 and Moraine 6 number 1. The Ivik number 1 and the Oooguruk number 1 7 plot in blue on your slides and are on a regional water 8 gradient. The Moraine 1 plots in green on your slides 9 and is a regional -- represents a regional oil 10 gradient. In petroleum science a free water level can 11 be estimated by drawing a line through points known to 12 be on an oil gradient and those points known to be on a 13 water gradient. The intersection of those lines can be 14 used to estimate a free water level. When this method 15 is applied to Moraine we get a free water level between 16 5,190 on the top here on this black dash line and 17 5,275. The uncertainty -- 5,275 TVD subsea to be 18 specific. The uncertainty in this estimation can be 19 due to a number of things, measurement error, offset 20 production injection affects, temperature variation in 21 the wells and/or layered, intermingled oil and water. 22 This layering or intermingling of oil and water is not 23 uncommon in turbidite systems that have low 24 permeability -- low vertical permeability, excuse me, 25 and when you combine this phenomena with capillary 45 • • 1 forces you can easily get in the situation where you 2 have oil beneath water or water above oil or the 3 appearance of multiple oil/water contacts in this kind 4 of data. 5 So in conclusion there is mobile water present 6 in the Moraine oil pool beginning at a depth of 5,190 7 to 5,275 TVD subsea. This may take the form of a 8 single contact, multiple contacts or transition zone, 9 we just don't have enough data to tell at the moment. 10 And all of this is roughly on the eastern boundary of 11 the Moraine oil pool as defined by Kelly and Kasper 12 earlier. However this does not mean that no flow of 13 hydrocarbons will exist below this depth range, we just 14 don't have enough data at this point in time. 15 So with that if there are no further questions 16 I'll turn it over to Kasper. 17 MR. KOWALEWSKI: Hello, this is Kasper 18 Kowalewski again. I'll finish the information more 19 relevant for the Moraine oil pool application and then 20 transition over to the AIO application more relevant 21 information. I'll reference a few regulations which 22 are all under 20 AAC 25. To avoid redundancy I'll just 23 verbalize the sections instead of the entire 24 regulations. 25 Here on slide number 21 is the summary of the 46 1 anticipated well design of the Moraine oil pool wells. 2 These wells will be drilled from gravel pads utilizing 3 drilling procedures, well designs and casing and 4 cementing procedures that are consistent with current 5 practices in other North Slope fields and follow AOGCC 6 regulations with the exception of the proposed Moraine 7 oil pool rules. The figure on the right illustrates 8 the generic Moraine produce well schematic which will 9 be similar to the planned injectors. 10 A few topics or a few notes for this particular 11 figure. As the regulations require cement to surface 12 on the surface casing, for the production casing cement 13 to 500 feet measured depth above known hydrocarbon 14 bearing zones and then also isolation from the open 15 intervals via a packer or a liner hanger in this 16 particular case. 17 Based on the current knowledge of the reservoir 18 characteristics, ConocoPhillips Alaska expects to 19 develop the Moraine oil pool using horizontal wells 20 with solid liners including pre -perforated puffs and/or 21 sliding sleeves and external swell packers to 22 facilitate stage hydraulic fracture stimulation 23 treatments. You'll also notice in this figure we do 24 have four and a half inch tubing and that is for both 25 the injectors and producers as Adam mentioned earlier 47 1 for the hydraulic stimulation to facilitate it. 2 However that tubing as well as in general the tubulars, 3 they may change depending on well performance as well 4 as we get more information on the reservoir. 5 Speaking of the hydraulic stimulation 6 operations they will be performed in accordance with 7 section 283 with emphasis on the execution of hydraulic 8 stimulation operations in a safe manner as to avoid 9 harm to personnel and to the environment. All wells 10 will demonstrate competent barriers to prevent any 11 uncontrolled fluids from the wells. Wells which cannot 12 demonstrate competent barriers will not be 13 hydraulically stimulated and will be shut-in. All 14 fluid formulations used in hydraulic stimulation 15 operations are included in Frack Focus and are publicly 16 available. 17 Here on slide number 22 the facilities are 18 discussed. The Moraine oil pool will be initially 19 developed from the existing KRU drill site 3S as Adam 20 mentioned which is connected to the KRU central 21 processing facility, CPF 3. Here on the lower right is 22 an image, an aerial view, of the 3S drill site. Upon 23 successful development from the 3S drill site as Adam 24 mentioned additional drill sites may be added which 25 will be connected to the established Kuparuk M. 0 1 infrastructure. 2 There are two main reasons that we targeted the 3 3S drill site for the initial Moraine development, the 4 first being that we're able to target the Moraine 5 reservoir from the surface facilities, from 3S, the 6 second being that the infrastructure is already in 7 place and established to CPF 3. The economic 8 development of the Moraine oil pool is contingent upon 9 the utilization of these facilities. The 3S drill site 10 specifically is designed to accommodate 26 wells on 20 11 foot centers. Currently out of those 26 wells 17 are 12 being used for Kuparuk producers or injectors. The 13 individual well lines commingle into common headers 14 that feed into the cross country pipe lines for 15 transport to CPF 3. The Moraine oil pool production 16 will be commingled with production from other Kuparuk 17 River field oil pools and tract operations in the 18 surface facilities, however there will be no 19 commingling down -hole. 20 Each production well connects to the drill site 21 test header which flows through the test separator 22 module on the pad. This test separator provides two 23 phase separation and measures flow rates of the gas and 24 liquid phases. The liquid stream passes through a 25 Phase Dynamic meter to determine the oil/water split of 49 1 the liquid. Testing can take place remotely through a 2 divert valve system which redirects the flow from the 3 production header to the test separator. 4 Here on slide number 23 I'll discuss the 5 Kuparuk gathering system a little bit more in detail 6 and then I'll discuss the production allocation for the 7 Moraine oil pool. 8 So on this figure the upper left corner has the 9 CPF 3 image that we're going to be focusing on. CPF 3 10 takes the well production from the ConocoPhillips 11 operated drill sites and the Oooguruk offshore island. 12 So here in the upper portion of the drill sites the 13 Oooguruk island is shown right here which is just above 14 the center of the figure. CPF 3 separates the fluids 15 into wet oil, gas and waterstreams. The wet oil is 16 then sent to CPF 1 and 2 so 1 and then 2, for further 17 processing to reach sales quality. Gas is dehydrated 18 and compressed for artificial lift and fuel gas to 19 support the facility. Produced water pressure is 20 boosted and used for waterflooding. Additionally CPF 3 21 has two seawater injection pumps which are in the upper 22 left-hand corner of the figure. These are used for 23 injecting seawater into the reservoir for pressure 24 maintenance and for waterflooding. 25 Production for the Moraine oil pool will be 50 1 measured with equipment in accordance with section 228. 2 Production will be allocated to producing wells based 3 on the actual plant oil sales volume and well tests on 4 individual producing wells. The well tests will be 5 used to create performance curves to determine the 6 daily theoretical production from each well. The CPF 3 7 allocation factor will be applied to adjust total 8 production from the associated drill sites. 9 ConocoPhillips Alaska does request that the 10 requirements described in regulation section 230(a) be 11 waived. I'll discuss that a little bit further when we 12 go through the proposed Moraine oil rules. 13 Here on slide number 24 I'll start to cover 14 information which is more relevant to the area 15 injection order application. I'll specifically focus 16 on the planned injection fluids, the compatibility of 17 those injection fluids, the injection pressures as well 18 as evidence to support that the injection wells will 19 not initiate or propagate any fractures through the 20 confining zones. 21 We'll start with the proposed injection fluids. 22 These fluids have been broken up into two categories, 23 the first being fluids for continuous injection as a 24 means for enhanced recovery. The second grouping are 25 wells that are not used for continuous injection as a 51 • 0 1 means for enhanced recovery, instead they are just 2 periodic injection. In that second grouping of fluids 3 the volumes of the fluids are expected to be less than 4 0.1 percent of the total volume injected and are not 5 expected to hinder the recovery efficiency of the 6 proposed Moraine oil pool. 7 Back to the first grouping of fluids. The 8 first two sub -bullets are related to waterflooding. As 9 Adam mentioned earlier waterflooding will be 10 implemented as the initial enhanced recovery mechanism 11 for the proposed Moraine oil pool with the use of 12 either seawater or produced water. We plan to either 13 use source water from the Kuparuk seawater treatment 14 plant or produced water from CPF 3. Additionally 15 waterflooding will be followed later with either lean 16 gas or miscible gas injection to further improve 17 recovery which are the last two sub -bullets in that 18 first grouping. 19 Now on to that second grouping of injection 20 fluids, the first fluids used during hydraulic 21 stimulation. Again the hydraulic stimulation 22 operations will be performed in accordance with section 23 283. The second, tracer survey fluids, to monitor 24 reservoir performance. These will include tracer 25 fluids used during they hydraulic stimulations as well 52 1 as tracer fluids used later in the life of the wells to 2 determine well interactions. Third, fluids used to 3 improve near wellbore injectivity via use of acid or 4 similar treatment. Fourth, fluids used to seal 5 wellbore intervals which negatively impact recovery 6 efficiency, for example, cement, resin. Fifth, fluids 7 associated with freeze protection such as diesel, 8 glycol or methanol. The sixth and last, other standard 9 oil field chemicals such as corrosion and scale 10 inhibitors and emulsion breakers. 11 Here on slide number 25 I'll discuss the 12 injection fluid compatibilities. Although the Moraine 13 reservoir has a high clay content, the majority of the 14 clay occurs in laminar sheets between the reservoir 15 sandstone beds where fluids for enhanced oil recovery 16 will be injected. Dispersed clay in the sandstone 17 layers is not prone to swelling when in contact with 18 the typical injection water salinities expected to be 19 used in the Moraine oil pool. Analyses of formation 20 water samples collected from the Moraine producers 3S- 21 19 and 3S-620 indicate the potential for moderate 22 scaling during production and when the formation water 23 mixes with seawater. The specific scale risks are 24 listed in that second bullet point. 25 For CPF 3 produced water injection barium 53 1 sulfate and calcium carbonate may form, however scale 2 risks are minimized as the injection water goes deeper 3 into the formation. For CPF 3 seawater injection if no 4 mitigation measures are implemented barium sulfate risk 5 is high from the wellbore throughout the mixing zone 6 and calcium carbonate risk is minor in the reservoir 7 beyond the near wellbore area. However scaling 8 mitigation measures will be used and they include 9 placement of fluid and solid phase scale inhibitors and 10 fracture treatment, conventional squeeze treatments and 11 chemical injection in the wells at the surface. 12 Specifically scale inhibition at CPF 3 will be 13 optimized and a chemical skid for scale inhibition will 14 be used at 3S. The analyses of the formation of water 15 samples listed indicate that the scale risk is expected 16 to be controlled utilizing these measures. Field 17 injectivity data from the periphery Tarn which is an 18 analogous fine grain turbidite reservoir in the Kuparuk 19 River field suggests limited permeability degradation 20 will occur when properly treated -- when injection 21 fluids are properly treated. 22 No compatibility issues between Kuparuk River 23 field injection gas and Moraine reservoir fluids have 24 been identified. Fluids used for hydraulic stimulation 25 are planned to include a mixture of water, freshwater, 54 0 • 1 seawater or produced water. Gelling agents added to 2 make the fluid thicker and slicker and larger grain 3 ceramic sands to improve and sustain conductivity 4 within the fracture through the life of the well. 5 Hydraulic stimulation formulations may be adjusted as 6 new technologies emerge and as the reservoir 7 characterization is further defined. 8 Here on slide number 26 I'll review some of the 9 information Kelly shared as it relates to the confining 10 intervals. Looking at the log on the right we'll start 11 from the bottom and go up. So our lower confining 12 interval is the HRZ which is approximately 100 to 150 13 feet thick in the proposed AIO and pool area. Above 14 the HRZ are proposed -- is where our proposed pool is 15 and it extends from the HRZ to the top of the Moraine 16 marker. As Kelly mentioned it is one coursing up 17 package of turbidite deposits identified by seismic and 18 well data. Above that is the upper confining interval 19 which extends from the top of the Moraine to the top of 20 the Torok. This upper confining interval is comprised 21 of marine siltstone and mudstone slope deposits. The 22 total thickness varies from 250 feet to 1,000 plus 23 feet. Above the upper confining interval is the Hue 24 shale which is approximately 300 feet to 1,000 plus 25 feet thick and consists of claystones and tuffaceous 55 • 1 mudstones. 2 Slide number 27 further describes the confining 3 zones, specifically this slide reviews the 4 geomechanical analysis conducted by ConocoPhillips. 5 The figure on the right shows the modeled effective 6 block strength of the Palm 1 in pound per gallon 7 equivalent as compared to the gamma ray. So on the 8 schematic in your slides the effective rock strength is 9 more of a blue, here it looks a little more like the 10 orange and it varies between 10 to 20 ppg. The gamma 11 ray is on the left and it ranges from zero to 200 gamma 12 ray API. on the far right we have the major interval 13 divisions which were just discussed on the previous 14 slide. Highlighted in the orange on your slides which 15 in here it doesn't seem like it's coming up, is the 16 equivalent stratigraphy that was sampled in the Moraine 17 1 core for geomechanical analysis. There are 29 18 samples in Moraine 1 ranging from depths of 5,100 feet 19 measured depth to 5,295 feet measured depth. That 20 depth range includes samples in the overburden from the 21 shale interval directly on top of the Moraine oil pool. 22 The tests conducted on the samples include triaxial 23 compression tests, unconfined compression tests and a 24 fracture toughness test. 25 Young's modulus and Poisson's ratio values 56 1 obtained from the test were used to calibrate the 2 strength curves calculated from the advanced logging 3 conducted on Moraine 1. The calibrated curves align 4 with the actual leak -off test result from the 3S-620 5 which is signified by a red dot on your slides and more 6 of an orange dot here on the overhead. A leak -off test 7 value of 13.5 ppg from 35-620 fits on the predicted 8 curve. Of note is that the predicted strength of the 9 Moraine oil pool is lower than that of the overburden. 10 The results from the geomechanical analysis indicate a 11 confining barrier above the Moraine oil pool. For the 12 Moraine oil pool the overburden was cored to calibrate 13 the strength curves. This data was critical in 14 determining the injection pressure limits and 15 estimating the fracture heights determined for the 16 Moraine oil pool. 17 Here on slide number 28 I will summarize the 18 frack and containment modeling. The three upcoming 19 slides will illustrate the results of three simulation 20 scenarios. A containment assurance analysis conducted 21 by ConocoPhillips indicates that the estimated maximum 22 injection pressures for the Moraine wells in water or 23 gas injection service which are covered on an upcoming 24 slide will not initiate or propagate fractures through 25 the confining strata and therefore will not allow 57 1 injection or formation fluid to escape the Moraine oil 2 pool interval. 3 In addition to this analysis ConocoPhillips 4 Alaska has implemented a subsurface containment 5 assurance standard for each pool which includes a 6 periodic containment review with a multi -disciplinary 7 team consisting of geology, geophysics, drilling, 8 reservoir production, well integrity and operations 9 personnel. 10 Back to the containment assurance analysis. it The three scenarios evaluated are water injection in a 12 non-fracked well, water injection in a fracked well and 13 MI injection in an unfracked well. The analysis 14 involved the use of a frack model built based on 15 Moraine 1 log well data and calibrated by using data 16 from core sample geomechanical tests and pressure 17 history match data from the 3S-620 frack results. The 18 simulations of the hydraulic fracturing stages and long 19 term water injection cases were run and indicate that 20 fracture growth is contained within the Moraine oil 21 pool without risk of breaking through the confining 22 zones. 23 Here on slide number 29 I will summarize the 24 results from the containment assurance analysis as it 25 relates to scenario one which is water injection from a W: �J • 1 horizontal well without a propped fracture. In other 2 words water injection without a frack. 3 For the upcoming three slides the labels are 4 going to be very similar so I'll define them for this 5 slide and for the upcoming ones just where I need to 6 I'll define them. It's a little bit probably easier to 7 see on the slides that were submitted as opposed to the 8 overhead, but on the left-hand side to the left Y axis 9 we have the shale to sandstone ratio as a reference, on 10 the X axis we have the wellbore length. On the second 11 Y axis to the right we have the depth and TVD and then 12 most important for these upcoming slides on the far 13 right Y axis we have the net pressure. Also of note 14 for each of these scenarios we do have the Palm log -- 15 the type log included and that's as a reference to see 16 where exactly the model what -- that it's referring to. 17 So if you looked at the text top upper Moraine, the 18 upper portion and the bottom portion is the base upper 19 Moraine so the top lower Moraine. 20 So speaking of the net pressure again for this 21 particular stimulation it's the most important because 22 it tells you what the additional core pressure is above 23 the reservoir core pressure. For all of these cases 24 that are going to be discussed, a 275 acre flooded area 25 at 6,000 barrels of water injected per day is used 59 1 except for the MI gas injected which will be 6 million 2 cubic feet per day. The reservoir pressure is kept 3 constant during injection so in other words as Adam 4 mentioned earlier for every barrel of fluid produced a 5 barrel of fluid is injected. So back to this net 6 pressure. Again it's a little hard to see on this 7 overhead, but on your slides the highest pressure, net 8 pressure, is roughly 400 psi. So adding that 400 psi 9 to the core pressure of 2,260 the maximum pressure we 10 have is just below 2,700 psi. Of note there's also -- 11 there are no fractures above the upper Moraine. 