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Home My WebLink AboutAIO 039AREA INJECTION ORDER 39 Kuparuk River Field, Moraine Oil Pool 1. March 31, 2016 ConocoPhillips Alaska, Inc.'s request for Area Injection Order for Moriane Oil Pool 2. April 26, 2016 Notice of Public Hearing, Affidavit of Publication, bulk mail list, email distribution list 3. May 10, 2016 Transcript, Presentation and Sign in sheet 4. May 24, 2016 CPA Additional Information 5. August 10, 2016 Background information on a request for reconsideration of AIO 39 and CO 725. (no order issued in this AIO). See CO 725 AREA INJECTION ORDER 39 ORDERS • 0 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue Anchorage Alaska 99501 Re: THE APPLICATION OF ConocoPhillips ) Docket Number: AIO-16-011 Alaska, Inc. for an order authorizing ) Area Injection Order No. 39 underground injection of fluids for enhanced ) Kuparuk River Unit recovery in the proposed Moraine Oil Pool ) Kuparuk River Field within the Kuparuk River Field, Kuparuk River ) Kuparuk River -Torok Oil Pool Unit ) North Slope Borough, Alaska July 22, 2016 IT APPEARING THAT: 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, requested authorization for the injection of fluids for enhanced recovery in the proposed Moraine Oil 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. 3. 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. 5. The record was held open until May 24, 2016, to allow CPAI to respond to requests made during the hearing. FINDINGS: 1. Pool Definition: Conservation Order No. 725 defines the Kuparuk River -Torok Oil Pool (KRTOP) and establishes pool rules that govern development operations and production.' 1 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) in Conservation Order No. 725, the AOGCC applied the name Kuparuk River -Torok Oil Pool to this pool in lieu of CPAI's proposed name "Moraine Oil Pool". AIO 39 July 22, 2016 Page 2 of 13 a et{ % '. Odoguruk Unit30 f f�COLY k,A, 6020000c Fl li � OOdi.0 f 1r' .axoaax r. pµk- Y+SORX,F COLmw� ' N9a000aF N- + Kuparu River nit 3� a 3$ r 3A Legend 3G Una Bourn Strry Lease Boundary _ Leases -"'n Alfl and N Pool aiea hul rnn4de KRU _._..,_..___... .. A10 nrel PoN Area ---------------- r 2T DnN Sae Pads 2X RY .o.Mrr ;Zvi r�.,�:v.. 2A� 2Cy�j,h:l- 4 ...._ . Figure 1. Kuparuk River -Torok Oil Pool Affected Areal 2. Owners and Landowners: The State of Alaska is landowner for the planned Affected Area. (See Figure 1). Working interest owners 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 lease ADL 392374 is in alignment with the ownership and working interest percentage for those KRU oil and gas leases within the pool boundary. 2 This map is presented for illustration purposes only. It has been modified from an original map submitted by CPAI in support of the Area Injection Order application. For a more precise depiction of the Affected Area, refer to the legal description presented on page 10 of this order. AIO 39 • July 22, 2016 Page 3 of 13 The royalty interest for ADL 392374 is 16.66667 percent. Royalty interest for the KRU oil and gas leases within the pool ranges from 12.5 to 16.667 percent. 3. Operator: CPAI is the operator of the leases in the proposed Affected Area, which is defined below. 4. Surface Owners: The State, several native allotments overseen by the Bureau of Indian Affairs, and the North Slope Borough are the surface owners within one -quarter mile of the proposed Affected Area. 5. Adjacent Operators: Eni Petroleum US LLC, 70&148, LLC, Caelus Natural Resources Alaska, LLC, ASRC Exploration LLC, and Brooks Range Petroleum Corporation are the operators within one -quarter mile of the proposed effective area. 6. Notification of Surface Owners and Operators: In accordance with 20 AAC 25.402(c)(3), CPAI provided an affidavit with the application showing that copies of the Area Injection Order (AIO) application were sent by certified mail to the surface owners and operators identified in Findings 2, 4 and 5 on March 31, 2016. CPAI provided proof of certified mailing to the AOGCC. 7. Affected Area Proposed for Enhanced Oil Recovery: CPAI requests authorization to inject fluids for the purposes of enhanced recovery operation on lands in the Kuparuk River Unit. The proposed injection area includes portions of Township (T) 11 North, Range (R) 8 East; T12 North, R 7 East; T 12 North, R 8 East; and T 13 North, R 8 East, Umiat Meridian. (See Figure 1). 8. Interval Proposed for Enhanced Oil Recovery: Enhanced recovery injection is proposed within the Kuparuk River -Torok Oil Pool, which is defined in Conservation Order No. 725 as the interval that correlates to 4,991 to 5,272 feet measured depth (MD) on the resistivity log recorded in the Kalubik No. 1 exploration well. (See Figure 2.) 9. Description of Operations: The KRTOP will be developed initially from the existing onshore 3S Drill Site with four to five hydraulically fractured horizontal producers and three to four fracture stimulated horizontal injectors. Wells will be completed with 3,000 to 8,000 foot horizontal sections within the KRTOP. Upon successful development of the initial drilling program from 3S Drill Site, additional wells may be drilled from 3S Drill Site. One to two additional drill sites may be constructed for further development. Wells will trend northwest and will be arranged in a line drive pattern. Water injection with possible future injection of lean (IWAG) or miscible gas (MWAG) will enhance recovery from the KRTOP. Injection operations will be managed to maintain reservoir pressure near the original reservoir pressure. 10. Geology: a. Stratigraphy: The KRTOP consists of lower Cretaceous -aged, Brookian, slope -to -basin turbidite deposits comprising thinly laminated mudstones, siltstones and very fine to fine- grained sandstones. Within the proposed development area, the reservoir interval ranges from 140 to more than 200 feet in thickness. Regionally, this reservoir interval AlO 39 • • July 22, 2016 Page 4 of 13 thins towards the southeast and southwest, and it pinches out to the west against the paleo-shelf. The sandstone and siltstone beds are interpreted to be locally continuous, s Porosdy GR <MD ResD(RILD) RHOS 10 API 240 2 OHMM 200 65 GM1CC 2 65, and - SiN - Shak 1V(JSS> ResM(RILhA) ow Pot 2 OHMM 200 SP TVC) ResS(RFOC) tdPOR 100 MV 100 .2 OHM 200 0 01 <M D DTCP(DT) 70 USff T 701 4$00 asoo zi- Kuparuk River - Torok Oil Pool Correlation Depth ResI -4800 4900 Figure 2. Kalubik No. 1—Type Well Log for the Kuparuk River -Torok Oil Poof 3 Figure 2 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. AIO 39 • • July 22, 2016 Page 5 of 13 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 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. Within the Affected Area, the top of the KRTOP lies between -4,940 and -5,880 feet true vertical depth below mean sea level (also termed true vertical depth subsea and represented herein by the acronym TVDss).4 c. Trap Configuration and Seals: Well log and seismic information indicate that the KRTOP 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 overlying and underlying the reservoir provide the top and bottom seals. An additional confining zone would be provided by the underlying HRZ Shale. 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. 4 To avoid confusion, when depths presented represent true vertical depth subsea, the footage will be preceded by a negative sign and followed by the acronym TVDss (e.g., 4,940 feet true vertical subsea will be depicted as -4,940 feet TVDss). AIO 39 • • July 22, 2016 Page 6 of 13 e. Permafrost Base: The base of the permafrost is interpreted to lie between -500 and -1,700 feet TVDss within the proposed development area. 11. 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, 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 testimony 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. 12. Reservoir Fluid Properties (-5,000 feet TVDss Datum): Initial reservoir pressure 2,263 psig Reservoir temperature 1350 F Gas -oil ratio 425 scf/bbl API gravity 26.50 F Bubble point pressure 2,134 psig Oil formation volume factor 1.2 rb/stbo Oil viscosity 2.5 cp Gas formation volume factor 1.2 bbl/mscf (at saturation pressure) OWC estimated between -5,190 and -5,275 feet TVDss 13. In -Place and Recoverable Oil Volumes: Hydrocarbon Resources Estimated Volume (MMSTB) Drill Site 3 S 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 Primary + IWAG (11-45% OOIP) 11-225 11-135 Primary + MWAG (13-55% OOIP) 13-275 13-165 AIO 39 • • July 22, 2016 Page 7 of 13 Regular production from this pool within the Kuparuk River Unit began in 2013 from KRU 3S-19, and it has been reported in the AOGCC's records as the Kuparuk River Torok Undefined Oil Pool. 14. Well Logs for Injectors: To date no injection wells have been drilled in the KRTOP. When injection wells are drilled, logs will be filed with the AOGCC in accordance with the requirements of 20 AAC 25. 