12 Here on slide number 30 I will summarize the 13 results from the containment assurance analysis as it 14 relates to scenario number 2 which is water injection 15 for a horizontal well with the propped fracture. The 16 previous slide focused on net pressures, this slide 17 focuses more on proppant concentration. The reason for 18 that is that it illustrates the fracture pass. Again 19 the labels are exactly the same except for the proppant 20 concentration. So the previous slide had net pressure 21 here, in our case it will be proppant concentration. 22 Again 6,000 barrels of water injected per day 23 was an assumption as well as the 275 acre spacing. In 24 this case no proppant concentration is above the upper 25 Moraine member so no fractures into the confining • • 1 interval. 2 Here on slide number 31 I will summarize the 3 results from the containment assurance analysis as it 4 relates to scenario number 3 which is MI injection for 5 a horizontal well without a propped fracture, in other 6 words MI injection without a frack. 7 As I mentioned earlier so instead of 6,000 8 barrels of liquid per day injected in this case it will 9 be 6 million cubic feet of MI injected per day. The 10 axes are identical to the axes two slides ago. So no 11 proppant concentration this time, it'll be net 12 pressure. And again it's a little bit easier to see on 13 the slides that you were given. 14 So the maximum net pressure is yellow which is 15 below a net pressure of 250 psi. Adding the 250 psi to 16 the core pressure of 2,260, the maximum reservoir 17 pressure is 260 psi. Also again no fractures above the 18 upper Moraine member. Excuse me, so I said 260, I 19 meant to say 2,600 psi. Sorry for that. 20 Here on slide number 32 the injection pressures 21 will be summarized for the Moraine oil pool. The upper 22 section is a table and this is for one specific depth, 23 so 5,200 feet TVD. Before I delve into the details 24 ConocoPhillips Alaska proposes to use this gradient 25 method versus an absolute pressure method due to the 61 1 changes in the reservoir depth which impact the maximum 2 surface pressure. ConocoPhillips Alaska as Adam 3 mentioned earlier -proposes to develop the Moraine oil 4 pool using IWAG with the option to convert to MWAG or 5 rich gas flood to enhance recovery from the reservoir. 6 Injection rates will be managed to replace offset 7 production voidage so in other words the withdrawal 8 injection ratio will be targeted at a one. The 9 injection rates will also be controlled by surface 10 chokes. 11 The overburden pressure gradient based on the 12 Moraine 1 core data is 0.72 psi per foot. The 13 overburden fracture gradient based off of the 14 geomechanical analysis is approximately 0.82 psi per 15 foot. To ensure containment of injected fluids within 16 the Moraine oil pool injection pressures will be 17 managed as to not exceed the maximum injection gradient 18 of 0.67 psi per foot. Average injection pressures will 19 follow the fracture closure pressure gradient at sand 20 face of 0.62 psi per foot. This average injection 21 pressure gradient has been selected since the fracture 22 closure pressure, the pressure at which created 23 fractures are expected to close, is below the fracture 24 pressure, the pressure at which new fractures are 25 created. Using this average injection gradient will 62 1 optimize the injection into the reservoir without 2 initiating new fractures. 3 So back now to this table which again is 4 referenced to 5,200 feet TVD. For water injection at 5 surface using that gradient of 0.67 the maximum surface 6 pressure for water will be 1,190. That correlates to 7 an estimated bottom hole pressure of 3,500 psi. For 8 the MI injection since a lower gradient of the actual 9 fluid being injected exists, we have higher surface 10 pressures, however the bottom hole pressures are also 11 estimated to be the same both for the average as well 12 the maximum. 13 That concludes the supporting material for the 14 Moraine pool rules and AIO applications. The following 15 slides will list the proposed pool rules for the 16 Moraine oil pool application. Following these slides 17 the proposed rules for the area injection order 18 application for the Moraine oil pool will be listed. 19 So here the first rule listed on slide number 20 33 pertains to the field and pool names. The field 21 name is the Kuparuk River field and the pool is the 22 Moraine oil pool. 23 The second rule, this is on slide number 34, 24 pertains to the pool definition. The Moraine oil pool 25 is defined as the accumulation of oil and gas common to M 1 and correlating with the interval within the Palm 2 number 1 well between the depths of 5,630 measured 3 depth and 6,043 feet measured depth. 4 The third rule listed on slide number 35 5 pertains to the gas oil ratio regulation. Wells 6 producing from the Moraine oil pool are exempt from the 7 gas oil ratio set forth in regulation section 240. We 8 are proposing this rule since the Moraine oil pool 9 plans are to implement enhanced recovery techniques. 10 Since gas will be injected into the Moraine oil pool 11 during the life of the pool the GOR is expected to rise 12 above the solution GOR in some of the wells. The 13 breakthrough of reinjected gas will cause GORs of some 14 of the producing wells to exceed the limits set forth 15 in the current regulation. 16 The fourth rule listed on slide number 36 17 pertains to the drilling and completion practices. The 18 first bullet point reenforces the possibility of 19 variances in the casing and completion designs which 20 were listed in the application and those specified in 21 the regulations. As long as they're administratively 22 approved by the Commission upon application and 23 presentation of data which demonstrates that the 24 alternatives are appropriate and based upon sound 25 engineering principles. 64 0 1 The next bullet point under the rule proposes 2 that permits to drill shall include plan view, vertical 3 section, close approach data and directional data in 4 lieu of the requirements under section 050(b). The 5 reasoning behind this proposal is to relieve 6 administrative burden on both the AOGCC and 7 ConocoPhillips Alaska. 8 The last bullet point under the rule proposes 9 that only one well per drill site is required to be 10 logged for the portion of the well below the conductor 11 pipe by either complete electrical log or a complete 12 radio activity log unless the Commission specifies 13 which type of log is to be run. This is in lieu of the 14 requirements under regulation 20 AAC 25.071(a). This 15 waiver from the regulation is proposed since these 16 requirements will not significantly add to the geologic 17 knowledge of the area in light of the information that 18 is available from other wells in the area. 19 The fifth rule listed on slide number 37 20 pertains to well spacing. The first bullet point 21 proposes that the requirements of section 055 are 22 waived for development wells in the moraine oil pool. 23 This waiver is proposed since the horizontal well 24 development of the proposed Moraine oil pool via line 25 drive flood pattern will yield greater recovery than a 65 1 conventional vertical slash slant well development plan 2 with a minimum spacing rule. However the second bullet 3 point does require that prior approval is granted prior 4 to the completion of any development wells any closer 5 than 500 feet to an external boundary where working 6 interest ownership changes. 7 CHAIR FOERSTER: So this says you can drill 8 them closer, but not complete them? 9 MR. KOWALEWSKI: Excuse me, so drilling and 10 completing would be the intent of that particular rule. 11 CHAIR FOERSTER: okay. 12 MR. KOWALEWSKI: The sixth rule listed on slide 13 number 38 pertains to reservoir surveillance. Static 14 bottom hole surveys -- excuse me, static bottom hole 15 pressure surveys for the moraine oil pool will be 16 conducted in all new injection wells prior to 17 initiating injection. Static surveys on the other hand 18 will be performed on production wells at the discretion 19 of ConocoPhillips. For annual pressure surveillance a 20 minimum of one pressure survey will be conducted 21 annually in the Moraine oil pool concentrating on 22 injection wells. 23 In lieu of the stabilized bottom home pressure 24 measurements the alternative pressure survey methods 25 can be implemented, open hole wireline formation fluid MOO 0 0 1 pressure measurements; cased hole pressure buildups 2 with bottom hole pressure measurement; injector surface 3 pressure fall off; static pressure surveys following 4 extended shut-in periods; or bottom hole pressures 5 calculated from wellhead pressure and fluid levels in 6 the tubing of a stabilized shut-in injector. 7 All pressure surveys will be reported annually 8 rather than monthly to relieve administrative burden on 9 both the AOGCC and ConocoPhillips Alaska. 10 The seventh rule listed on slide number 39 11 pertains to well work operations. The following 12 operations in production and enhanced recovery wells 13 within the Moraine oil pool may be conducted without 14 filing an application pursuant to regulation 20 AAC 15 25.280(a), perforate or re -perforate casing; stimulate; 16 coil tubing operations with the exception of drilling 17 or sidetracks. 18 The intent of this proposed rule is to reduce 19 the paperwork burden on both the Commission and 20 ConocoPhillips Alaska. Summary reports and records 21 will continue to be kept in accordance with section 22 280(c) and (d). 23 CHAIR FOERSTER: When you say stimulate you 24 mean other than hydraulic fracture stimulation? 25 MR. KOWALEWSKI: That's correct. 67 0 0 1 CHAIR FOERSTER: Okay. 2 MR. KOWALEWSKI: The eighth rule listed on 3 slide number 40 pertains to production practices. 4 Please note this rule referenced the incorrect 5 regulation in the application. The application 6 referenced section 030(a), the intent was to reference 7 section 230(a). 8 In lieu of the requirements under section 9 230(a) ConocoPhillips Alaska proposes that each 10 producing well will be tested at least monthly for the 11 first 12 months and then at least every three months 12 thereafter. This rule is proposed due to the 13 feasibility challenges of accurately measuring well 14 rates of all producers monthly for the multi well drill 15 sites planned for the Moraine oil pool. Since the most 16 rapid change in well performance is expected during the 17 first year monthly tests during that time will identify 18 significant production declines. 19 The ninth rule listed on slide number 41 20 pertains to administrative action. Upon proper 21 application the Commission may administratively waive 22 the requirements of any rule stated or administratively 23 amend the order as long as the change does not promote 24 waste, jeopardize correlative rights and is based on 25 sound engineering principles. Z-11 0 0 1 The following slides will not relate to the 2 proposed rules for the area injection order application 3 for the moraine oil pool. 4 The first rule listed on slide number 42 5 pertains to the authorized injection strata or enhanced 6 recovery. The depths listed are the same as the depths 7 listed in the proposed rule two of the Moraine oil pool 8 rules application. 9 The fluids authorized under rule three which 10 will be listed in an upcoming slide may be injected for 11 the purposes of pressure maintenance and enhanced 12 hydrocarbon recovery within the proposed moraine oil 13 pool which is defined as the accumulation of oil and 14 gas common to and correlating with the interval within 15 the Palm number 1 well between the measured depths of 16 5,630 feet an 6,043 feet. 17 The second rule listed on slide number 43 18 pertains to the well construction. In lieu of the 19 packer depth requirement under section 412(b) the 20 packer slash isolation equipment depth may be located 21 above 200 feet measured depth from above the top of the 22 perforations slash open interval, but shall not be 23 located above the confining zone and shall have outer 24 casing cement volume sufficient to place cement a 25 minimum of 300 feet measured depth above the planned Me 0 0 1 packer depth. 2 The reason for this rule is to optimize the 3 completion designs of the moraine oil pool. Since the 4 injectors are planned as horizontal wells stimulation 5 optimization efforts and well work feasibility may be 6 impeded if the packer slash isolation equipment depth 7 is required to be within 200 feet measured depth from 8 above the top of the perforations slash open interval. 9 The third rule listed on slide number 44 10 pertains to the authorized fluids for injection into 11 the moraine oil pool for enhanced recovery. We've 12 covered this material earlier, I apologize in advance 13 for the redundancy. 14 The fluids authorized for injection are source 15 water from the Kuparuk seawater treatment plants; 16 produced water from all present and yet to be defined 17 oil pools within the Kuparuk River field including 18 without limitation the Kuparuk oil pool and the Moraine 19 oil pool; enriched hydrocarbon gas would be a blend of 20 Kuparuk River unit lean gas with indigenous and/or 21 imported natural gas liquids; lean gas; fluids used 22 during hydraulic stimulation; tracer survey fluids to 23 monitor reservoir performance; fluids used to improve 24 near wellbore injectivity; fluids used to seal wellbore 25 intervals which negatively impact recovery efficiency; Of 0 0 1 fluids associated with freeze protection; and then 2 finally standard oil field chemicals. 3 The fourth rule listed on slide number 45 4 pertains to the authorized injection pressure for the 5 Moraine oil pool for enhanced recovery. Injection 6 pressures will be managed as to not exceed the maximum 7 injection gradient of 0.67 psi per foot to ensure 8 containment of injected fluids within the Moraine oil 9 pool. 10 The fifth rule listed on slide number 46 11 pertains to administrative action. This rule is very 12 similar to rule nine of the Moraine oil pool rules 13 application. Upon proper application the Commission 14 may administratively waive the requirements of any rule 15 stated or administratively amend the order as long as 16 the change does not promote waste or jeopardize 17 correlative rights, is based on sound engineering or 18 geoscience principles and will not result in increased 19 risk of fluid movement into freshwater. 20 That concludes our presentation. Are there any 21 questions. 22 CHAIR FOERSTER: Commissioner Seamount, I'd 23 like to take a recess and so our staff can make our 24 questions sound smarter when we come back and ask them. 25 Is that okay with you? 71 1 COMMISSIONER SEAMOUNT: I don't know if my 2 questions could be much smarter, but, yeah. 3 CHAIR FOERSTER: I know mine could. All right. 4 So it is currently 10:35 so let's take a 20 minute 5 recess and come back at five minutes until 11:00. And 6 we're recessed. 7 (Off record - 10:35 a.m.) 8 (On record - 10:53 a.m.) 9 CHAIR FOERSTER: We'll go back on the record at 10 10:53. All right. Commissioner Seamount, do you have 11 any questions all smartened up by our staff? 12 COMMISSIONER SEAMOUNT: I have very few 13 comments and questions, but I would like to get back to 14 one and that has to do with the Oooguruk and Moraine 15 pools. Really pools don't have to follow ownership 16 lines so I'd like to ask a question. How is the 17 Moraine -- is it in communication with the Oooguruk? 18 CHAIR FOERSTER: The Torok. 19 MS. UMLAUF: I think probably along the lease 20 line it is. 21 COMMISSIONER SEAMOUNT: Along the lease line. 22 MS. UMLAUF: Uh-huh. It -- so I'll kind of 23 just walk you through my thinking there. So, you know, 24 with a line source style of sediment source you got a 25 lot of different sediment coming out to the basin from 72 0 1 different areas, right, and what we interpret is that 2 really they're coming out and they're coming out an 3 unconfined flow and creating maybe lobes or layered 4 lobe complexes, something on a scale of less than a 5 mile wide or so, maybe a little bit more than that. So 6 you can imagine that's happening all along the shelf, 7 you're not going to have sands that are in 8 communication all the way up to ..... 9 COMMISSIONER SEAMOUNT: Right. 10 MS. UMLAUF: Oooguruk down to 3S, but you 11 probably will have some overlapping lobes in there. 12 COMMISSIONER SEAMOUNT: So it's a pretty lucky 13 lease line. CHAIR FOERSTER: Well, so actually it's 14 in as much communication with Oooguruk as it is with 15 something, you know, elsewhere, it's a gradation of 16 communication, this is in communication with this, but 17 this isn't with this and this isn't with that, is that 18 what you're saying? 19 MS. UMLAUF: Yes, that could be it. 20 CHAIR FOERSTER: Okay. 21 COMMISSIONER SEAMOUNT: But there's no law that 22 says that a pool has to follow lease lines or ownership 23 lines and ..... 24 CHAIR FOERSTER: In fact, they shouldn't. 25 COMMISSIONER SEAMOUNT: ..... however pool rules 73 0 0 1 can change, they can change, with ownership and lease. 2 okay. That's all I have to say. 3 CHAIR FOERSTER: That's everything? 4 COMMISSIONER SEAMOUNT: That's everything. 5 CHAIR FOERSTER: Wow. 6 COMMISSIONER SEAMOUNT: Well, for this. 7 Although I would like to thank you for a very complete 8 presentation. That was very well done. 9 CHAIR FOERSTER: Okay. I have several 10 questions, is anyone surprised. I would like the 11 answer to the ownership question because commingling at 12 the surface would be a problem, a custody transfer 13 problem, if there is an ownership difference so I do 14 need that question answered. 15 This one I think is for Mr. Kowalewski. You 16 talked a lot about hydraulic fracturing and following 17 20 AAC 25.283, are those regulations under 283 are 18 those going to be onerous or make it difficult for you 19 guys to conduct your hydraulic fracturing operations? 20 MR. KOWALEWSKI: To date we have been following 21 those regulations and internally I haven't heard any 22 sort of ..... 23 CHAIR FOERSTER: Okay. 24 MR. KOWALEWSKI: ..... concerns with following 25 them. 74 0 9 1 CHAIR FOERSTER: Okay. I just wanted to check 2 again some statements that some people that are in the 3 back of the room made when we were instigating these 4 hydraulic fracture regulations that the world as we 5 knew it would end and half of Kuparuk would become 6 uneconomical, but so that didn't happen? 7 MR. KOWALEWSKI: As far as I know. 8 CHAIR FOERSTER: Okay. Good. So have you 9 compared this reservoir with your Meltwater reservoir 10 when doing your confining analyses? 11 MR. KOWALEWSKI: Since Adam worked thoroughly 12 on the Meltwater as well as on the Moraine I'll defer 13 the question to him. 14 CHAIR FOERSTER: He gave you the hard one. 15 MR. LEWIS: So this is Adam Lewis. A direct 16 comparison, no, other than to say that the analysis 17 that we've done on the Moraine oil pool and the 18 confinement is far more substantial than anything that 19 we did for Meltwater before development. 20 CHAIR FOERSTER: Are you familiar with the 21 confining issues at Meltwater? 22 MR. LEWIS: Yes, I am. 23 CHAIR FOERSTER: And do you have data to 24 confirm that those issues do not exist? 25 MR. LEWIS: Yes, we do have data -- well, that 75 1 they do not exist because we have not commenced 2 injection into the Moraine oil pool so the issues that 3 happened at Meltwater can't possibly occur at Moraine 4 right now. 5 CHAIR FOERSTER: Don't get cute with me. I'm 6 asking a question ..... 