15. Mechanical Integrity and Designjection Wells: The proposed well design is similar to that used in the Kuparuk River Oil Pool with production casing set below the base of the West Sak Formation and cemented back to surface. Intermediate casing will be set with the shoe just above or just into the Torok Formation. The intermediate casing will be cemented in accordance with AOGCC regulations to assure proper isolation of any potentially hydrocarbon bearing zones. The wells are likely to be horizontal wells completed with solid liners with pre -perforated pups and/or sliding sleeves and external swell packers. Wells will likely need to be hydraulically fractured and will be completed with 4-1/2" tubing to accommodate this. Due to limitations with wellbore access for fracture stimulation and workover operations that may occur in the planned horizontal wells if the packer is set no more than 200 feet MD above the perforated interval, as required by 20 AAC 25.412(b), CPAI requests a waiver to allow the packer to be set more than 200 feet MD above the top of the perforated interval but the packer would not be located above the confining zone and with a minimum of 300 feet MD of outer casing cement above the packer setting depth. Tubing/casing annular pressure will be tested in accordance with AOGCC regulations and cement bond logs, or other data approved by the AOGCC, shall be run on each injection well to demonstrate isolation of injected fluids to the approved injection interval. 16. Injection Fluids: CPAI proposes initially to inject produced or seawater in the KRTOP to enhance recovery and may follow the water flooding in the future with lean or miscible gas injection to further enhance recovery. CPAI requests authorization to inject the following fluids: a. Source water from the Kuparuk seawater treatment plan. b. Produced water from all present and yet -to -be defined oil pools within the Kuparuk River Field, including without limitation the Kuparuk River Oil Pool and the KRTOP. c. Enriched hydrocarbon gas (MI): Blend of KRU lean gas with indigenous and/or imported natural gas liquids. d. Lean gas. e. Fluids used during hydraulic stimulation. f. Tracer survey fluids to monitor reservoir performance. g. Fluids used to improve near wellbore injectivity. h. Fluids used to seal wellbore intervals which negatively impact recovery efficiency. AIO 39 • July 22, 2016 Page 8 of 13 i. Fluids associated with freeze protection. j. Standard oilfield chemicals. 17. Fluid Compatibility: The KRTOP has a high clay content, but the majority of the clay occurs in laminar sheets between the reservoir intervals. Dispersed clay within the sandstone layers is not expected to be prone to swelling at the typical injection water salinities. Produced water from the KRTOP indicates the potential for moderate scaling during production and when mixed with seawater. Scaling risk is minimized by the placement of aqueous and solid phase scale inhibitors during the hydraulic fracture treatments, squeeze treatments, and chemical injection at the surface. These methods are expected to control scale risk. No compatibility issues are expected with proposed injection gases. 18. Injection Rates and Pressures: Maximum anticipated injection rates are 6,000 barrels per day or 6 million standard cubic feet per day, actual maximum rates for the wells will be constrained so that injection pressures do not exceed the overburden pressure gradient to prevent fractures from penetrating through the confining layer. The overburden pressure gradient, derived from the Moraine 1 core data, is 0.72 psi/ft. Maximum injection pressure will not exceed 0.67 psi/ft and average injection pressure at the sand face will be 0.62 psi/ft. Injection volumes will be managed to offset production voidage. 19. Fracture Confinement: CPAI built a fracture simulation model based on the Moraine 1 well log data, calibrated to core sample geo-mechanical tests data, and pressure matched to KRU 3 S-620 hydraulic fracturing results. The fracture simulation model was used to model hydraulic fracturing operations as well as water injection operations. The model results showed fractures to be contained within the KRTOP and no risk of breaching the confining layers. 20. Formation Water Quality and Aquifer Exemption: Analysis of KRTOP water samples collected from Moraine 1 core measured 21,362 mg/1 of total dissolved solids. Calculated salinity for produced water from the KRU 3S-19 and 3S-620 wells ranged from 16,000 to 20,000 mg/1 NaCl. Calculated and measured salinity values exceed the 10,000 mg/1 cutoff for freshwater. In 40 CFR 147.102(b)(3), the EPA adopted an aquifer exemption that covers the proposed affected area. 21. Offset Wells: Moraine 1 is a properly abandoned, vertical exploratory well that is approximately 725 feet from the proposed KRU 3S-613 injection well. The only other well in the initial development area is the producer KRU 3 S-620 well, which is located approximately 1,450 feet from the proposed injector. Future wells drilled in this area will be evaluated in accordance with AOGCC regulations. 