7 MR. LEWIS: All right. 8 CHAIR FOERSTER: ..... have you -- has your 9 analysis convinced you that those problems will not 10 result when you instigate injection? 11 MR. LEWIS: Yes. 12 CHAIR FOERSTER: Could you give us that 13 information? 14 MR. LEWIS: The fracture modeling that we've 15 completed here and shown that our injection ..... 16 CHAIR FOERSTER: okay. But did you do -- do 17 you have similar analysis to that from Meltwater? 18 MR. LEWIS: Yes, we do. 19 CHAIR FOERSTER: Okay. And it -- does it 20 indicate to you that you're going to frack out of zone 21 when you inject? 22 MR. LEWIS: At Meltwater? 23 CHAIR FOERSTER: Yes. 24 MR. LEWIS: No, it did not. 25 CHAIR FOERSTER: Okay. So how do you convince 76 0 0 1 -- so your Meltwater stuff says you're going to be cool 2 and you're not. And your Torok stuff says you're going 3 to be cool and you tell me to believe that. You see 4 where I'm going with this? 5 MR. LEWIS: Yes, ma'am. And I said that the 6 model for Moraine 1 is far more calibrated than the 7 model we had at Meltwater. 8 CHAIR FOERSTER: But you haven't gone back and 9 calibrated your Meltwater model to make sure you're not 10 going to have the exact same problem? 11 MR. LEWIS: We are talking about Moraine, 12 right? Okay. 13 CHAIR FOERSTER: I'm saying are you going to 14 learn from a past mistake and make sure you don't make 15 it again, that's all I'm ..... 16 MR. LEWIS: Yeah, and I'm trying to say -- I'm 17 sorry, we're just getting crosswired here. We have -- 18 we've collected far more information on Moraine than we 19 did on Meltwater specifically to avoid a problem like 20 that again. 21 CHAIR FOERSTER: And you -- do you feel that if 22 you had collected all of this data for Meltwater it 23 would have told you that you had a problem? 24 MR. LEWIS: That's a very difficult question to 25 answer. 77 0 0 1 CHAIR FOERSTER: Okay. Okay. So all this 2 extra data that you collected gives you confidence 3 here, but you have no confidence that if you had that 4 same data there you would have known the problem? 5 MR. LEWIS: The ..... 6 CHAIR FOERSTER: That's not -- the warm fuzzies 7 just aren't happening and they need to. 8 MR. KOWALEWSKI: For the Moraine oil pool -- 9 this is Kasper Kowalewski again, we will be a lot more 10 diligent in following the IW target of one as well as 11 monitoring the i-pressures of the wells. 12 CHAIR FOERSTER: So you have a surveillance 13 program planned to identify a problem early on? 14 MR. KOWALEWSKI: Yes. 15 CHAIR FOERSTER: Okay. Could you give me the 16 details of that plan on the record? 17 MR. KOWALEWSKI: I currently don't have those 18 details in front of me, but if you'd like ..... 19 CHAIR FOERSTER: Okay. That's something that 20 we'll need to get answered be ..... 21 MR. KOWALEWSKI: Okay. 22 CHAIR FOERSTER: ..... we'll leave the record 23 open and get that answer. 24 MR. BRAUN: This is Michael Braun. one thing 25 that's substantially different in the planned Moraine W., 0 0 1 development to Meltwater is the drilling and completion 2 of very long horizontal wells and the line drive. And 3 we are very confident that we will be able to inject 4 the target at injection rates at or below the pressure 5 limitations we -- we're self imposing. 6 CHAIR FOERSTER: How do those pressure 7 limitations compare to the pressure limitations that 8 Meltwater has? 9 MR. LEWIS: They're actually very similar to 10 the current limitations of Meltwater. 11 CHAIR FOERSTER: To the current limitations, to 12 the ones that are working? 13 MR. LEWIS: Yes. 14 CHAIR FOERSTER: Okay. And -- okay. All 15 right. There's a little warmth and a little fuzzy 16 coming in there. Okay. But you'll get me that 17 surveillance plan. Okay. is So do you feel that given that you need extra 19 surveillance for reservoir monitoring and management do 20 you feel that rule eight will be sufficient for you and 21 do you feel that your pressure -- well, I guess there 22 are two questions, let's just answer that one first. 23 Rule eight will be ..... 24 MR. KOWALEWSKI: Yes, we do. 25 CHAIR FOERSTER: So everywhere else in Kuparuk 79 0 0 1 you test wells -- you're able to test wells monthly, 2 why can't you do that on 3S for this development? 3 MR. BRAUN: I can answer that. This is 4 Michael. we could. The -- I believe however the 5 ultimate intent ConocoPhillips has is consistent with 6 possibly the intent that the AOGCC has which is to 7 ensure that we have quality testing. So our intent is 8 to have the flexibility so that we can test the wells 9 we believe are worth testing with higher frequency and 10 just have the flexibility as an operator to make the 11 call which wells we should test more frequently. We do 12 know that at CPF 3 there is an ongoing study that wells 13 tests require between five and 10 hours to stabilize to 14 give us an accurate watercut. And so we do need about 15 24 hours to complete one well test. 16 CHAIR FOERSTER: And given the concerns about 17 the confining layers do you think your pressure testing 18 program is going to give you adequate information if 19 you're just going to pressure test injectors and you're 20 just going to do it periodically, you ..... 21 MR. KOWALEWSKI: So that -- that's rule number 22 7, is that correct, with the pressure surveillance 23 program? 24 CHAIR FOERSTER: I don't recall, but I 25 think ..... I-IR 0 0 1 MR. KOWALEWSKI: Rule number 6. 2 CHAIR FOERSTER: Okay. 3 MR. KOWALEWSKI: So that's not necessarily the 4 type of surveillance that we'll be focusing on. Our 5 focus is the daily collected data on the wells for the 6 i-pressures to make sure that they don't get over 7 pressured. The shed and bottom home pressures, it's a 8 little bit different from the standpoint of the type of 9 surveillance program when you compare the two of them. 10 CHAIR FOERSTER: But won't reservoir pressure 11 tell you something about whether your injected fluids 12 are staying in the reservoir or not? 13 MR. KOWALEWSKI: So you're asking if gathering 14 additional shed and bottom hole pressures on producers 15 prior to putting them on production will give you 16 additional information on the injection? 17 CHAIR FOERSTER: Or after they're on production 18 periodically? 19 MR. KOWALEWSKI: So periodically the data that 20 you would end up collecting is not necessarily -- 21 depending of course on if you wait for the stabilized 22 shut-in, the pressure. So going back to the rule from 23 the standpoint of testing these wells or obtaining the 24 shed and bottom hole pressure prior to putting it 25 online. It would -- certainly would be beneficial from 81 0 0 1 the standpoint of checking what your injection pressure 2 is with -- throughout the reservoir is correct. 3 CHAIR FOERSTER: Okay. So prior to fracking 4 any of these wells you'll have to be able to ensure 5 that you have good cement and mechanical integrity in 6 all of your 3S wells, have you all done that yet? 7 MR. KOWALEWSKI: So for -- you're asking about 8 the Kuparuk wells that are ..... 9 CHAIR FOERSTER: Yeah. 10 MR. KOWALEWSKI: ..... independent of the 11 Moraine wells? So at this point with the wells in our 12 phase one so the 3S-613, there are no wells within a 13 quarter mile radius with an open annuli and with our 14 phase two development that'll be the same case since 15 they're going up to the northwest portion. 16 CHAIR FOERSTER: So the old -- I'm asking about 17 the old Kuparuk wells. MR. KOWALEWSKI: Yes. 18 So with -- since they are not within a quarter mile 19 radius that ..... 20 CHAIR FOERSTER: At the bottom hole location. 21 But they're drilled off the same pad, there may be some 22 issues, you haven't looked at those? 23 MR. KOWALEWSKI: We have not. 24 CHAIR FOERSTER: Okay. we may be asking you 25 to. Did you consider using -- going back to M 0 0 1 Commissioner Seamount's question, did you guys consider 2 the Kuparuk Milne model for pool rules and pool 3 designation of -- it's -- recognizing that it's all the 4 same pool, but you can certainly have different pool 5 rules and different AIOs? 6 MR. KOWALEWSKI: We did not consider that. 7 CHAIR FOERSTER: Why not? 8 MR. KOWALEWSKI: So from internally reviewing 9 the super (indiscernible) I believe is the way it's 10 phrased, we don't see any benefit in doing it. As long 11 as the operators on both sides of the lease line, they 12 reasonably develop the resource, there is no promotion 13 of waste and correlative rights will also not be 14 hindered. You have challenges if there is a poll for a 15 superpool from the standpoint of gaining alignment with 16 those operators. 17 (off record comments) is CHAIR FOERSTER: I apologize. Please continue. 19 MR. KOWALEWSKI: That was actually the 20 conclusion of my statement. 21 CHAIR FOERSTER: okay. Okay. You've given 22 some very specific exemptions from having to file 23 sundries, did you consider adopting the Kuparuk sundry 24 matrix ..... 25 MR. KOWALEWSKI: We ..... A 0 0 1 CHAIR FOERSTER: ..... which is a broader set of 2 exemptions from having to file sundries? 3 MR. KOWALEWSKI: We did not consider that. We 4 were looking over historically the most recent 5 conservation orders, looking at what was common and 6 looking at the administrative burden and if this was 7 something that had a precedent is how we looked at it. 8 CHAIR FOERSTER: Okay. Well, the person who's 9 writing down the questions, could you consider whether 10 that is something that would be of benefit to you and 11 if it is could you request that, you know, we consider 12 making that broader ..... 13 MR. KOWALEWSKI: Okay. So that's the ..... 14 CHAIR FOERSTER: ..... as it needs ..... 15 MR. KOWALEWSKI: ..... Kuparuk -- what is it? 16 CHAIR FOERSTER: We have a Kuparuk matrix of 17 types of activities that are not required to file for a 18 sundry and it's a broader group of activities than the 19 ones that you have requested. 20 MR. KOWALEWSKI: Okay. 21 CHAIR FOERSTER: And so take a look at that and 22 see if that's of interest to you because, you know, 23 that's something that would -- would be something we'd 24 be willing to consider. 25 MR. KOWALEWSKI: Okay. thank you. M 0 0 1 CHAIR FOERSTER: You're welcome. If we grant 2 the packer variance we might add a requirement that you 3 run and provide cement evaluation logs in all 4 injectors, is that something that would be onerous and 5 unacceptable, kind of like our hydraulic fracturing 6 rules or ..... 7 MR. KOWALEWSKI: Unfortunately I don't have the 8 answer to that. I'll have to discuss internally to 9 see ..... 10 CHAIR FOERSTER: All right. So we can add that 11 to the list of things you're going to come back and 12 answer for us. 13 All right. Did I trigger any more questions 14 for you? 15 COMMISSIONER SEAMOUNT: No. 16 CHAIR FOERSTER: okay. All right. Does Conoco 17 have anything else they want to add after the questions 18 that have been asked, maybe Mr Kanady wants to come up 19 and fight with me about hydraulic fracturing regs or 20 something, I don't know. Do you have anything you want 21 for the good of the order? 22 MR. KOWALEWSKI: We do not. 23 CHAIR FOERSTER: Okay. Thanks. Is there 24 anyone else in the audience who wishes to testify? 25 (No comments) 85 1 CHAIR FOERSTER: All right. Seeing no one -- 2 oh, wait before we adjourn. We're going to leave the 3 record open for you to respond to the questions that 4 we've asked and could you give me a readout of what 5 you've got as your questions so we can make sure it's 6 the same list? 7 MS. JOLLEY: I'm Liz Jolley, I'll be reading 8 back the questions for today. The first one is in 9 terms of is there a royalty difference between the two 10 leases that are currently outside of the KRU and the 11 current KRU, and then as well as to look into the 12 ownership changes of the two if there is any. 13 The next question or comment is to provide 14 surveillance plans for the Moraine to ensure 15 containment is maintained. 16 The next one is look into any issues with 17 existing wells at 3S for any mechanical integrity 18 issues in terms of potential fracking. 19 The next one is to investigate if it's worth 20 adopting the KRU matrix of exemptions for the Moraine 21 area. 22 And then also following up on the packer 23 exemption with will bond logs be run on all the 24 injection wells (indiscernible) ..... 25 CHAIR FOERSTER: Okay. Did you have any other EMSI 0 0 1 questions that didn't get captured? 2 COMMISSIONER SEAMOUNT: No, I didn't. 3 CHAIR FOERSTER: Okay. How long do you think 4 we need to leave the record open for you guys to allow 5 you time to provide answers to those questions? 6 MR. KOWALEWSKI: If possible two weeks ..... 7 CHAIR FOERSTER: Okay. 8 MR. KOWALEWSKI: ..... since the 3S-613 we 9 planned the injections to start in July. 10 CHAIR FOERSTER: Okay. So two weeks from today 11 would be May 24th and that will be adequate for you? 12 MR. KOWALEWSKI: Yes, it would. 13 CHAIR FOERSTER: Okay. Well, then we'll leave 14 the record open until May 24th to allow you time to 15 provide answers to those questions. 16 And if there's nothing else for the good of the 17 order at 11:12 a.m. this hearing is adjourned. 18 (Hearing adjourned 11:12 a.m.) 19 11:14:27 20 (END OF REQUESTED PORTION) N-N 0 0 1 C E R T I F I C A T E 2 UNITED STATES OF AMERICA 3 )ss 4 STATE OF ALASKA 5 6 1, Salena A. Hile, Notary Public in and for the 7 state of Alaska, residing in Anchorage in said state, 8 do hereby certify that the foregoing matter: Docket 9 No.: CO 16-007 and AIO 16-011 was transcribed to the 10 best of our ability; Pages 02 through 88; 11 IN WITNESS WHEREOF I have hereunto set my hand 12 and affixed my seal this 16th day of May 2016. 13 14 15 16 17 18 Salena A. Hile Notary Public, State of Alaska my Commission Expires: 09/16/2018 H., M. E STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION Docket Number: CO- 16-007 and AIO 16-011 ConocoPhillips Alaska Inc. May 10, 2016 NAME AFFILIATION Testify (yes or no) C- o p yef I-OkN,4 P,1(,HVMdND C6 e h-1 K-Azam -Abf-A8(>iA cor rJoi ZioeCreA- 5i-e-oc, WGz)-rk&-,f-4- D 1,j (7Z A.) 0 0 0 NAME AFFILIATION Testif y (yes or no) I fl-M ConocoPhillips AOGCC Pool Rules and Area Injection Order Applications for the Moraine Oil Pool � Mayloth , 2016 w AIO —Area Injection Order ft KRU — Kuparuk River Unit w API —American Petroleum Institute w LOT — Leak -off Test w BaSO4 — Barium Sulfate w MD — Measured Depth w CaCO3 — Calcium Carbonate w MI — Miscible Injectant w CPAI — ConocoPhillips Alaska, Inc. w MWAG — Miscible Water Alternating w CPF — Central Processing Facility Gas w DS — Drill Site m ODS — Oooguruk Drill Site w FWL — Free Water Level w OOIP —Original Oil in Place m GAPI — Gamma Ray American w O/W — Oil/Water Petroleum Institute (Units) w PPG — Pound per Gallon w GOHFER —Grid Oriented Hydraulic w RDT — Reservoir Description Tool Fracture Extension Replicator w RF — Recovery Factor w GOR — Gas -oil Ratio w TOC —Top of Cement w HC - Hydrocarbon m TVDSS —Total Vertical Depth w HRZ — Highly Radioactive Zone Subsurface w HZ — Horizontal m USBM — United States Bureau of Mines w IWAG — Immiscible Water Alternating m WF — Waterflood Gas w WI — Water Injection Conoco•hilfips Objective: To supply the AOGCC with the information necessary to approve CPAI's Moraine Oil Pool application and Area Injection Order application, with the proposed rules. Presentation Outline: w Background and Project Overview (Kasper Kowalewski) w Geology and Pool Description (Kelly Umlauf) w Resource and Recovery Overview (Adam Lewis) w Operations and Containment Assurance (Kasper Kowalewski) � w Proposed Moraine Oil Pool and NO Rules (Kasper Kowalewski) Timeline w 1960's — 1980's ■ 3 wells and core (Colville 1, Colville Delta 2 & 3) ■ Vertical well test and core gathering campaign (Kalubik 1&2) 2000's — 2010's ■ Successful horizontal well tests and ODS Development 2013 — 2016 CPAI ■ 3S-19 recomplete ■ Moraine 1 core well ■ Cored overburden for geomechanical testing and reservoir containment study ■ 3S-620 horizontal producer ■ 3S-613 (planned horizontal '� �' r='' ^ 1 injector) Significant Moraine Wells Shown 0 r: 283 ADL392712 ADL39z711 ADL389960 � ADL.389958 793a41 NikaitcLhq ADL35501I [ a/tOL389� 577 ADI391Uni10gDL3908 ADL3'S9018 __F+ Legato Q��Wor+�+a.Mo_,aa�u ftft* 0 &AV -- drea ti ry ►eaoWsa&NOWreo M_ A*. 9174N Mu�ie$al E}tilament Oq a1-4-MNO" &CPS EOMOW- ATM- R AD{. aty}?,NON1++i006 Ep1gWuATM R =Am.,rli}. H0,11„ 1.90E woow. . ATM. R Essemsnts 016� 4,7aa7;1'�!M NM,! rNew,au Ma 4. __ft"mw 4tanre f wz 0OU*p %M Wft ftft Ke..rC*VM go—WCiii. Ptrmit o _Lwu iiiiiiif:l0. a0}T}7. Cc'iooelHOs Aatb K 11le+enaa:ar•a Cav (NT 1-0C.41-mm. 0ewM 9MlmJVaftmW4 NC4-4q.e= Ad Cwe Gal, A7. n t1r,C. ew Rrora� E.oe1M,0+CO r ,. 9MIK:aete ea^v 6+n •OMraa, wan 1,Msr Verk %V 11 Nee wm MC -A Yuricpal Land ErAftm as ®.a. a, ya.. 1401A aWe 6-91 A'd, M 11 Wp 0.9 Q A0. a10V. Hats aWe SOWA- AM,' * A1*. 0W O A3. 417W N" sloe WmV Q R. 41-"1. Hats aWe§W%4ft Am WA1-A OW DuRau d Lind Mar gwnant (" Natkm Atbtments F Ag1e "94 (Noe 9M4}: [t�'wan 013131 =NWF ""3a Mho► CIUM =Ave clam =wow mm Owae onus �Aae cow) ,ti•sdsaee:ao�+►rines+cerov Q,c v.s AO( wane} =0T./A cow ADL391W ADL39IMS I ADL392M I ADL025571 3 ADL355023 T3 F 014wg -ADL R 417983 I" 3Q j _ U1 AOLD25512 02551 3� ADLO25514 0253 ADL02552i 25S20 ADL025519 4 � 3K 3J AD 1 AD L 25631 ADLA2 ADLO25629 ADL02W28 Kuparuk River Unit 38 7 3 ADL029E32 5833 ADL02SE34 1R ADL02 35 G ADL025542 ADL025543 ADL02 1 2W AM02 213 2) 2 ADL02 ADLO ConocoPhillips ' Alaska N Moraine Area Injection Order L 4 ADL02 55 ADL Surface Rights and Leases A 0 OS 1 2A l MR •Bieee3ee• ConocoPhillips • ConocoPhillips • Geology and Pool Description Cono4hillips Well: PALM No. 1 Alaska, Inc. AGE M.Y. B.P. LITHOSTRATIGRAPHY NORTH SEISMIC SEQUENCE (� OUAT, GUBIK FM 2 OU W w SAGAVANIRKTOR FM _ Y --------------�O mW 0 U 100 _ NANUS p M __ ` 4'~ B F RIFT EBB E SHALE _ '-_SEQUENCE CUO U SK SAW r-Kllit;GAK!9H WwZ U) LIKE I = _ �W _KIItUC _ SPOL�Gg K.4�VI h 1.,.. E( H^.OKA Ft< PU a gw v WWz O300 O 0 p LISBURNE GP 0 NQ WN G LU JQ m OTTT U a Z tu 400 �� . M' NER4fOKPUK Fca Y53 ZO m Q F 0 Stratigraphic column modified from Alaska DO&G, 1996 w Moraine Oil Pool within Torok Formation ■ Cretaceous slope to basin floor turbidite deposits ■ Divided into two Members: Upper and Lower Moraine Combination trap with stratigraphic and structural components Cono4hillips Alaska, nc. Well: PALM No. 1 Moraine Oil Poo ReeauM Sael. 1 OHMM 1lb N..Von ity _ ReeielM Med. 60 F 0 (a) Mo (RI 1 OHMM 100 �ro� 1.65 G/C0 2.65 Gamma Ra 1.Wo Rene Member Formation0 GAPI 200 1 OHMM 100 5050 5550 5100 5a00 1 � RIpON MO 5150 5650._. T C 5200 0 — 5700 ..: CIO r d. 5250 5750 , a G <Y` CL -- se90 O 5J00 yyy... O► 5950 y' d s: 5350 C W 5900 O ` 5<00 � 5950 W 47. O 5450 6000 J 5500 _ > I N 6100 � <, 5550 5a90 m Gross depositional model — shelf edge delta supplying sediment, transported down slope gullies to the basin slope and basin floor m Beds interpreted to be laterally continuous on a local scale (100-2,000 ft. laterally) m Deposit dominated by very fine grained sand to coarse silt m Thin bedded reservoir (sub -inch to few feet), interbedded sandstones, siltstones, and mudstones m Expect poor vertical permeability due to the interbedded mudstones Modified from Ford, T.D., 2002 • Moraine Oil Pool Sandstones 50-70% quartz, 1-10% feldspar, and 15-30% lithic fragments (dominantly metamorphic) with minor detrital clay minerals and organic debris Clay minerals mainly illite with minor amounts of smectite, chlorite, and kaolinite 30% to 60% gross sandstone 15% to 28% porosity, arithmetic mean of 19% 0.5 mD to 93 mD permeability, with an arithmetic mean of5mD 30% to 85% water saturation Peripheral Tarn deposits as local analog Modifiedfrom Ford, TD., 2002 9 ConocoPhillips ....... 0 U N Ultraviolet Light T a U m F Moraine Oil Pool w Sandstones 50-70% quartz, 1-10% feldspar, and 15-30% lithic fragments (dominantly metamorphic) with minor detrital clay minerals and organic debris ft Clay minerals mainly illite with minor amounts of smectite, chlorite, and kaolinite w 30% to 60% gross sandstone w 15% to 28% porosity, arithmetic mean of 19% w 0.5 mD to 93 mD permeability, with an arithmetic mean of 5 mD w 30% to 85% water saturation w Peripheral Tarn deposits as local analog Do" -D" 40 Modified from Ford, T.D., 2002 0 ConocoPMllips Alaska, Inc. 60400MI:N Upper Moraine Depth FN Surface Structure Map ` ' NAB ale Oob uruk g • • • 6020000F J } �- T�►P Upper ; r 1..,9 t`�� g w \\� 4'0_ • 2000OF N Moraine �,. 4 '^ � '00 ') Structure / o CI = 20 ft. moo ,`. ., ,- • �y s . 4940� v Y s lorainel 1 Y -5000\ -5050 pper Moraine/ -510 -5150 -5250 ro :5300 Kur�3aru -River -5400 g o 60000DOF N �',� .5450 4 _5500 •+ � .. • ; • ' • OOOOOOF N L• 5600 3 . D • o ' %4 i n -5650 r' -58 0 ° PALM1 1g� Top Pool/Top Moraine 5850 5100 .5900 0 ••��_:5240- : -4,940 ft. to -5,880 ft. TVDSS 5140 I .52 0 • ��60' / •• • • • • 598000OF N MILES y21 `-� ,y1a • 980000E N Placer , 5°- ° '�° ° , . ''\\ o (�--✓• 6 Legend S 5�,6 r' -5 • to • p .. .., h r Coastline ._.__._.__..__._._..._.. i �_ �___.i .,. .,.„ - \� • m o • . \Nso Unit Boundary ......._..._..__.__.... 0 Lower Moraine! Pool •�. may, \. • \ -moo Lease Boundary ....................... /RZ d w e �� o I �. 3615�AIO and Pool Area. �----------� Well Penetration • • • • • • in Upper Moraine .................. _... 596000OF N " • Fault ._..__......._._............................ 960000E N LL LL O 8 LL 8 O O ConocoPhillips Conoc�M'Ilips AJanka, Inc. KI^ 1 R'Y S., "HMM 100 Neuron R ... bty MW w PU 0 Iwse mo 1 OKMM 100 M (h) --- i.05G= 255 OHMM 1w roo 5800 '50- , 41 -A 5750- J� wo. 6W40- f1m. — 5500- 6�Wo - 5550- 6100- — 71 6150- 5600, w LU LU Uj U. U. 7— 6WFN---Moraine Oil Pool N Isochore og� Oo6guruk A'- 5020DDOF N soz0000F Moraine Oil Pool 44 Isochore Cl 10 ft. 640 r3 Top Mwainw 550 rop Upper momm/ 525 top Pod 500 475 4 450 uparu over 25 40 5 6000000F N — FN 0 179 PA Moraine Oil Pool Thickness 150 125 100% •60 ft. to 640 ft. 60 MAES 598000OF N 5980000F N — Placer Legend F----I -------- — — ------ L Coastline . ..... UnItBoundary . Base Laver Mo,ah,e/ Lease Boundary . . ....... a.. Pool/ Top HRZ -------------- AJO and Pool Area a ene on in Moraine Oil Pool FN aFault ..... . .................. N 5960000 8 U. West to east cross section across the A10 area (outlined in dashed red), curves shown here include gamma ray, TVDSS, measured depth (MD), deep resistivity (black curve), and shallow resistivity (gray curve) Gamma Ray Resistivity GAPI TVDS Nip ohmm 0........180 1......100 ruk Unit Y, -14- 1 C Y ro F- • i y •� WW y ulna- ..a5., Yr55 YYSn .. 5.dn , - now 51VA ti aW R i ( aasn .. r j r ti i tow ._- YDIIa SHn i .SOW IadYa-- Y5!.d -. YSud 5500 - 1a650 .. f/_y 9Dan - .5d5n Wo ,Dolt .. lofts ' l M5t - b55t - - boon A 51bn InY ,5taaIa75tl -1 1 TdB S _ 'r : y SDbd 5Yn6 lama �.. 3 • m5e - ltma - l - erm - Upper Iada Yatp 5rT Yand 5}on— STnn Moraine 57nD - ttu5a - a2ta 1 elda now . aro low ArA = i .etst ono ar5a - 5»n J.r loop - i t dr5n , - atde tlatt. .r-- -- � SaYaq � MCI— i � -5Ooo 1 Lower 1 .5%4 SNYSa � 17t:T.: • eeno• • • 1 -57Pt .. ... ydDh : r!• 1a5X t 1 SYnd .,,,, YIMa ..toot I Moraine �.. tdrw.� - auto - i �� ROD Ytan Donn InD49 * - om - 1. Wo .SIW a/5a 5ana 595n . .D/an felon - atdb TdaY - 1 , .. :.T + 4ow + 1 arrA Von e+SP bWo nDW .. latn - rma - -SYdd . SPIM ON - - fna5e - Tlee t �Sp dn5o - 55ae - 55Xo fI RZ blot Ilodo I'. 55Pa - SSYD 1 .• Do__61n11 ' .1 MAD lima .. ,595a Y)5d n55a •.. A55a . tttaa 55•R - TDao - Ono .. etsn - 1 -. •5ad0... .Dnoa t11Sn - .risod - D.w a7d0 11rea TSnn •. I b:St'p AM - ,56W - - 175a - �565fi 11:7a 'San "' Ji',q I 595X Y7nt Er Wo.- 111 1 Y k .5rno Y55a - 510D Y311Y Storm lltte .Von rYDa t n15X li 1 - 5iha I - lS754 - 1 its 1 a{X'l - I 3S-19 Palm 1 3S-08 3G-I f 3A-08 --------------------- ;AIO/Pool Boundary; C. .• North tosouth cross section across the A]O area (outlined in dashed red), curves shown here include gamma ray,TVDSS, measured depth (MD), deep resistivity (black ' curve), and shallow resistivity (gray curve) Gamma Ray Resistivity GAP[ TVDSS MID ohmm 11 S150- Szw- low -tow Upper -t Moraine Moraine law "W l6d, 41.7v. . , z.— f SSW- .1wa hw- l.I UW —-- � rr I 7550 10 1 * I ConocoPhillips Resource and • Recovery Details Legend _ _ Coastline Unit Boundary Lease Boundary _ - _.. ;Q• AlOand Pool Area .._....._.._.�__�_ 000gu a -; os Pads ... _ _._..__........_ 35 (ex.) • . • . • 30 Well Penetration • in Moraine Oil Pool _ , 3M , • Fault 34 . .. Kupaeu •River �,• �3J �wuMr • • • . .3 w 35 •- - r-f M •/3G � • . 38.. o i z 1Q �g .. zW Placer •zo - �Z7 • • : 2X 2A• _ Phased development approach focused from existing infrastructure ■ Primary target — DS-3S area ■ Secondary target — new drill site to a NE/SW (pending success and high WF recovery) w Horizontal line drive development ■ IWAG/MWAG injection program ■ Hydraulic stimulations planned for injectors and producers Wells placed along maximum principal stress to improve WF performance ■ Estimated in -zone well length 3,000 — 8,000 ft. Target voidage replacement ratio of 1.0 • ta, I �.�' J'J� �"� rttW5ft9 .eLmf611 .o�vesn Kupar k River / //�•� i 31 °ed ,• MORAINE 1 '.:iALM 'I 35-19.. .usn,o, /nwss.x 1 .amxax ■ Wxzw °ram Legend Placer Cmst trm............. _.............. ---f _ llntt Rminttary ......__.........._......0 Leas* t7nuntlxry _._.._..... o », axe------------i •°1B1'� At0 unA Pall Areal Otlll ritf. Pn(Is ............... _... _..__.. - Fault Phase 2 Wells . .............. ......... ......••-mama..»-. I�'hax 3 Ueveloµ�rleM Pha e 4 w Planned horizontal well length to range from 3,000-8,000 ft w Well spacing to range from 1,000- 21500 ft 2,263 140 425 26.5 2,134 1.2 2.5 1.2 Estimated OOIP 00 00 M MSTB 100 00 M M STB Well Count 1 fi 14-28 Dev. TypeHoriz. Line Drive Horiz.- Drive Estimated RF 1 17 •• .mConocoPhillips ass. • Typcial Waterflood Recovery Efficiency (Moraine) E 35 30 25 g 20 - I 15 -- — °C 10 s v 0 0.00 0.50 1.00 1.50 2.00 2.50 3.00 HCPV Water Injected (fraction) 12 T --____ --- _--. .� 10 8 �— 0 6 _.._ —IWAG 'o —25% MGI 4�� —5096 MGI � —75%MGI E 2 T---_- Y I C ' 0 0.00 0.50 1.00 1.50 2.00 2.50 3.00 HCPV Total: water+gas (fraction) m USBM wettability tests from Colville Delta 3 well indicates waterflood (WF) recovery to range from 24-56% of OOIP ■—20-50% incremental compared to primary depletion only m The layered nature of the system will reduce WF efficiency ■ Modelling indicates pattern level RF will range from 10-30% of OOIP after WF (0.05-0.25 incremental RF from WF) m IWAG incremental is expected range from 1-5% of OOI P m MWAG incremental is expected to range from 3-15% of OOIP ■ Tarn: 8-15% of 001P ■ Ku pa ru k: 2-10% of 001 P • • w Regional RDT data used to delineate fluid contacts w Water zone controlled by Ivik 1 well w Oil zone dictated by Moraine 1 well w FWL estimated at -5,190 ft. to -5,275 ft. TVDSS ■ Possible transition zone (mobile oil and water above -5,275 ft. TVDSS) -5050 -5100 -5150 -5200 N -5250 V -5300 i Q N -5350 -5400 -5450 -5500 -5550 2260 2270 2280 2290 2300 2310 2320 2330 2340 2350 2360 2370 2380 2390 2400 2410 2420 2430 2440 Formation Pressure (psia) 0 ConocoPhillips • Containment ands Operations Details - Prevent leakage into oil, gas or freshwater zones (no freshwater zone is present) ■ Cased and cemented for zonal isolation w Isolate pressure to injection zone ■ Casing, tubing and packer w Verify mechanical integrity ■ Tubing and casing pressure tested ■ Daily monitoring w Well Design ■ Directional wells ■ Conductor casing driven or cemented to surface ■ Surface casing cemented to surface ■ Production casing set in Moraine Reservoir, cemented at least 500 ft MD above known hydrocarbon bearing formations ■ Likely horizontal liner with swell packers ■ Likely hydraulically stimulated 16" Conductor to -110' 4-1/2" Tubing 10-3/4" Surface Casing Cemented to surface 7-5/8" Production Casing Planned TOC 500' MD above HC 7-5/8" Liner Hanger/packer 1/1 111 21 Cono4hillips ........ • 0 Development Scope Plans are to initially develop the Moraine Reservoir from the existing KRU drill site 3S which is connected to the KRU CPF-3 One or more new drill sites may be constructed in future development 3S Drill Site Facilities Designed to accommodate 26 wells on 20-foot centers ■ Individual well lines comingle into common headers that feed into cross-country pipelines for transport to CPF-3 ■ Moraine Oil Pool to be commingled with production from other Kuparuk River Field Oil Pools in surface facilities 22 Conoco`Phillips ...... • 0 PUM WelOillfrom of iOooguruk I Caelas P twnn p 140. 1,�rC! Wet Oil at - 36% water Ku ruk Pipeline cut is sent from CPF3 Pe Prudhoe Bay to CPF1 and CPF2 // And other North Kuparuk River Slope oil Held production CPF - 2 /1'/� Milne Point III (��{� i Sales Oil - Hilcorp c`F -' Legend _ oil Alpine sales on ENt Sales oil Enters KPL at CPF2 Enters KPL between CPF2 and CPFI ® Water Gas Comingied Produced Gas, Oil & Water m Fluids for continuous injection as a means for enhanced recovery ■ Source water from the Kuparuk seawater treatment plant ■ Produced water from all present and yet -to -be defined oil pools within the Kuparuk River Field, including without limitation the Kuparuk Oil Pool and the Moraine Oil Pool • Blend of KRU lean as with indigenous and/or Enriched hydrocarbon gas (MI). Ble g g imported natural gas liquids ■ Lean gas w Fluids planned for periodic injection ■ Fluids used during hydraulic stimulation in accordance with 20 AAC 25.283 ■ Tracer survey fluids to monitor reservoir performance including chemical and radioactive tracers ■ Fluids used to improve near wellbore injectivity (via use of acid or similar treatment) • ■ Fluids used to seal wellbore intervals which negatively impact recovery efficiency including cement, resin, gels and expandable particles ® Fluids associated with freeze protection (typically diesel, glycol or methanol) ■ Other standard oilfield chemicals such as corrosion and scale inhibitors, and emulsion breakers Dispersed clay in sandstone layers is not prone to swelling when in contact with water salinities expected w Analyses of water injection fluids ■ CPF-3 produced water injection ■ BaSO4 and CaCO3 ■ Scale risks become smaller as the injection water going deeper into formation ■ CPF-3 seawater injection ■ BaSO4 risk is high from wellbore throughout the mixing zone ■ CaCO3 risk is minor in reservoir beyond the near wellbore area ■ Incumbent scale inhibitor at sufficient residual in the CPF-3 produced water expected to control scale risk ■ Scale mitigation measures ■ Monitor inhibitor residual in the CPF-3 produced water before injection ■ Optimize the minimum effective concentration (MEC) of the incumbent scale inhibitor needed to control scale risk w No compatibility issues with Kuparuk River Field injection gas identified m Fluids used for hydraulic stimulation ■ Plan to include a mixture of water, gelling agents, and larger grain ceramic sand ■ Hydraulic stimulation operations will be performed in accordance with 20 AAC 25.283 25 = �.• ConocoPhillips Lower Confining Interval — HRZ ■ The HRZ is approximately 100 ft. to 150 ft. thick in the proposed AlO and Pool area, consisting of marine mudstones Proposed Pool - top Moraine marker down to the top HRZ marker ■ One coursing up package of turbidite deposits identified by seismic and well data Upper Confining Interval - top Torok Formation down to the top of the Moraine ■ Comprised of marine siltstone and mudstone slope deposits. Total thickness varies from 250 ft. to 1,000+ ft. Above the Upper Confining Interval - Hue Shale ■ Approximately 300 ft. to 1,000+ ft. thick, consisting of claystones and tuffaceous mudstones Conoa;killips Well: PALM No. 1 Alaska, Inc. _ Res�stivd�ShaL Neutron PorositY 1 OHMM 100 60 PU 0 Resistivity Med. Twu (ft.) MD Den 1 OHMM 100 1.55 GIO3 2,65 Gamma Rev t 7700 (M1) Rftstmty Dee Member Formation 0 W1 2001 it OHMM 100 3500 .-__. 3500 R Cn d 4000 4500 4500 5000 p 1 L C 5000 5500 r;, sswrt. Mo ° 0 UPPer a Moraine -_ n Lower .m Moraine ° WW 6043rt MD HRZ 26 - "...... """ ConocoPhillips ............ ............. • 0 w Geomechanical samples within overburden and reservoir from Moraine 1 core ■ Data from 29 samples between 5,100 ft. MD to 51295 ft. MD from Moraine 1 ■ Triaxial Compression Tests ■ Unconfined Compression Tests ■ Overburden Fracture Toughness Test ■ Results from tests indicate definite confining barrier above the Moraine Oil Pool Calibrated modeled strength curves to core data Modeled curves match 13.5 ppg leak -off test (LOT) results from 3S-620 (red dot on fracture pressure curve) Palm 1 equivalent stratigraphy sampled for geomechanical work in Moraine 1, highlighted in orange on Palm 1 • r� u w Conducted internal containment assurance analysis ■ CPAI has subsurface containment assurance standard which includes a multi -discipline periodic containment review m Three scenarios evaluated utilizing `GOHFER' simulation modeling package ■ Scenario 1: Water injection for HZ well without propped fracture ■ Scenario 2: Water injection for HZ well with propped fracture ■ Scenario 3: MI injection for HZ well without propped fracture w Analysis inputs ■ Moraine 1 logs, fluids and core data ■ 3S-620 frac and production data ■ Palm 1 (blue star on figure) core and log data w Modeling analysis indicates ■ Injection fracture fluids are contained ■ Hydraulic fracture fluids are contained Note: GOHFER is a 'Barree & Associates LLC' Product Legend nk Ua o ; akBWMtYy Laaae BlwyI -- AlO and Pool Mea------_-- Oooguruk OS Pads _ _. _..__. 3S (ex.) ;o Well PeneUadoa a - .Mw—GOPool .. .iM . Fault . M w • 3N �;- Kuji N •River .. . . . . . . . . �A• • � �/3G• 3B• .• • 3C / •T F• • , •• • • 1Q Placer =W •ze • 2T • • ZK • • 2A • 0 n Top Upper Moraine/Top Pool ••'•.fir ;•;��•>•r Palm No.1 (COPAI) UM Top UM Base LM Base -2376 -792 Net Pressure (psi) 792 2352 Base Upper Moraine/Top Lower Moraine 3936 5520 5100. o --" 5268.0 5292.0 5316.0 z rr+ V Vf Vf Y M 479.166 610,1 Id 739,583 29 = ConocoPhillips .......... 0 r, X 4-1 M L C 0 N i M N 0 Top Upper Moraine/Top Pool Proppant Concentration (lb/ft2) Palm No.1 (COPAI) Base Upper Moraine/Top Lower Moraine 30 """°" ConocoPhillips ..... Top l Moraine/Top Pool �._... __ .1" 7 t Ii t 4 ' � • f� V1■■tN■■1■1■ll■If■1■Nfl f ilf !tf■UI■ 1• 11 = IM,! ■ft■t■■lf!■■1■1■N! : ; : ; : ' • • : • ■Iflm■1 Nu�f �If�■1■N�n�loll%1l11■Il�l� N■�1�■■�■UIlfU■1N�■ ■ I �� °I■tll■lf1�IH1�� Hfl■If — NN■■1■11 N■!ULu U■UI■■1■INII 1IN■1■NN■!1■UIwII it lli_- illill lilt ensure (psi)g r . oil tgUl.�l■'' •1■N �1■1 mN ■INfmmmi IHHU�U1 ■■ t t 1 1 N■t■ I IHI /I N■WW� U U■t* ■■!! !W■t I 1 1 14_ 1 1 1 �� 1 1 ■ Uri■��U 1■t■111 I nil ■I,'�t'1n H NH■ ■1■iq ■I ■UU H#hU I■ INn I■IHI t N ■1 I �1 ■1 ! 1 ■ t■Ht U ■■1 ■1■ NNEBIl 1 1■■1! �� HUIm■UN■ INI■I HUI 1■1�l1■!m■1W■U■1lIHIH#■1■N■ 1■1■■UN■IHINWNNI !IW ■ U■ 1 ■UlINHIHI■Im UINInW■tH U! ■1■ I >�■ 1■ IHI■1lI�I 1■ ■ Ut■ ! ■ ■ 1 ■ Uof 1 1■N tN ■1 1■■1 N U■U!■ .� tH mmm ! Hl Ulgl UtHIH■Nml INI■tH 1,i� ■ ,^ t�1 1 t#■1%1■■1■ -- •• - , # �: 1 # I lUIN UlUUfl ilfl■1 1 1 t �UHgM#■ 1■u��l� U■1■1■■ 1■ImNn N ! ■ UI■ N N■ ■1 to ■ 1 1 q f U � I WN ■ I ■ lI t■■■■■■ IIN �i nn■ IW�In �1 H� ■ folio illow UI „ 1� 1 U of IH .1 N � ■ ■■U■ 1 1 IN I p U ■1■ ••. N 1 �. �. � 1 W In #H ■ _ '■ul min IN ■ ■'>�' W # ■ �� 1■,t■ U1nN �� U r.. e , ■ t■ ._A 1■■ 1 Base Upper Moraine/Top Lower Moraine Oni • 0 Injection Type Estimated Wellhead Pressure (PSIA) Estimated Bottom -hole Pressure (PSIA) Average* Maximum** Average* Maximum** Water Injection 930 1190 3200 3500 Enriched Hydrocarbon 2440 2700 3200 3500 Gas Injection *Based on current operations at a true vertical depth of 5200 feet **Maximums vary according to correlated depth Assumptions • m Average injection gradient: 0.62 psi/ft m Maximum injection gradient: 0.67 psi/ft w Overburden pressure gradient: 0.72 psi/ft w Overburden fracture gradient: —0.82 psi/ft w CPF-3 Fluid gradient (water): 0.442 psi/ft m Gas gradient (MI): 0.15 psi/ft Rule 1. Field and Pool Names The field is the Kuparuk River Field, and the pool is the Moraine Oil Pool. 0 Rule 2. Pool Definition m The Moraine Oil Pool is defined as the accumulation of oil and gas common to and correlating with the interval within the Palm No.1 well between the depths of 5,630 ft. MD and 6,043 ft. MD (-5,144 ft. and -5,486 ft. TVDSS respectively). 0 Rule 3. Gas -Oil Ratio Exemption Wells producing from the Moraine Oil Pool are exempt from the gas -oil ratio (GOR) limit set forth in 20 AAC 25.240. • • ConocoPhillips Rule 4. Drilling and Completion Practices w Alternate casing and completion programs, in addition to those specified in the regulations, may be administratively approved by the Commission upon application and presentation of data which demonstrate the alternatives are appropriate, based upon sound engineering principles. In lieu of the requirements under 20 AAC 25.050(b), CPAI proposes that permit(s) to drill shall include: plan view, vertical section, close approach data, and directional data. In lieu of the requirements under 20 AAC 25.071(a), CPAI proposes that only one well per drill site is required to be logged for the portion of the well below the conductor pipe by either a complete electrical log or a complete radio -activity log unless the commission specifies which type of log is to be run. 36 ......., Rule S. Well Spacing w The requirements of 20 AAC 25.055 are waived for development wells in the Moraine Oil Pool. Without prior approval, development wells may not be completed any closer than 500 feet to an external boundary where working interest ownership changes. is 37 °'0°"""' ConocoPhillips Rule 6. Reservoir Surveillance Static bottom -hole pressure surveys will be conducted in all new injection wells prior to initiating injection. w Static surveys will be performed on production wells at the discretion of CPAI. is For annual pressure surveillance, a minimum of one (1) pressure survey will be conducted annually in the Moraine Oil Pool, concentrating on injection wells. w In lieu of stabilized bottom -hole pressure measurements, the alternative pressure survey methods below can be implemented: ■ open -hole wireline formation fluid pressure measurements, ■ cased hole pressure buildups with bottom -hole pressure measurement, ■ injector surface pressure fall -off, ■ static pressure surveys following extended shut-in periods, or ■ bottom -hole pressures calculated from wellhead pressure and fluid levels in the tubing of a stabilized shut-in injector sw All pressure surveys will be reported annually, rather than monthly, to reduce paperwork due to the limited number of surveys. Rule 7. Well Work Operations The following operations in production and enhanced recovery wells within the Moraine Oil Pool may be conducted without filing an application pursuant to 20 AAC 25.280(a): ■ perforate or re -perforate casing ■ stimulate ■ coil tubing operations with the exception of drilling or sidetracks 39 .........., 0 • Rule 8. Production Practices In lieu of the requirements under 20 AAC 25.230(a), CPAI proposes that each producing well will be tested at least monthly for the first 12 months, and then at least every three months thereafter. Cono4hillips • Rule 9. Administrative Action Upon proper application, the Commission may administratively waive the requirements of any rule stated or administratively amend the order as long as the change does not promote waste, jeopardize correlative rights, and is based • on sound engineering principles. is 41 .......... ........ Rule 1. Authorized Injection Strata for Enhanced Recovery Fluids authorized under Rule 3, below, may be injected for the purposes of pressure maintenance and enhanced hydrocarbon recovery within the proposed Moraine Oil Pool, which is defined as the accumulation of oil and gas common to • and correlating with the interval within the Palm No.1 well between the measured depths of 5,630 ft. MD and 6,043 ft. MD (-5,144 ft. TVDSS and -5,486 TVDSS respectively). 0 I Rule 2. Well Construction In lieu of the packer depth requirement under 20 AAC 25.412(b), the packer/isolation equipment depth may be located above 200 ft. measured depth from above the top of the perforations/open interval, but shall not be located • above the confining zone and shall have outer casing cement volume sufficient to place cement a minimum of 300' measured depth above the planned packer depth. 0 Rule 3. Authorized Fluids for Injection for Enhanced Recovery w Fluids authorized for injection are: ■ Source water from the Kuparuk seawater treatment plant ■ Produced water from all present and yet -to -be defined oil pools within the Kuparuk • River Field, including without limitation the Kuparuk Oil Pool and the Moraine Oil Pool ■ Enriched hydrocarbon gas (MI): Blend of KRU lean gas with indigenous and/or imported natural gas liquids ■ Lean gas ■ Fluids used during hydraulic stimulation ■ Tracer survey fluids to monitor reservoir performance (chemical, radioactive, etc.) ■ Fluids used to improve near wellbore injectivity (via use of acid or similar treatment) ■ Fluids used to seal wellbore intervals which negatively impact recovery efficiency (cement, resin, etc.) ■ Fluids associated with freeze protection (diesel, glycol, methanol, etc.) ■ Standard oilfield chemicals (corrosion inhibitor, scale inhibitor, etc.) Rule 4. Authorized Injection Pressure for Enhanced Recovery Injection pressures will be managed as to not exceed the maximum injection gradient of 0.67 psi/ft. to ensure containment of injected fluids within the Moraine Oil Pool. 0 ............... 45 aw Y,.+.w.+u.uw.. ConocoPhilli s ..::....+............. P Rule 5® Administrative Action w Upon proper application, the Commission may administratively waive the requirements of any rule stated or administratively amend the order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering or geoscience principles, and will not result in an increased risk of fluid movement into freshwater. • Questions? 47 '------ ConocoPhillips ........ 0 0 Colombie, Jody J (DOA) From: Kowalewski, Kasper <Kasper.Kowalewski@conocophillips.com> Sent: Monday, May 09, 2016 8:49 AM To: Wallace, Chris D (DOA) Cc: Colombie, Jody J (DOA) Subject: Error in Moraine Oil Pool Application Chris, There is an error on page 24 and 26 of the Moraine Oil Pool Application. On paragraph 5 on page 24, the application references 20 AAC 25.030(a), the intent was to reference 20 AAC 25.230(a). - The sentence reads "In lieu of the requirements under 20 AAC 25.030(a), CPAI proposes..." - It should read "In lieu of the requirements under 20 AAC 25.230(a), CPAI proposes..." The same error is on page 26, which lists the proposed rule: - Rule 8 reads "in lieu of the requirements under 20 AAC 25.030(a), CPAI proposes that each producing well will be tested at least monthly for the first 12 months, and then at least every three months thereafter." - It should read "In lieu of the requirements under 20 AAC 25.230(a), CPAI proposes that each producing well will be tested at least monthly for the first 12 months, and then at least every three months thereafter." Sorry in advance for the inconvenience. This will be corrected for the hearing tomorrow. Take care, KASPER KOWALEWSKI I Petroleum Engineer (Moraine) CoP Alaska Business Unit I CPF2 — A, B, & C CPF3 — Moraine 700 G Street, Anchorage, AK 99501 1 ATO-1356 Office/Cell 1 +1.907.265.1363/ +1.907.231.0369 kasper.kowalewski@cop.com 0 E Bettis, Patricia K (DOA) From: Wallace, Chris D (DOA) Sent: Wednesday, April 27, 2016 9:32 AM To: Bettis, Patricia K (DOA) Subject: FW: Correction to Moraine Pool Rule CO-16-007 and AIO 16-011 Applications Patricia, Can you please make the minor changes, Thanks, Chris From: Kowalewski, Kasper [maiIto:Kasper.Kowalewski@conocophiIIips.com] Sent: Wednesday, April 27, 2016 8:21 AM To: Wallace, Chris D (DOA) Cc: Urnlauf, Kelly K Subject: Correction to Moraine Pool Rule CO-16-007 and AIO 16-011 Applications Hi Chris, Below is the correction for the Moraine Oil Pool and AIO applications. Please let me know if you need anything else. The sentence "Two dominant sets of normal faults are present in the proposed development area: an early Cretaceous NNE to SSW striking system and a younger, Cenozoic WNW -ESE striking set" should be replaced with "Two dominant sets of normal faults are present in the proposed development area: an early Cretaceous WNW -ESE striking system and a younger, Cenozoic NNE to SSW striking set." The change applies to the following... Pool Application — page 8 of 26, paragraph 3, 11t sentence AIO Application — page 9 of 49, paragraph 3, 5 th sentence Kindest Regards, I�ASPER KOWALEWSKI I Petroleum Engineer (Moraine) CaP Alaska Business Unit I CPF2 --A, B, & C CPF3 — Moraine 700 G Street, Anchorage, AK 99501 1 ATO 1-356 Office/Cell 1 +1.907,265,1363/ i-1.90T231,0369 kasper.kowalewski@cop.com 0 Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Re: Docket Number: CO- 16-007 and AIO 16-011 Moraine Oil Pool, Kuparuk River Field Pool Rules and Area Injection ConocoPhillips Alaska, Inc., by applications received March 31, 2016, requests the Alaska Oil and Gas Conservation Commission (AOGCC) issue orders under 20 AAC 25.520 and 20 AAC 25.460, to establish pool rules and authorize enhanced recovery operations on an area injection basis to govern the development of the proposed Moraine Oil Pool in the Kuparuk River Field. The AOGCC has scheduled a public hearing on this application for May 10, 2016, at 9:00 a.m. at 333 West 7th Avenue, Anchorage, Alaska 99501. Comments must be received no later than the conclusion of the May 10, 2016, 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 (907) 793-1221, no later than April 28, 2016. 4115-0� Daniel T. Seamount, Jr. Commissioner 1�1 0 STATE OF ALASKA ADVERTISING ORDER NOTICE TO PUBLISHER SUBMIT INVOICE SHOWNG ADVERTISING ORDER NO., CERTIFIED AFFIDAVIT OF PUBLICATION WITH ATTACHED COPY OF ADVERUSMENT. I I ADVERTISING ORDER NUNMER AO-16-018 FROM: Alaska Oil and Gas Conservation Commission AGENCY CONTACT: Jody Colombie/Samantha Carlisle DATE OF A.0. 04/05/16 AGENCY PHONE: 1(907) 279-1433 333 West 7th Avenue Anchorage, Alaska 99501 DATES ADVERTISEMENT REQUIRED: COMPANY CONTACT NAME: PHONE NUMBER: Z-6/2016 FAX NUMBER: (907) 276-7542 TO PUBLISHER: Alaska Dispatch News SPECIAL INSTRUCTIONS: PO Box 149001 Anchorage, Alaska 99514 71 7 .77 LFGA LAS$IFIED THEWfSpeclify _MLE A, Who DESCRIPTION bellovv) PRICE CO 16-007 and AIO 16-011 .. ...... ......... ...... ..... Initials of who prepared AO: Alaska Non -Taxable 92-600185 ......... I ................... .... w ....... . ...... ............. ..... . ............ EA .., ERT.!FIE -AFFH)AVTI-OF.-'-'- ::::::OR-D NO.:r- D ................. .................. D epartinent of Administration Division of AOGCC 333 West 7th Avenue Anchorage, Alaska 99501 __Yye I of 1 Total of All Pages $1 REF Type Number Amount- Date Comments I PvN ADN84501 2 Ao AO-16-018 3 4 FIN AMOUNT Sy Appr Unit PGM LGR Object FY DIST LIQ 1 16 021147717 3046 16 2 3 4 Purc ig 01 JAI Purchasing Authority's Signature Telephone Num her c V #3nd recei ing agen y n;r;(rmust aoRpr on all invoices and documents relating to this purchase. 2. h state is registered for tax free transactiont-under Chapter 32, IRS code. Registration number 92-73-0006 K. Items are for the exclusive use ofthe state and not for re a ............. .......... ......... ............ .................. ......... . . ................ ............ .... f6'n:' ]Fse"o, V'O�'! .... ........... ..... .... ... ..... ............ ....... ........... . 0 :A.o'::*::'::'::'::'::*::'::'::':.0 ....... ... ........... ................ ............. .. ................ I ............ ... .... . .. ... ................................ ... ................... ........... ..... ......... ................ Form: 02-901 Revised: 4/5/2016 0 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Wednesday, April 06, 2016 8:49 AM To: Ballantine, Tab A (LAW); Bender, Makana K (DOA); Bettis, Patricia K (DOA); Bixby, Brian D (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Cook, Guy D (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Herrera, Matthew F (DOA); Hill, Johnnie W (DOA); Jones, Jeffery B (DOA); Kair, Michael N (DOA); Link, Liz M (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Quick, Michael J (DOA); Regg, James B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Wallace, Chris D (DOA); AKDCWellIntegrityCoordinator, Alan Bailey, Alex Demarban; Alexander Bridge; Allen Huckabay; Amanda Tuttle; Andrew VanderJack; Anna Raff, Barbara F Fullmer, bbritch; bbohrer@ap.org; Bob Shavelson; Brian Havelock; Bruce Webb; Burdick, John D (DNR); Caleb Conrad; Cliff Posey; Colleen Miller, Crandall, Krissell; D Lawrence; Dave Harbour, David Boelens; David Duffy; David House; David McCaleb; David Steingreaber, David Tetta; 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; Gordon Pospisil; Gregg Nady; gspfoff, Hyun, James J (DNR); Jacki Rose; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jerry McCutcheon; Jim Watt; Jim White; Joe Lastufka; Radio Kenai; Easton, John R (DNR); Jon Goltz; Juanita Lovett; Judy Stanek; Houle, Julie (DNR); Julie Little; Karen Thomas; Kari Moriarty; Kazeern Adegbola; Keith Wiles; Kelly Sperback, Gregersen, Laura S (DNR); Leslie Smith; 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; Mealear Tauch; Michael Calkins; Michael Duncan; Michael Moora; Mike Bill; MJ Loveland; mkm7200; Morones, Mark P (DNR); Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nick W. Glover, Nikki Martin; NSK Problem Well Supv; Oliver Sternicki; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillem; Renan Yanish; Richard Cool; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Skutca, Joseph E (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer, Stephen Hennigan; Moothart, Steve R (DNR); Suzanne Gibson; sheffield@aoga.org; Tania Ramos; Ted Kramer; Davidson, Temple (DNR); Teresa Imm; Thor Cutler, Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Aaron Gluzman; Aaron Sorrell; Ajibola Acleyeye; Alan Dennis; Ann Danielson; Anne Hillman; Bajsarowicz, Caroline J; Brian Gross; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Don Shaw; Eric Lidji; Garrett Haag; Smith, Graham 0 (DNR); Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Holly Pearen; Jason Bergerson; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Kasper Kowalewski; King, Kathleen J (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck, Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Franger, James M (DNR); Morgan, Kirk A (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Pollard, Susan R (LAM; Talib Syed; Terence Dalton; Tina Grovier (tmgrovier@stoel.com); Todd, Richard J (LAW); Tostevin, Breck C (LAW); Vicky Sterling; Wayne Wooster, William Van Dyke Subject: Public Notice CPA Moraine Oil Pool, Pool Rules and AIO Attachments: Dockets CO 16-007 and AIO 16-011.pdf .Totty T. Cohmlbie ,'10(iCCSpeciat A�sislaiit ' 0 -.41 ska Oit awt (jas Conservatimi Covmiiission 11"est 7"' _Avellule "AlIchorage, Atiiska o�) _5o i 0IliCC: �')F(.IX: (�)0;7) 276-75_12 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, Vithout first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jody Colombie at 907.793.1221 or iody.colombie@alaska.aov. 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 PennyVadla George Vaught, Jr. 3201 Westmar Cir. 399 W. Riverview Ave. P.O. Box 13557 Anchorage, AK 99508-4336 Soldotna, AN 99669-7714 Denver, CO 80201-3557 Kazeern Adegbola Manager, GKA Development Richard Wagner Darwin Waidsmith North Slope Operations and Development P.O. Box 60868 P.O. Box 39309 ConocoPhillips Alaska, Inc. Fairbanks, AK 99706 Ninilchik, AK 99639 ATO-1326 700 G St. Anchorage, AK 99501 2-0 U4 Angela K. Singh 0 0 FRIE C, E i V E D MAR 3 1, 2016 NP-W10' Cono%coPhillips March 31s', 2016 Catherine P. Foerster, Chair Alaska Oil and Gas Conservation Commission 333 W. 7th Ave #100 Anchorage, Alaska, 99501-3539 RE: Application for Pool Rules Moraine Oil Pool, North Slope, AK Dear Commissioner Foerster: Kazeem A. Adegbola AOGCC Manager, GKA Development North Slope Operations and Development ConocoPhillips Alaska, Inc. ATO-1326 700 G Street Anchorage, AK 99501 phone 907.263.4027 In accordance with 20 ACC 25.520, ConocoPhillips Alaska, Inc. ("CPAI") as operator of the Kuparuk River Unit ("KRU") and on behalf of the Working Interest owners, requests that the Alaska Oil and Gas Conservation Commission ("Commission") approve CPAI's application for a Conservation Order to classify the Moraine Oil Pool and to prescribe pool rules for development of the Moraine Oil Pool within the Kuparuk River Field as defined by the Commission and within the KRU as defined in the KRU Agreement by and between the Alaska Department of Natural Resources. CPAI requests that the hearing date for this application be scheduled as soon as possible after the 30-day notice period has concluded. Enclosed are two printed originals of the application and a disc containing an electronic version of the application. Please contact Kasper Kowalewski (265-1363) if you have questions or require additional information. Regards, Kazeem Adegbola Manager, GKA Development North Slope Operations and Development Cc: Rebecca Swensen, KRU secretary Rob Kinnear, BP Exploration Alaska Inc. KRU WIO Representative Glenn C. Fredrick Chevron U.S.A. Inc. KRU WIO Representative Gilbert Wong ExxonMobil Alaska Production Inc. KRU WIO Representative Enclosures (3) 0 0 ConocoPhillips March 31s, 2016 Catherine P. Foerster, Chair Alaska Oil and Gas Conservation Commission 333 W. 7th Ave #100 Anchorage, Alaska, 99501-3539 RE: Application for Pool Rules Moraine Oil Pool, North Slope, AK Dear Commissioner Foerster: Kazeem A. Adegbola Manager, GKA Development North Slope Operations and Development ConocoPhillips Alaska, Inc. ATO-1326 700 G Street Anchorage, AK 99501 phone 907.263.4027 In accordance with 20 ACC 25.520, ConocoPhillips Alaska, Inc. ("CPAI") as operator of the Kuparuk River Unit ("KRU") and on behalf of the Working Interest owners, requests that the Alaska Oil and Gas Conservation Commission ("Commission") approve CPAI's application for a Conservation Order to classify the Moraine Oil Pool and to prescribe pool rules for development of the Moraine Oil Pool within the Kuparuk River Field as defined by the Commission and within the KRU as defined in the KRU Agreement by and between the Alaska Department of Natural Resources. CPAI requests that the hearing date for this application be scheduled as soon as possible after the 30-day notice period has concluded. Enclosed are two printed originals of the application and a disc containing an electronic version of the application. Please contact Kasper Kowalewski (265-1363) if you have questions or require additional information. Regards, Kazeem Adegbola Manager, GKA Development North Slope Operations and Development Cc: Rebecca Swensen, KRU secretary Rob Kinnear, BP Exploration Alaska Inc. KRU WIO Representative Glenn C. Fredrick Chevron U.S.A. Inc. KRU WIO Representative Gilbert Wong ExxonMobil Alaska Production Inc. KRU WIO Representative Enclosures (3) CPAI Application for Pool Rules* March 2016 Page 1 of 26 lowe" ConocoPhillips APPLICATION FOR POOL RULES OF THE MORAINE OIL POOL March 311, 2016 1. Introduction 2. Geology 3. Reservoir 4. Reservoir Development 5. Drilling 6. Well Operations 7. Facilities 8. Proposed Moraine Oil Pool Rules List of Figures 1 . Proposed Moraine Oil Pool Area 2. Palm 1 Type Log 3. Palm 1 Type Log Extended Stratigraphy 4. lsochore Moraine Oil Pool 5. West to East well cross section across the Pool Area 6. North to South well cross section across the Pool Area 7. Depth Structure Surface Map of Moraine Oil Pool 8. Plots showing simulated waterflood recovery in the Moraine Reservoir in terms of time (top) and hydrocarbon pore volumes (HCPV) of water injected (bottom) 9. Plot showing simulated incremental recovery in the Moraine Reservoir due to injecting gas of varying levels of enrichment 10. Plot showing incremental recovery in the Moraine Reservoir vs. cumulative rich gas injected 11. Proposed Moraine producer well schematic CPAI Application for Pool Rulese March 2016 Page 2 of 26 1. INTRODUCTION Document Scope This application for Pool is submitted for approval by the Alaska Oil and Gas Conservation Commission ("Commission") to define the proposed Moraine Oil Pool and establish Pool Rules for the oil pool pursuant to 20 ACC 25.520. ConocoPhillips Alaska, Inc. ("CIPAI"), submits this application to the Commission in its capacity as Operator of the Kuparuk River Unit ("KRU"). The scope of this application includes a discussion of geological and reservoir properties of the proposed Moraine Oil Pool as they are currently understood, and CIPAI's plans for reservoir development, reservoir surveillance, and well construction. This application and supporting testimony will enable the Commission to establish rules that will allow economic development of resources, promote greater ultimate recovery, and prevent waste within the Moraine Oil Pool. Confidential data and interpretation concerning the Moraine Reservoir, as defined below in this application, may be provided to the Commission by CPAI as additional support for this application in accordance with the provisions of AS 31.05.035 and 20 ACC 25.537. The proposed area to be covered by the Moraine Oil Pool Rules is shown in Figure 1. All of the proposed Moraine Oil Pool and the area to which the proposed Area Injection Order ("AIO") applies is within the KRU, with a special caveat for two leases. These two leases proposed for inclusion in the Moraine Oil Pool and the AIO are ADL392374 and ADL392371, depicted on Figure 1. Those two leases are not presently within and part of the KRU. Historically, those lands were within the KRU in 1984, when the Environmental Protection Agency adopted the aquifer exemption, and in 1986, when the Commission incorporated the KRU aquifer exemption. CPAI plans to apply to the Department of Natural Resources for KRU expansion to include the two additional leases into the KRU again prior to drilling any development wells (producers or injectors) in the two leases. Well Palm 1 provides the type log for the Moraine Oil Pool shown in Figure 2. CPAI requests that the single turbidite progradational package of the Upper Moraine Member and Lower Moraine Member, as shown in the correlative section on the type log from measured depths 5,630 ft. and 6,043 ft. or -5,144 ft. true vertical depth sub -sea ("TVDSS") to -5,486 ft. TVDSS, be included in the Pool. The base of the Moraine Oil Pool is defined by the top of the HRZ Formation and the top is defined by the top Moraine marker within the Torok Formation (Figures 2 and 3). Geographical Area The Upper and Lower Moraine Members are a turbidite fan system deposited in the northwest portion of the KRU and beyond, to the north and west. They are comprised of thinly bedded, laminated sandstones, siltstones, and mudstones. The Moraine Oil Pool lies between -4,940 ft. TVDSS and -6,190 ft. TVDSS within the Kuparuk River Unit (KRU). Project Background The Moraine Reservoir was first assessed in 1965 by Sinclair with the Colville 1 well, while targeting a deeper zone. The reservoir was further tested in the 1980s by Texaco in the Colville Delta 2 and Colville Delta 3 wells; both wells were initially unstimulated and produced insignificant rates (for locations, see Figure 1). However, the Colville Delta 3 well produced at modest rates after fracture stimulation operations. In the 1 990s, ARCO Alaska, Inc. (now known as CPAI) drilled two exploratory wells, Kalubik 1 and Kalubik 2, to evaluate the Moraine Reservoir. Unstimulated production of the Kalubik 1 yielded minimal oil production. During much of the early history, the Moraine Reservoir was a peripheral target in exploration wells that tested other reservoirs with only a few operators collecting data which were targeting deeper reservoirs. CPAI Application for Pool Rules* March 2016 Page 3 of 26 In 2010-2012, three producer wells (ODST-39 API# 50-703-20572-00-00, ODST-45A API# 50-703- 20577-01 -00 and ODST-46 API# 50-703-20631 -00-00) were drilled and completed in the Upper Moraine Member in the adjacent Oooguruk Unit by Pioneer with initial production from these wells in the range of 350 to 600 BOPID with 10-50% initial water cut (Commission public data). In 2013, CPA[ hydraulically stimulated the Upper Moraine Member within the 3S-1 9 Kuparuk C-sand producer and obtained flow rates of 250-300 BOPID from the reservoir. In 2015, CPAI drilled and cored the Moraine 1 well to further evaluate the reservoir properties of the reservoir using cores, logs, and fluid samples. Also in 2015, CPAI drilled the horizontal well 3S-620 with a 4,200 foot lateral and stimulated the well with an eight stage hydraulic fracture program. The initial production of the 3S-620 was 1,575 BOPID with 75% water cut. CPAI plans initial development of the Moraine Oil Pool from the e)dsting onshore 3S drill site. On the surface, Moraine Oil Pool production will be commingled with other production as it is carded to the field Central Processing Facilities ("CPF") at CPF-3 and then on to CPF-1 and CPF-2. If initial development of the Moraine Reservoir from drill site 3S is successful, additional drill sites may be constructed for further development. All Moraine Reservoir production Vill be measured as described in Section 7 of this application, without any down -hole commingling with production from other pools prior to measurement. Subject to Commission approval of the facilities and measurement program, no separate approval for commingling is necessary under the standards of 20 AAC 25.215 and 20 AAC 25.245. CPAI Application for Pool Rules March 2016 w w w w LL LL Page 4 of 26 6040000E 6020000E 600000OF 598DOOOF N-iw-- tl mxSPo)°.Afl ADLWWA AO00M ADL»K» ADL1aa37i ADIMItd3 I A,,,.,. A,..,, IVIK I ADL20MO ANn�4 ------ AM3V,= 0) ODST-" 9 Ocraguruk AWNS= Unit AMYrm 11\ /I ODST-45A'S of COLV DELTA 2 N AM316M NU Al A01.311"m Ameam AM 0715N COLV DELT I P B I Kuparu River nit 4 39-620 MORAINE 1� 3S-19 PALM I A"IWI AIX-Vftft ACLUDW AIil013SY AOLJBpftn Ab1pxYlti AOLp25611 A., WA 1 2 COLVILLE 1 AIN MILES ADL*ZS'S5l AM02VA9 ADL*2%0 ADLOrA43 AOIrl Legend (Placer Unit .......... MIMI ADL2K*. ADUOIW2 AOL""' ADL1111" MAW 8''Y L... P-1 . ... ... ... ......... .......... Leases W,t11f11 A* OW ftwwe.W0UL%k*KRV- 17,777= IJACKWIU. = am Pew Area .......... . ...... j AM.11IIIIAW.UkbbnADLOMM 04 &W Daft ...... ..... .... I 04000OF N 020000E N 0 000000F N 080000F N 0 5960000E j ub 59600OOr N Kuparuk River Unit (KRU) outline LL LL displayed here is the 1 1th I expansion I - Figure 1: Outline of AlO and Pool area highlighting leases outside of the Kuparuk River Unit (KRU) CPAI Application for Pool Rules* March 2016 Page 5 of 26 Well: PALM No.l • ✓ ConocoPhillips Alaska, Inc. Rr'ystivitY XU4.. Resisti%nty Shai. 1 OHMM 100 Neutron Porosity 60 PU 0 Resistivity Med. TVD8s MD Density 1 OHMM 100 Ot) (ft) 165 GIC3 2.65 Gamma Ray1 600 Resistive DeepMember Formation 0 GAR 200 1 OHMM 100 5050 5550 5100 5600 .... 5.630 ft. MO 5150 5650 C 5200 5700 0 O O ` CL 5250 5750 a O LM 5800 C� 5300 O O 5850 C C 5350 R 5900 0 >` 4 5400 5950 3 0 5450 6000 J 6050 6 043 ft MO 5500 N 6100 5550 6150 5600 Figure 2: Defining well, Palm 1, highlighting Pool interval CPAI Application for Pool Rules• March 2016 Page 6 of 26 • ConocdP illips Well: PALM No. 1 Alaska, Inc. kesis(r. (y XL) eL i OHMM 1i' Resistivity Shal. 1 OHMM 100 Neutron Porosdy 60 PU 0 Resistivity Med. T` DSS (ft.) MD Density 1 OHMM 100 1.65 G/C3 2.65 (hl Gamma Ray 1: 2700 Resistivity Dee Member Formation 0 GAR 200 1 OHMM 100 3500.E — —. - 3500 s U) a� 4000 TT� i 4000 i 4500 t i 4500 ►/ 5000 O LM O 5000 5500 5,630 ft MD a - Upper n Moraine �i Lower � CO . Moraine � 6000 6,043 ft MD H RZ Figure 3: Defining well, Palm 1, highlighting Pool interval with respect to the upper and lower confining intervals CPAI Application for Pool Rules* March 2016 Page 7 of 26 2. GEOLOGY Pool Identification The Moraine Oil Pool is defined as the accumulation of hydrocarbons common to and correlating with the interval between the measured depths of 5,630 f.t and 6,043 ft. (-5,144 ft. and -5,486 ft. TVDSS respectively) in the Palm No. 1 well (Figure 2). It is occasionally referred to as the Moraine Reservoir. Using well data, the above defined Moraine Oil Pool is divided into two major Members: the younger, Upper Moraine Member with higher sand concentrations and the older, Lower Moraine Member of the same turbidite progradational package. Using seismic data, it is not possible to differentiate these internal member divisions of the Moraine Reservoir. The Upper and Lower Moraine Members are within the Torok Formation as a part of the Brookian Megasequence. The entire Torok Formation extends from the top High Radioactive Zone ("HRZ") marker to the top Torok marker with the Moraine sequence extending from the top HRZ marker to the top Moraine marker within the Torok Formation (Figure 3). Lower Confining Interval Below the Moraine Oil Pool is the HRZ shale. The H RZ is approximately 100 ft. to 150 ft. thick in the proposed area of development, consisting of marine mudstones. Recommended Pool The top Moraine marker down to the top HRZ marker is one progradational package of turbidite deposits identified by seismic and well data. A detailed description is provided under the Stratigraphy and Sedimentology section. Upper Confining Interval The top Torok Formation down to the top of the Moraine is a series of progradational packages comprised of marine siltstones and mudstones slope deposits. Total thickness varies from 250 ft. to 1,000+ ft. Above the Upper Confining Interval The Hue Shale is above the Torok Formation. It is approximately 300 ft. to 1,000+ ft. thick, consisting of claystones and tuffaceous mudstones. Stratigraphy and Sedimentology The Upper and Lower Moraine Members consist of Lower Cretaceous Brookian slope to basin floor turbidite deposits comprised of thinly laminated, very fine to fine-grained sandstones, siltstones, and mudstones. The total proposed Moraine Oil Pool thickness varies from 60 to 640 ft. (Figure 4). Individually, the Upper Moraine Member ranges from approximately 10 to 315 ft. thick, and the Lower Moraine Member ranges from approximately 50 to 325 ft. thick. The gross depositional model for the Members infers a shelf edge delta delivering sediment via slope gullies to the basin slope and basin floor. Similar to other turbidite deposits, the sandstone and siltstone beds are interpreted to be locally continuous sheet -like deposits from unconfined flow, developing layered lobe complexes. Individual beds range in size from less than an inch to a few feet. Despite the thinly bedded nature of the reservoir, the sandstone and siltstone beds are interpreted to be laterally continuous on a local scale (100-2,000 ft. laterally), with poor vertical permeability due to the interbedded mudstones. Available core and well log data lack evidence of erosion, suggesting the lobes are largely uninterrupted by channels or major scour events. The reservoir gradually thins toward the southeast and southwest away from the paleoslope (Figures 5 and 6). The reservoir is also poorly developed at the paleoslope-basin interface to the west. The Moraine Oil Pool is capped by a series of progradational slope deposits of siltstones and mudstones (see Upper Confining Interval section). CPAI Application for Pool Rules* is March 2016 Page 8 of 26 The sandstone and siltstone beds range in thickness from less than an inch to a few feet. Sand grains range in size from very fine to fine-grained with rare occurrences of medium sand. The sandstones are typically comprised of 50-70% quartz, 1-10% feldspar, and 15-30% lithic fragments (dominantly metamorphic) with contributions from clay minerals and organic debris. Porosity values from core data range from 15-28% with an arithmetic mean of 19% in the sandstones and siltstones while air permeability values from core data range from 0.5-93 mD with an arithmetic mean of 5 mD in the sandstone and siltstones. The mudstones are dominated by clay minerals, mainly illite with minor amounts of smeGtite, chlorite, and kaolinite. Based on core data, gross sand content varies between 30- 60%. Sand content increases up section from the base of the Lower Moraine to top Moraine of the Upper Member. Water saturation estimates for reservoir sandstones and siltstones; range from 30 to 85%. Structure and Trap The Upper Moraine Member ranges in depth between -4,940 and -5,880 ft. TVDSS. Likewise, the Lower Moraine Member ranges in depth between -5,240 ft. and -5,920 ft. TVDSS. Both Members generally dip to the southeast but are flexed over the Colville High (Figure 7). The Colville High is a broad southeast plunging anticline that developed after the deposition of the Moraine deposits. Two dominant sets of normal faults are present in the proposed development area: an early Cretaceous NNE to SSW striking system and a younger, Cenozoic WNW -ESE striking set. While the early Cretaceous set minimally offset the reservoir, the total vertical offset from the Cenozoic set can be as much as 60 ft. Due to the thinly bedded nature of the reservoir, faults may act as barriers to flow but should minimally impact intended development plans. Despite the presence of faulting, much of the trap is stratigraphic with a structural component from the broad anticline. Mudstones and siltstones below and overlying the Moraine Oil Pool provide a seal for the oil column. Defining Net Pay The thin -bedded deposits within the Moraine Members are most often below the vertical resolution of standard well logging tools. The thin bed effect on well log data often suppresses or averages the expected signatures between the interbedded sandstones and mudstones, calculating lower pay counts than expected. However, total pay is higher than that indicated by standard logging tools, as demonstrated by production data. To account for the thin -bed effect, net pay calculations rely on advanced logging, log analysis, and core data. Based on CPAI's recent interpretation, the most meaningful interpreted logs to consider when defining net pay are total porosity and water saturation. Water saturation cutoffs between 50% and 75% along with a total porosity cutoff greater than 15% generally identify net pay within the Moraine Oil Pool. CPAI Application for Pool Rules March 2016 Page 9 of 26 Figure 4: Moraine Oil Pool Isochore with faults, mapped interval is highlighted in yellow on corresponding Palm 1 log for reference AID$Ka. Inc. Pnim Pln 1 Raven sn,y. N•ulral 1 f>HMM lw R Sya e0 PU 0 * MO / OHMM 1w Oens G•a•n•R (1t) (e•lo• + 1a{ Roe•.- 165 GIC3 265 OHMM 100 0 GAPI 2w sow ssw 1 t 51w •y]] sego s150 t 4a, s200 5701 STw Sew - r _ t � 6M. O ;. - i i sew � � � r swp i9;0 fi ,3 J uw vow 8050 Sw0 r - 51w x� 6150 r� kr 'i SBw 1 Top Moraine/ Tap Upper Morame/ Top Pool •Base Lower Moraine Base Pool/ Top HRZ W W LAW$ Q ly u s QWW, $$ ,ZQQdj 604000 Moraine Oil Pool °40°°0F N Isochore r ;atil" •• 1 L f •Qdoguruk jUnit , , P it 6020000E N, _ Oil Pool `••^'• ', a 01 N v �00 90 •, 20000E N Moraine Isochore ti .y / � ' m . .� •• Cl = loft.640 `� tee'; `� f ; o • • 0 600 575 550 525500 a 0 N` _ •. . •Epp - 5980000E 75 450 425 375 �W 350 275 250 225 175 150 100 60 0 11 2 MILES LE -.--J T: Unit 5960WOF N KRU outline displayed LL here is the 11 th expansion ,,! , , • K ppru 'River nit 'h i .• t �n Q1c �`' 0 0 .LO�'I 1q . • . a ' • • •6000000F N pad •" � 'laa • , o 598000OF N 10 o 0 0 11 //!j_ Legend Coastline Unit Boundary .- .. Lease Boundary ....� r 1 1 om • $` s - A10 aMl Pool Area 1 1 6----------1 Well Penetration 't c� _._ _ _ _ • In Helaine ON PO01 .. _.... _-. • • • • •QQ 596000OF N LL CPAI Application for Pool Rules March 2016 Page 10 of 26 West to East Structural Cross Section Gamma Ray Resistivity GAPI TVD55 MD ohmm 0........180 (n•) (ft.) 1......100 W 8300 -4950 8350 - 8100 _ -5000 8450 0500 5050 9550 - •5100 8500 •5350 - 8700 8750 •5200 - 8800 - 8850 •5250 - 8900 8950 -53M •5350 9050 9100 -5100 9150 _ -5450 9200 - •l950 5400 •5000 _ 5450 5500 -5050 5550 Sloe 5600 5650 -5200 5700 -5250 _ 5750 - -- -4300 5850 -53W 5900 •5400 5550 - .5450 t 6000 Upper Moraine Lower ; Moraine',-' 9800 •49" - 9850 I� 9900 ' 9950 -5000 10000 ' (I 10050 .5050 = 10100 10150 . 5100 10200 = 10250 " 10300 I -5150 30350 _ 10. -5200 - 10450 - 10500 _.i.. 1000 r aruT :--. Tm�' •r ` 1 mile •5300 _ 10650 - - - 10700 ' 5350• 18800 -5400 10050 _ I� � 10900 _ I .5450 10950 I 5300 5350 z Sl00 5t50 6500 5550 - pp 5600 17. - .SZ00 - Soo I 1 Sno -5250 _ 5750 _ I -- 33D� E950- - 1 •5300 5000 I 6900 5950 •5350 �' ` ; •5350 = 6950 = I III I �' - 5900 - - - - - -5l00 — 5950- .5400 7000 I ' 7050 ; •5450 8000 Soso _ I 1. 7100I' I - 605 0 bunu -5500 1000 5500 44 '5500 -5500 6100 6100 21050 3450 5550 -5550 -55W 72009250 - - "- . 6150 _ I 7M0 _ _ 1200 •4800 9/00 ! - •5600 3600 13150 = i -5600 _ 1 .. -5600 9/50 I - 8200 _ 11200 - { ' 73M 8250 -5650 _ 9500 - -5650- 8250 - - 5650 - - 11250 I -5850 - 7350 .5650 -- 1300 •5700 _ 9550 1 -5700 _ 6300 { - -5700 I1�0 _ _5700 7l00 I -5700 6340 _ _12350- -- 3S-19 Palm 1 3S-08 3G-17 3A-08 r----------------I IAIO/Pool Boundary; L----------------- 1 Figure 5: West to East cross section across the A1O area (outlined in dashed red), curves shown here include gamma ray, TVDSS, measured depth (MD), deep resistivity (black curve), and shallow resistivity (gray curve) CPAI Application for Pool Rules March 2016 Page 11 of 26 Figure 6: North to South cross section across the AIO area (outlined in dashed red), curves shown here include gamma ray, TVDSS, measured depth (MD), deep resistivity (black curve), and shallow resistivity (gray curve) North to South Structural Cross Section Gamma Ray Resistivity GAPI TVDSS MD ohmm 0........180 (rt.) (ft.) 1......100 k Unit -5050 .5050 '10350 5050- 8600 - 505D-.: g100 5100 (I Ili 040c, -10450 8650 8150- --- 53 5150 �) j. 530 4 050 10550 51 8700 8760 51 6200 1 mile `'41 .5150 III L' -.5150- 0600. ' ( .5150 - 9000 .5150 8250 -. 5200 �',� ! 10650 1070 8300 8350 <. 5: 0n .6700 - 520 . I 30750- 520 05250 89050 520 8400 6750080 5250 -5250 "10850 5250 5250 8450 5300 I I 109W 10950 upper 9000 9050 8500 - 858 - - - 53 � � ' jI 530 13000. Moraine 530 530 8550- � 5350. �j 1130o- 9300 8600 -- 6900- -5350 I I� -5350.5390 1 _ _ t58 - -5350 Soso- , 8950- 54 5/00 j 510 --112 11250 9200 - 5100- 8700 540 7000 5450 5450 li i; 1 17350- �r -5450 9250 9300 .5450- 8750 8800 7050- Lower - - 550 150 , 55 9400 550 8900 550 7150 5550- l�yr� �MOrainej 2450 0950 -5550 -5550 160 -.5550 9500 .5550 9000.-.5550- 7200 68 5800 _ _ _ « �i; , 560 11650- 580 9550 -500 9050- 560 7250- 5650 170 9600 9700 - 7300 -5650 -5650- 11750 ,�5650- . 9150 - - -5650- 7350- 5700 1100 9700 9200 - 570 570 11850 5700- 9750 - 5700- 9250 570 7100 -5750-5750- 5750 190 HRZ - 5750-" 9800 9300 "'- '1 3750 7450- 5800 31950- 9850 9350 7500- 580 580 120M 580 9900 580 9400 580 7550- 5850- 1205g 9450-- -5850 .5850 - 210 .5850 9950 --5850 9500 .5850 7600-. 5900 f 000 ,. 9550 - 7650 - 590 12150 ( 590 590 5900- 5950 30050 - 9800 - 7700 5950 .5950 1220 .5950 O30 -5950-- 9650- .5950- 7750-- B000 12250- 10150 9700 800 .00D- 230 800 BDOg- g750 6050 - E. Harr. Bay 1 31VI-23 3W-07 3H-22 3G-17 530 11750 - " - - 1180 5350-.11850 1190 20 5450--1205 # 1230 I 550 12150- i 1220 5550 -12250 i i 1230 560 12350- 5650- 240 12450 570 250 32550- SS" 57501260 SSS S 1265D 580 1270 5850-.12750 280 j 5900- 1285 II -1290 5950 12950 2T-23 2T-36 CPAI Application for Pool Rules March 2016 Page 12 of 26 W LU W tu LL LL LL LL }jx Figure 7: Top Upper Moraine with faults, marker is highlighted on Palm I log for reference 604000OFN1, Upper Moraine Depth 504000OF N Surface Structure Map Conoc(;PIhlllips Ainka, Inc. Palm No.1 at *qdoguruk --------- OHMM too TI _-2nnt—mly �Rml_ . . : . . Re.i.My WAd. 50 Pu 4Y 0 V WM ME) OHMM 100 Geerna M 1.65 G/C3 2 6t • O. -802 APPY Ml 6020000F N Top Upper solo f Moraine ORN Structure 5550- . •0 C1 = 20 ft slop-4940 5000 x -5050 -5100 R _!W -5150 Top Upper lVittrainal -Top Morainal 5150- -5200 - Top Pool :5250 5300 Ktipp i�u I -c 'River Unit I 0 -5350 52 -540 0 -5450 5500 00- 00. 6000000F N - OOOOOF N 5550 00 50' :56 5250- J, p :5800 5850 5800 -5850 .51,00 - 900 50()z 0 -5240') -4, - L49—A 5300- 0 sm- 0 71 5350- 598000OF N 5 598WWF Nj- 5400- — 6 C�/- Legend . ........... III Coastline L yao 5450-twoo (1air Unit bO Unit Boundary - Placi Lease Boundary -Saw Lower Morainal , ---------- 5500- Base Pool/ X AIO and Pool Area I __1 Top HRZ 6 ---------- Well Penetration - 0100- W In Upper Moraine 50- j Fault ... .. ................ ...... - Ot • 55 + 5960000F N -.5960000F N at 5.1 ui T__ KRU outline displayed LL here is the 1 1th expansion CPAI Application for Pool Rules* March 2016 Page 13 of 26 3. RESERVOIR Introduction 0 The Moraine Reservoir consists of Lower Cretaceous Brookian slope to basin floor turbidite deposits comprised of thinly laminated, very fine to fine-grained sandstones, siltstones, and mudstones. Similar facies compromise the nearby producing fields, Tam in the Kuparuk River Field and Nanuq in the Colville River Field. This section will summarize reservoir properties. Core data provides the foundation for much of the rock property information presented in this section. Whole cores were collected from Colville 1, Colville Delta 3, Kalubik 1, Kalubik 2, and Moraine 1. Porosity, Permeability and Water Saturation The Moraine Reservoir is very interbedded with core measuring 30-60% sandstone. Porosity values from core data range from 15-28% with an arithmetic mean of 19% in the sandstones and siltstones while air permeability values from core data range from 0.5-93 mD with an arithmetic mean of 5 mD in the sandstone and siltstones. Water saturation estimates for reservoir sandstones and siltstones range from 30-85%. Net Pay Determination A porosity cutoff of 15% and a water saturation cutoff between 50%-75% define net pay. Reservoir Fluids and Pressure, Volume and Temperature ("PVT") Properties Reservoir fluid PVT and oil characterization studies have been completed on fluids gathered from the Moraine 1 well. Moraine Reservoir and fluid properties are (-5,000 foot TVDSS datum): - Initial Reservoir pressure: 2263 psig - Reservoir temperature: 1350 F - GOR: 425 scf/bbi - API gravity: 26.50 - Bubble point pressure: 2134 psig - Oil formation volume factor: 1.2 rb/stho - Oil viscosity: 2.5 cp - Gas formation volume factor: 1.2 bbl/mscf (at saturation pressure) - Oil/Water estimated contact depth: between -5, 190 and -5,275 feet TVDSS Regional Reservoir Description Tool ("RDr) data was used to delineate fluid contacts with the water zone controlled by Ivik 1 and the oil zone contact controlled by the Moraine 1. Original Oil -in -Place ("OOIP'l) The stock tank OOIP volumetric estimates for the Moraine Oil Pool range from 200 to 800 MMSTB for the development planned from the 3S drill site and an additional drill site. The volumetric estimates are based off of core data analyses, which have been used to describe the expected net pay within the pool area, as well as 3D seismic, well control, and production to date. CPAI Application for Pool Rules• • March 2016 Page 14 of 26 4. RESERVOIR DEVELOPMENT Current Development Approach The Moraine Oil Pool will be developed in a phased approach initiated from existing infrastructure. Development of the Pool will be completed in discrete phases to apply knowledge gained from previous phases and improve recovery. The initial targets will be accessed from the 3S drill site and future targets may be accessed via a new drill site to the northeast of 3S, if initial target production is successful with high waterflood recovery. The table below summarizes the potential resource associated with the Moraine Oil Pool development. 100 — 500 MMSTB 100 — 300 MMSTB 10-40 14-28 Horizontal Line Drive Horizontal Line Drive 10-40% 10-40% 10 — 200 MMSTB 10 — 120 MMSTB The Moraine Oil Pool will employ a horizontal well line drive pattern Immiscible Water Alternating Gas ("IWAG") flood, with the option to convert to a Miscible Water Alternating Gas ("MWAG") or rich gas flood, to enhance recovery from the reservoir. Due to the highly laminated nature of the reservoir, all the wells (including the injectors) will likely be hydraulically fracture stimulated to enhance productivity and improve vertical injection sweep. Most wells will trend northwest, along the maximum principal stress direction to improve waterflood performance, and range in length from 3,000 to 8,000 feet within the reservoir. Wells will be arranged end -to -end to form alternating rows of producers and injectors in a line -drive flood pattern. Initial studies suggest a 1,500 ft. inter -well spacing is optimal assuming modest secondary response. The initial well pair (3S-613 and 3S-620) will provide critical performance and injection data for the Moraine Oil Pool which may, in combination with additional geologic and engineering studies, change the number of wells, well spacing, well design, and well placement for the Moraine Oil Pool development. The primary uncertainties in the development of the Moraine Oil Pool are the lateral continuity of thin sand beds, fracture heights, and the effective displaceable pore volumes. However, extended production test results of both 3S-19 and 3S-620 are consistent with laterally continuous productive sands over development well spacing distances of 1,000 to 2,000 ft. As a turbidite system, compartmentalization is possible, but hydraulic fracture stimulation will aid in making contact with individual sandstone beds. CPAI Application for Pool Rulesle 0 March 2016 Page 15 of 26 Hydrocarbon Recovery The quality of the crude requires adoption of a secondary recovery mechanism to obtain an economic production profile. Water injection has been implemented as the main improved recovery process for the Kuparuk River Field, and will also be planned for the Moraine Oil Pool. This waterflood technique has been widely used on the North Slope with consistent success. CPAI estimates that primary recovery will recover approximately 5% of the OOIP and that waterflood recovery will range from 5-25% incremental recovery OOIP, yielding a total recovery after waterflood of 10-30% (Figure 8). Gas injection, whether miscible or immiscible, is expected to yield significant incremental recovery in the Moraine Oil Pool. IWAG incremental recovery is expected to range between 1-5% of OOIP, while MWAG incremental recovery is expected to range from 3-15% of OOIP (Figure 9). Resource recovery for floods is heavily dependent on injection throughput, waterflood recovery efficiency, and gas injection recovery efficiency. Typical Waterflood Recovery Efficiency (Moraine) 0.35 0.3 0.25 0.2 0.15 0.1 0.05 0 1 0 20 Year : . L I . 1 30 40 Typcial Waterflood Recovery Efficiency (Moraine) E 0.35 0.3 C0.25 ------- - 0.2 W 0.15 0.1 0.05 0 31: 0.00 0.50 1.00 1.50 2.00 2.50 3.00 HCPV Water Injected (fraction) Figure 8: Plots showing simulated waterflood recovery in the Moraine Reservoir in terms of time (top) and hydrocarbon pore volumes ("HCPV") of water injected (bottom) CPAI Application for Pool Rules• • March 2016 Page 16 of 26 0.12 � r 0.10 M a 0.08 ------ -- -- ---- — �o w O IWAG a 0.06 c0 25% MGI u A C'U w 0.04 . _,_.__ _� __..______ 50% MGI +fQ' 75% MGI 0 0.02 - __--- -- --- - -.. d v c 0.00 - 0.00 0.50 1.00 1.50 2.00 2.50 3.00 HCPV Total: water+gas (fraction) Figure 9: Plot showing simulated incremental recovery in the Moraine Reservoir due to injecting gas of varying levels of enrichment Due to uncertainty in Natural Gas Liquid ("NGL") supply, there is uncertainty in the exact composition of gas that will be available for injection in the Moraine Reservoir. Therefore, it is not possible at this time to predict with certainty whether or not miscibility between the injected gas and the formation oil will be achieved; however, the fundamental variable that affects the incremental recovery is not dependent on achieving miscibility, but rather on the cumulative C4+ injected (Figure 10). Incremental Recovery vs. Enriching Fluid Injected 0.12 E 0.1 d >r a a 0.08 s 1C 0.06 Y iS C 0.04 C v V2 0.02 C 04-- 1.00E+13 5.10E+14 1.01E+15 Cumulative Rich Gas C4+ Injected (moles) Figure 10: Plot showing incremental recovery in the Moraine Reservoir vs cumulative rich gas injected CPAI Application for Pool Rulesle March 2016 Page 17 of 26 Recovery Process Selection To evaluate the performance of the Moraine Reservoir, a 3-D compositional model was constructed covering the entire Moraine Oil Pool. Lean gas injection, miscible gas injection and waterflood development scenarios were evaluated with this model. Waterflooding was the recovery method selected. Additionally, waterflooding may be followed later with either lean gas or miscible gas injection to further improve recovery. The uncertainties in the waterflood case can be simplified into two groups. The first being the question of interconnectivity of the reservoir at the proposed development scale of 1,500 ft. well spacing. The highly interbedded nature of the Moraine Oil Pool could result in poor inter -well communication at that distance. Simulation modelling using existing core data and geologic descriptions has predicted that communication will occur. The first well pair (3S-613 and 3S-620) will be used to test the inter -well reservoir the communication and throughput rates. The second uncertainty is the elevated water saturation of the Moraine Reservoir. High initial water saturation can result in poor performance of water floods due to water cycling. Injected water tends to go to areas that have higher water saturation making it difficult for the flood to expand to less mature areas. This process is reflected in the simulation modelling results. In addition to generating incremental oil recovery by mobilizing residual oil, implementation of an IWAG or MWAG will mitigate effects associated with water cycling should they occur. Future Optimization Optimizing field development will be an ongoing process requiring additional data, laboratory studies, and reservoir modeling. The effective length and skin of the model wells is being tuned based on well test data. Simulation studies to determine the incremental recovery from MWAG are also underway. Producing Gas -Oil Ratio ("GOR") Expectations CPAI requests that the requirements described in 20 AAC 25.240 be waived for the proposed Moraine Oil Pool since the Pool plans are to implement enhanced recovery techniques. Since gas will be injected into the Moraine Oil Pool during the life of the Pool, the GOR is expected to rise above solution GOR in some wells. The breakthrough of re -injected gas will cause GORs of some producing wells to exceed limits set forth in 20 AAC 25.240. Additionally, the Moraine Oil Pool average reservoir pressure will be maintained above the bubble point pressure with water injection for pressure maintenance. Well Conversion Strategy The Moraine Oil Pool development will target a 1.0 voidage replacement ratio. The injector/producer ratio will be dictated by the voidage replacement performance. Dependent on facility constraints, pre- production of injection wells may occur. After the pre -production period, these wells will be converted to injection, unless service conversion is determined beneficial for ultimate recovery or necessary to meet the voidage replacement ratio target. CPAI Application for Pool Rulesle March 2016 Page 18 of 26 5. DRILLING DrillingMell Design 0 The Moraine Oil Pool will be accessed from wells drilled from gravel pads utilizing drilling procedures, well designs, and casing and cementing programs consistent with current practices in other North Slope fields. Figure 11 on the following page illustrates a generic Moraine producer well schematic, which will also be similar to the planned injectors. For proper anchorage and to divert an uncontrolled flow, conductor casing will either be driven or drilled and cemented at least 75 feet below the pad. Cement returns to surface will be verified by visual inspection. Surface holes will be drilled and set below the West Sak Reservoir for proper anchorage, prevention of uncontrolled flow, and protection from permafrost thaw and freeze back. This casing setting depth provides sufficient depth for kick tolerance, yet shallow enough to initiate build sections for high departure wells. Within the planned development area, the base of permafrost is interpreted to be between -500 ft. and -1,700 ft. TVDSS. Surface casing strings will be cemented in accordance with 20 AAC 25.030(d)(4). No hydrocarbon bearing intervals have been encountered to this depth in previous wells. The blowout prevention equipment ("BOPE") will be installed and tested in accordance with 20 AAC 25.035 requirements. A Formation Integrity Test ("FIT") will be performed in accordance with 20 AAC 25.030(f). Intermediate sections will be drilled utilizing the latest directional techniques from surface casing, encountering the top of the Moraine at 0-70 degree inclination. Casing will be set and cemented with the shoe just above, or just into, the Moraine Reservoir. The section between the proposed surface casing shoe and the top of the Moraine Reservoir consists primarily of mudstones, and siltstones with very few major sandstones. Top of cement will extend a minimum of 500 feet measured depth above the known hydrocarbon bearing formations in accordance with 20 AAC 25.030(d)(5). After drilling out the intermediate casing, and prior to drilling ahead into the reservoir, an FIT will be performed in accordance with 20 AAC 25.030(f). Based on current knowledge of reservoir characteristics, CPAI expects to develop the Moraine Oil Pool using horizontal wells with solid liners including pre -perforated pups and /or sfiding sleeves and external swell packers to facilitate staged hydraulic fracture stimulation treatments. Both injection and production wells will likely be completed with 4-1/2 inch tubing to facilitate hydraulic stimulation. All tubular sizes are subject to change. Uncemented slotted liners are included in the drilling plans on an "as -needed" basis. For example, wellbores that encounter significant shale or lost circulation intervals may receive slotted liners with external casing packers ("ECIP"). At some point in the future coil tubing workovers may place slotted or cemented liners within the Moraine Reservoir. In addition to horizontal wells with solid liners including pre -perforated pups and /or sliding sleeves and external swell packers to facilitate staged hydraulic fracture stimulation treatments, it is proposed that Pool Rules authorize the following alternative completion methods: a) Open -hole liner or casing and perforated completions with the option of hydraulic fracture stimulation treatments. b) Cemented liner or casing and perforated completions with the option of hydraulic fracture stimulation treatments. c) Slotted liners, wire -wrapped screen liners, or combinations thereof, landed inside of cased hole and which may then be gravel packed. CPAI Application for Pool Rules* • March 2016 Page 19 of 26 d) Vertical or "conventional" open -hole completions. Open -hole completions may subsequently be completed with slotted or perforated liners, wire -wrapped screen liners, or combinations thereof, and may be gravel packed. e) Horizontal or "high angle" completions with liners, slotted or perforated liners, wire -wrapped screens, or combination thereof, landed inside the horizontal extension, and which may be cemented and perforated or gravel packed. f) Multi -lateral type completions in which more than one wellbore penetration is completed in a single well, with production gathered and routed back to a central wellbore. 4-12" Tubing Hanger I Tree 16" Conductor to - 110' 4!1-." Tubing Nipple 10-1W Surface Casing cemented to surface 4-%- Tubing Planned TOC 500' above hydrocarbon bearing zone 4-X" Tubing Nipple 7541" Liner Hanger I Packer 4=f2" Tubing Nipple J► Frac Sleeves Swell Packers (Drop Ball System) VV' Hole TD I -- -`- 4 %" Liner -- -- -- �- - 3000MM ft HA Section Pre�erf Pups 4-%' orange Peel Shoe Figure 11 — Proposed Moraine Producer Well Schematic CPAI Application for Pool Rules March 2016 Page 20 of 26 Other casing and completion methods may be approved by the Commission by administrative approval upon request by CPAI supported by data demonstrating that such alternatives are based on sound engineering principles. Drilling Fluids The drilling fluid program designed for wells within the Moraine Oil Pool will be prepared and implemented in accordance with 20 AAC 25.033. Formation pressures for the strata to be penetrated will be estimated and documented based on the current wells targeting the Moraine Reservoir as well as on the KRU wells which have already penetrated the Moraine Oil Pool. Blowout Prevention General well control for drilling and completion operations will be performed in accordancewith 20 AAC 25.035. Directional Drilling CPAI requests that the requirements descdbed in 20 AAC 25.050(b) be waived for the proposed Moraine Oil Pool to relieve administrative burden. In lieu of the requirements under 20 AAC 25.050(b), CPAI proposes that permit(s) to drill shall include: 1) plan view 2) vertical section 3) close approach data 4) directional data Well Spacing CPAI requests that the requirements described in 20 AAC 25.055 be waived for the proposed Moraine Oil Pool because the horizontal well development of the proposed Moraine Oil Pool, via line -drive flood pattern, will yield greater recovery than a conventional vertical/slant well development plan with a minimum spacing rule. In lieu of the requirements under 20 AAC 25.055, CPAI proposes without prior approval, development wells may not be completed any closer than 500 feet to an external boundary where working interest ownership changes. Logging Operations Since facies interpretation will be the most critical data requirement, the log suite planned in the Moraine Reservoir includes resistivity and gamma ray logs across the productive intervals. If log identification of formation facies is not possible, rate of penetration ("ROP") and cuttings will become the critical reservoir quality determinants. At some point in the future, it is possible that Moraine wells could be drilled solely using ROP as well as other drilling indicators to locate the pay zones. CPAI requests that the requirements descHbed in 20 AAC 25.071 (a) be waived for the proposed Moraine Oil Pool since these requirements will not significantly add to the geologic knowledge of the area in light of the information that is available from other wells in the area. In lieu of the requirements under 20 AAC 25.071 (a), CPAI proposes that only one well per drill site is required to be logged for the portion of the well below the conductor pipe by either a complete electrical log or a complete radio -activity log unless the commission specifies which type of log is to be run. As the first Moraine Reservoir targeted well on drill site 3S, 3S-620 was successfully investigated with a suite of gamma ray/resistivity/ neutron/density logs. Additional log investigation of formations from the 3S drill site of the Moraine Oil Pool will be performed at CPAI's discretion. CPAI Application for Pool Rules* March 2016 Page 21 of 26 6. WELL OPERATIONS Well Design and Completions Typical completions, for both injection and production wells, will likely be completed with 4-1/2 inch tubing to facilitate hydraulic stimulation and to exploit the production potential of horizontal wells. Based on the well performance, tubing size is subject to change. Producing wells will likely be equipped with gas lift mandrels. When needed, a single packer will provide pressure isolation for the tubing -casing annulus. Wells with liners placed in the horizontal segments may utilize combination liner hanger/packers. In this case, the tubing string will utilize sliding seals which seal into a polished bore in the liner hanger/packer. All completions will target reserves in the Moraine Oil Pool. Wellbore departure will reach laterally as far as 20,000 feet from the current drill site location at 3S. Dependent on the location of any additional drill sites and technologies available, high departure and extended horizontal completions may push measured depths even farther. Artificial Lift The current development utilizes gas lift as the artificial lift mechanism to produce from the Moraine Oil Pool; however, CPAI may employ several different techniques (jet pump, electrical submersible pumps, etc.) to optimize reservoir pressure drawdown, provide lift for long reach horizontal wells, and enhance production rates at the increased water cuts, which are anticipated following waterflood response. Sidetracks In the event early waterflood breakthrough is encountered due to thief intervals, the initial complebons may be plugged back and sidetracked to improve sweep and enhance recovery. Sidetracks may also become necessary if the parent wellbore does not produce/inject as expected or no longer supplies required integrity. In addition to pattern conformance, sidetracks could increase water injection, sidestep faulting or penetrate bypassed oil. Sidetracking scenarios can be expected to target maturing reservoir sections for increased injectivity, reach undrained or isolated pockets, and improve enhanced recovery techniques. As such, sidetracks can be expected to radiate out laterally from the parent wellbore. This further supports the request for a waiver of regulation 20 AAC 25.055. Reservoir Surveillance The initial reservoir pressure of the Moraine Oil Pool, as required by 20 AAC 25.270(a), was measured in the 3S-620 horizontal well. CPAI requests that the Commission approves the proposed reservoir pressure monitoring plan: - Static bottom -hole pressure surveys will be conducted in all new injection wells prior to initiating injection. - Static surveys will be performed on production wells at the discretion of CPAI. - For annual pressure surveillance, a minimum of one (1) pressure survey will be conducted annually in the Moraine Oil Pool, concentrating on injection wells. - Since lengthy horizontal wells require extended shut-in periods, often months long, to achieve stabilized bottom -hole pressures, the alternative pressure survey methods below can be implemented: o open -hole wireline formation fluid pressure measurements, o cased hole pressure buildups with bottom -hole pressure measurement, o injector surface pressure fall -off, o static pressure surveys following extended shut-in periods, or CPAI Application for Pool Rules March 2016 Page 22 of 26 o bottom -hole pressures calculated from wellhead pressure and fluid levels in the tubing of a stabilized shut-in injector All pressure surveys will be reported annually, rather than monthly, to reduce paperwork due to the limited number of surveys. While the pool extends between approximately -4,940 ft. TVDSS and -6,190 ft. TVDSS, a representative common datum for reporting should be -5,000 ft. TVDSS. The -5,000 TVDSS datum will be representative of the targeted depth since the oit/water estimated contact depth is between -5, 190 and -5,275 ft. TVDSS. Well Work Operations Well work operations in the Moraine Oil Pool will include routine mechanical integrity tests of each wellbore and artificial lift maintenance. Operations will also include remedial management of scale, asphaltenes, etc. with slickline or hot diesel treatments. Unlike more typical muffi-zone or multi -layer fields on the North Slope, the Moraine Oil Pool represents a single hydrocarbon accumulation. Production from a single pool minimizes profile modifications. For ongoing well work CPAI requests a waiver to the requirements of 20 AAC 25.280(a) for the following operations on producing wells and enhanced recovery wells a) perforate or re -perforate casing, b) stimulate, c) and coil tubing operations with the exception of drilling or sidetracks. This is intended to reduce the paperwork burden on both the Commission and the CPAL Summary reports and records will continue to be kept in accordance with 20 AAC 25.280(c,d). Stimulation Methods Stimulation techniques may be used at some point to enhance productivity of the Moraine Reservoir. Stimulation to remove drilling induced formation damage and enhance near wellbore flow characteristics may be performed to increase the commercial flow rates in this reservoir. Additional hydraulic fracture stimulation (in addition to initial hydraulic fracturing during completion) may also be performed to increase the commercial flow rates of the Moraine Reservoir. Wellbore trajectories, cementing programs, and tubulars will be designed to accommodate hydraulic fracture stimulation techniques. Hydraulic stimulation operations will also be performed in accordance with 20 AAC 25.283. Surface Safety Valves Wells will be equipped with appropriate well safety valve systems in accordance with 20 AAC 25-265. Periodic inspections and testing, not to exceed semi-annually, will be conducted following notification of the Commission. CPAI Application for Pool Rules* March 2016 Page 23 of 26 7. FACILITIES Introduction and Scope The Moraine Oil Pool will be initially developed from the existing KRU drill site 3S which is connected to the KRU CPF-3. Upon successful development of the proposed pool from the drill site 3S, additional development may occur from one or more new drill sites which will be connected to the established Kuparuk infrastructure. The 3S onshore gravel drill site was selected for the initial development due to the ability to adequately target the Moraine Oil Pool from that surface location and also due to the ability to use infrastructure already established to CPF-3, which is —11 miles away from the 3S drill site via gravel road. Economic development of the Moraine Oil Pool is contingent upon utilization of these facilities. Injection water will consist of produced water, with the future potential of injecting seawater. Injection gas will be sourced from KRU processing facilities. Although the future availability of gas for injection purposes cannot be predicted, some form of IWAG/MWAG will occur on one or more injection patterns. Drill Site Facilities The design premise of the 3S drill site requires minimal operator presence for daily operations. All data gathering and routine operations are accomplished remotely from CPF-3 or from the 3S control room. The below list includes the facility components located at the 3S drill site: - Production, test, water injection, and gas injection lateral piping and headers - Test separator for well testing - Instrumentation, control, and communication equipment The 3S drill site is designed to accommodate 26 wells on 20-foot centers equally split between producers and injectors. Currently 17 of the slot designations are used for Kuparuk Reservoir production or injection. The individual well lines comingle into common headers that feed into cross-country pipelines for transport to CPF-3. Each production well connects to the drill site test header which flows through the test separator module on the pad. This test separator provides two-phase separation and measures flow rates of the gas and liquid phases. The liquid stream passes through a phase dynamics meter to determine the oiltwater split of the liquid. Testing can take place remotely through a divert valve system, which redirects the flow from the production header to the test separator. The 3S drill site also has water and gas injection headers bringing high pressure fluids from the plant to the drill site for injection. Each injection well will be piped to receive water and/or gas depending on the reservoir development plan. Cross-country pipelines include a 16 inch common line from 3S which also connects the 3G, 3F and 3B drill sites to the CPF-3 processing plant. An 8 inch water injection line runs from 3S to 3G, and an 8 inch gas injection line runs from 3S to 3F. Central Processing Facility CPF-3 takes the well production from CPAI operated drill sites and Caleus'Oooguruk offshore island and separates fluids into wet oil, gas, and water streams. Wet oil is sent to CPF-1 and CPF-2 through pipelines for further processing to reach sales quality. Gas is dehydrated and compressed for artificial lift and fuel gas to support the facility. Produced water pressure is boosted and used for reinjection. The separation train consists of a single primary separator. This vessel removes gas and some water from the oil. This section of the plant contains pumps for transferring oil from CPF-3 to CPF-1 and CPF-2. Oil is metered for balancing flow to the CPF-1 and CPF-2 for optimal field wide processing of oil. Gas separated from oil in the separation train is processed and compressed primarily for artificial lift. There is one gas compression system at CPF-3 consisting of two GE Frame 3 driven units. The lift gas CPAI Application for Pool Rules 0 March 2016 Page 24 of 26 compressors are gas turbine engine driven centrifugal compressors with two stages. The first stage compressor boosts the gas in the plant up to -500 psig for fuel gas usage. The second stage boosts the gas to -1400 psig where it is used for lift gas throughout the CPF-3 drill sites. CPF-3 drill sites receive injection gas from CPF-1 and CPF-2, but CPF-3 does not generate any of its own injection gas. Produced water will be separated from the oil stream and reinjected into the reservoir for pressure maintenance and waterflood support. Additionally, CPF-3 also has two seawater injection pumps for injecting seawater into the reservoir for pressure maintenance and waterflood. CPF-3 contains the utility systems required to operate a North Slope oil field. Electricity is generated using a General Electric Frame 5 gas turbine as the primary generator. The Frame 5 can generate 23-27 MW depending on the ambient temperatures. Additionally, there is a single permanent Ruston gas turbine generator (-3.2MW generation capacity) and a portable emergency diesel generator. CPF-3 is tied into the Kuparuk Power Grid, with redundant tie -lines, and is typically an exporter of power. Other utility systems include instrument air, nitrogen, plant air, cooling glycol, and heating glycol. Production Allocation Production will be measured with equipment in accordance with 20 AAC 25.228. Production will be allocated to producing wells based on the actual plant oil sales volume and well tests on individual producing wells. The well tests will be used to create performance curves to determine the daily theoretical production from each well. The CPF-3 allocation factor will be applied to adjust total production from the associated drill sites. All the wells are connected to a test header system, which go to a test separator on the 3S pad. In the future, a multiphase flow meter (MPFM) may be installed to measure production from each well. CPAI requests that the requirements described in 20 AAC 25.230(a) be waived for the proposed Moraine Oil Pool due to the feasibility challenges of accurately measuring well rates of all producers monthly for the multi -well drill sites planned for the Moraine Oil Pool. In lieu of the requirements under 20 AAC 25.030(a), CPAI proposes that each producing well will be tested at least monthly for the first 12 months, and then at least every three months thereafter. Since the most rapid change in well performance is expected during the first year, and monthly tests during that time will identify significant production declines. A separate partieipating area is planned for the Moraine Oil Pool. The Moraine project area is also subject to the Kuparuk River Unit Operating Agreement. Royalty interests will be determined at intervals described in the agreement. The control system for the Moraine Pool wells will continuously gather operating data from the wells and the test separators. To accurately allocate the production the following actions will be followed: 1 ) All wells will be periodically tested. 2) The stabilization and test duration of each test will be optimized by CPAI to obtain a representative test. 3) Well and field operating condition information required for the construction of a field production history will be maintained. 4) Major test separator meters and major gas system meters will be installed and maintained according to industry recommended practices or standards. 5) CPAI will maintain records that permit verification of the satisfactory execution of the approved production allocafion methodologies. CPAI Applicabon for Pool Rule* March 2016 Page 25 of 26 8. PROPOSED MORAINE OIL POOL RULES The rules set forth apply to the following area referred to in this order: Umiat Meridian T1 1 N, RIBE Sections 1-12 all T12N, R7E Sections 1-2 all, T12N, RIBE Sections 1-36 all T13N, RIBE Sections 1-3 all, T1 3N, RgE Section 6 Rule 1. Field and Pool Name 11-14 all, 23-26 all, 35-36 all 10-15 all, 19-36 all The field is the Kuparuk River Field, and the pool is the Moraine Oil Pool. Rule 2. Pool Definition The Moraine Oil Pool is defined as the accumulation of oil and gas common to and correlating with the interval within the Palm No.1 well between the depths of 5,630 ft. MD and 6,043 ft. MD (-5,144 ft. and - 5,486 ft. TVDSS respectively). Rule 3. Gas -Oil Ratio E"mption Wells producing from the Moraine Oil Pool are exempt from the gas -oil ratio (GOR) limit set forth in 20 AAC 25.240. Rule 4. Drilling and Completion Practices a) Alternate casing and completion programs, in addition to those specified in the regulations, may be administratively approved by the Commission upon application and presentation of data which demonstrate the alternatives are appropriate, based upon sound engineering principles. b) In lieu of the requirements under 20 AAC 25.050(b), CPA[ proposes that permit(s) to drill shall include: plan view, vertical section, close approach data, and directional data. c) In lieu of the requirements under 20 AAC 25.071 (a), CPAI proposes that only one well per drill site is required to be logged for the portion of the well below the conductor pipe by either a complete electrical log or a complete radio -activity log unless the commission specifies which type of log is to be run. Rule 5. Well Spacing a) The requirements of 20 AAC 25.055 are waived for development wells in the Moraine Oil Pool. b) Without prior approval, development wells may not be completed any closer than 500 feet to an external boundary where working interest ownership changes. Rule 6. Reservoir Surveillance a) Static bottom -hole pressure surveys will be conducted in all new injection wells prior to initiating injection. b) Static surveys will be performed on production wells at the discretion of CPAI. c) For annual pressure surveillance, a minimum of one (1) pressure survey will be conducted annually in the Moraine Oil Pool, concentrating on injection wells. d) In lieu of stabilized bottom -hole pressure measurements, the alternative pressure survey methods below can be implemented: a. open -hole wireline formation fluid pressure measurements, b. cased hole pressure buildups with bottom -hole pressure measurement, c. injector surface pressure fall -off, CPAI Application for Pool Rulesle March 2016 Page 26 of 26 d. static pressure surveys following extended shut-in periods, or e. bottom -hole pressures calculated from wellhead pressure and fluid levels in the tubing of a stabilized shut-in injector e) All pressure surveys will be reported annually, rather than monthly, to reduce paperwork due to the limited number of surveys. Rule 7. Wellwork Operations The following operations in production and enhanced recovery wells within the Moraine Oil Pool may be conducted without filing an application pursuant to 20 AAC 25.280(a): - perforate or re -perforate casing - stimulate - coil tubing operations with the exception of drilling or sidetracks Rule 8. Production Practices In lieu of the requirements under 20 AAC 25.030(a), CPAI proposes that each producing well will be tested at least monthly for the first 12 months, and then at least every three months thereafter. Rule 9. Administrative Action Upon proper application, the Commission may administratively waive the requirements of any rule stated above or administratively amend the order as long as the change does not promote waste, jeopardize correlative rights, and is based on sound engineering principles. IV Conoaftillips TRANSMITTAL CONFIDENTIAL DATA FROM: Kazeem Adegbola, GKA Engineering TO: ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage AK 99510-0360 RE: Moraine AIO and Pool Rules Application DATE: 03/31/2016 paruk River Unit, Alaska RECOVED MAR 3 1 2016 A-,,OGCC Cathy Foerster, Commissioner AOGCC 333 W. 71h Ave, Suite 100 Anchorage, AJaska 99501-3539 Moraine AIO and Pool Rules Application, ConocoPhillips Alaska; Greater Kuparuk Area Engineering scan and return ekx1ronlically to 5andra.Q.Lemke(WC0P.com CC: Kasper Kowalewski, GKA Engineering COPA IT-TDM Transmittal tracker Receipt: Date: 61S-Technical0ata Management I C&nocoPhdlips I Anchorage, Alaska I Ph, 907.265.6947 46 1 1 0 d3� xO ,,,,\e!� cp 0 Complete items 1. 2, and 3. Also complete Item 4 If Restricted Delivery Is desired. 0 Print, your name and address on the reverse so that we can return the card to you. 11 Attach this card to the back of the mallpleos, or on the front If space permits. I . Article Addressed to. -Rob Kinnear BP Exploration Alaskai'lot. 900 E. Benson Boul� Anchorage, AK 9950'8 A. Signature B. Received 0 Agent 0. Date Of D. Is delivery address dftent froffi Item 1 ? U Yet If YES, enter delivery address below: 13 No S. Senrke Type KlOertlfiecl Malls 0 Priority Mail ExpreW 13 Registered 13 Return Recelpt for Merchandl, 0 Insured Mail 13 Collect on Delivery 4. Restricted Delivery? Pft Fee) 13 Yes 2. Article Number mrawar fmm service kW 7014 0150 0000 6333 7422 PS Form 3811. July 2013 Domestic Return Receipt • Complete items 1, 2, and 3. AJSO complete Item 4 if Restricted Delivery Is desired. SNnatu 0 Agent X • Print your name and address on the reverse E3 Address, so that we can return the card to you. • Attach this card to the back of the mallplece, or on the front if space permits. - JR, rijnw td by . , M a loci C aterf D Nve — D. Is(4ellvery address different from Rom 1� if VIES, enter delivery address below: 13 —Ys 13 No 1. Article Addressed to: G..C. Fredrick Chevron U.S.A. Inc. Oln V C+ + C ; AnC I CC , U LC S. Service Type Anchorage, AK 99501 GerNed Malls 13 Wority Mail ExprasC 13-Registered 0 Return Receipt for Merchandh 0 Insured Mall 13 Collect on Delivery 4. Restricted Dellvery?. Pft Fee) 0 Yes 2. Article Number (11anskr from service ftW 7014 0150 0000 6333 7439 Ps Form 3811, July 2013 Domestic Return Receipt • Complete items 1, 2, and 3. Aiso complete Item 4 if Restricted Delivery Is desired. • Print your name and address on the reverse so that we can return the card to you. • Attach this card to the back of the mallpleoe or on the front if space permits. 1. Article Addressed to: Gilbert Wong ExxonMobil Alaska Prod uc%icN44-,n C. 3301 C Street, Suite 400 Anchorage, AK 99519 A. s 1 rr, X by JP~ Iftne) Agent Addrasi D. Is delivery ad*"[Y)fdfmqQY--dm'-,&r& 1 ? 0 Yes If YES, enter ad*s belevh,��, 13 No 77, 'P -Yz 3. service lype te cerfi.fied mar E3 Priority mail Bpess- 13 Reglt;tered stum Receipt for Merchandla —E3 Insured Mail -103 collect on Delivery 4. Restricted Delkery? Pft Fee) ' 13 Yes 2. Article Numbw (riansfer fmm service law 7014 0150 0000 6333 7415 PS Form 3811, July 2013 Domestic Return Receipt • Complete Items 1, 2, and 3. AJso complete Item 4 if Restricted Delivery Is desired. • Print your name and address on the reverse so that we can return the card to you. • Attach this card to the back of the mallpiece, or on the front If space pennits. 1. Article Addressed to: State of Alaska Department of Natural Resources 550 West 7th Avenue, Suite 1100 Anchorage, AK 99501 sjgwure x Moe a, 13, R t :a 15 Dle of C D. Is delivery address diflarent from Iteni 1? 00 Y— If YES, enter delivery address below: tZ No 3. Samoa Tips XLCerfiftd MaI10 13 Priority Mail Express- E3 Registered E3 Return Receipt for Merchandli —0 Insured Mak E3 Collect on Delivery 4. Restricted DeUvwfl (Extm Fee) E3 Yes 2. Afficle Number (riansfer from serWcs labeo 7014 0150 00(10 6333 7392 Ps Form 3811, July 2013 Domestic RetLvn Receipt • Ccimplete Items 1. 2, and 3. 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Article Addressed to: Caelus Natural Resources Alaska, LLC 3700 Ce-riterpoint Dr. Ste. 500 Anchorage, AK 99503 A. Signatu 11 Agerit 0 Address B. Receiv !k�lrrfed Name) C. Date of Dative re '0�� 21��rly . __N <_ D. Is de r," ,�rdferentfrornfteml? OYes 1f. a �,-Address below: E3 No CC 3. 8 -13 Priority mail Exprese E3 Registered 0 Return Receipt for MetcharidLe 0 Insured Me# 13 Collect on Delivery 4. Restricted Deliver Pft Fee) M Yes 2. AActe Number (rMisier ftm service kw 7014 0150 0000 6333 7613 PS Form 3811. July 2013 Domestic Retum Receipt 9: Complete Items 1. 2, and 3. Also complete A. Si t X ra u item 4 If Restricted Delivery Is desired. a-A4-t 8 Print your name and address on the reverse r3 Address, I so that we can return the card to you' - . B. Received by (Pdnfed Nam) c". Datej6f ei E Attach this card to the back of the mallpleoe, or on the front If space permits. 1 XAA 17 1. Article Addressed to: D. 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Service Type CwWW Malle 0 Priority Mail Bpwr Registered Ofleturn Receipt 1br Merchandii E3 Insured Mail E3 Collect on Delivery 4. Restricted Delivery? Pft fee) 13 Yes P- Article Number 7014 0150 0000 6333 7606 (Tmwmr from saffte bw Ps Form 3811, July 2013 Domestic Return Receipt 0 Complete Items 1, 2, and 3. Also complete Item 4 if Restricted Delivery Is desired. R Print your name and address on the reverse so that we can return the card to you. 0 Attach this card to the back of the mallplece, or on the front If space permits. 1. Article Addressed to: Brooks Range Petroleum Corporation 510 L Street, Suite 601 Anchorage, AK 99501 A. Sl natu El Addressi ":,e" by'fthled Name) C. Palo of Pelive Kerc, i� 1q/ I///, D. Is delivery address different trom itern 1 ? U Yei If YES, enter delivery address below: 13 No E ce ype Malis 13 Priortty mail Bprew R,oistelld E3 Return Receipt for Merchandit 0 Insured Mail 0 Collect on Delivery 4. Restricted Delivery? Pft Fee) E3 Yes 2. Article Number 7014 0150 0000 6333 7378 Ps Form 381 1,quly 2013 Domestic Return Receipt