22. Waiver: CPAI requests a waiver of the Injection packer setting depth requirement of 20 AAC 25.412(b) for injection wells in the KRTOP to accommodate wellbore access for hydraulic fracturing and workover operations. Injection packers will not be set above the upper confining interval and will be set with outer casing cement extending a minimum of 300 feet MD above the packer. A10 39 • • July 22, 2016 Page 9 of 13 CONCLUSIONS: 1. The requirements of 20 AAC 25.402 have been met. 2. Operation of an enhanced oil recovery injection project in the Kuparuk River -Torok Oil Pool will significantly improve recovery from the pool. 3. The injection interval does not contain freshwater and is not a potential underground source of drinking water. 4. Review of laboratory data and analogous reservoirs indicates that fluids proposed for injection, when properly treated, will be compatible with the Kuparuk River -Torok Oil Pool formation and formation water. Scale formation will be controlled using standard oilfield practices. 5. The proposed injection activities will be conducted in permeable and hydraulically fractured strata. These strata can be reasonably expected to accept injected fluids at pressures that are lower than those required to fracture through the surrounding confining intervals. 6. Injected fluids will be confined within the receiving interval by thick and laterally impermeable confining layers, cement isolation of the wellbores, and appropriate operating conditions. 7. Regular well surveillance and reservoir monitoring will demonstrate appropriate performance of the enhanced recovery project and disclose possible abnormalities. An annual report of injection performance is required and must include an assessment of fracture propagation into adjacent confining intervals. 8. Setting the packers in the injection wells more than 200 feet MD above the injection interval to facilitate wellbore access for hydraulic fracturing and workover operations will not increase the potential of an injection fluid confinement failure, provided the packer is at least 300 feet MD below the top of the production casing cement and is not above the confining interval. The location of production casing cement will be established through cement bond logging or alternate methods deemed acceptable by the AOGCC. Any alternate methods must be approved in advance by the AOGCC. MITs will ensure integrity of injection wells. 9. Reservoir voidage will be maintained at a replacement ratio of about 1:1. 10. Injection pressure will be limited to a maximum sand face injection pressure gradient of 0.67 psi/ft. 11. Sufficient information has been provided to authorize injection of fluids into the Kuparuk River -Torok Oil Pool for the purposes of pressure maintenance and enhanced oil recovery. NOW THEREFORE IT IS ORDERED: The underground injection of fluids for pressure maintenance and enhanced oil recovery is authorized in the following area, subject to the following rules and 20 AAC 25, to the extent not superseded by these rules. AIO 39 • • July 22, 2016 Page 10 of 13 Affected Area: Umiat Meridian 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 Sections 19-21, 28-34: All Rule 1 Authorized Injection Strata for Enhanced Recovery Fluids authorized under Rule 3, below, may be injected for purposes of pressure maintenance and enhanced oil recovery within the Affected Area into strata that are common to, and correlate with, the interval within the Kalubik No. 1 well between 4,991 and 5,272 feet MD on the resistivity log recorded in exploratory well Kalubik No. 1. Rule 2 Well Construction To facilitate wellbore access, in lieu of the packer depth requirement under 20 AAC 25.412(b), the packer/isolation equipment depth may be located above 200 feet MD from 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 feet MD above the planned packer depth. Rule 3 Authorized Fluids Fluids authorized for injection are: a. Source water from the Kuparuk seawater treatment plant. b. Produced water from all present and yet -to -be defined oil pools within the Kuparuk River Field, including without limitation the Kuparuk River Oil Pool and the Kuparuk River - Torok Oil Pool. c. Enriched hydrocarbon gas (MI): Blend of KRU lean gas with indigenous and/or imported natural gas liquids. d. Lean gas. e. Fluids used during hydraulic stimulation. f. Tracer survey fluids to monitor reservoir performance. g. Fluids used to improve near wellbore injectivity. h. Fluids used to seal wellbore intervals which negatively impact recovery efficiency. AIO 39 • • July 22, 2016 Page 11 of 13 i. Fluids associated with freeze protection. j. Standard oilfield chemicals. Any other fluids, or uses for the above fluids, shall be approved in advance by separate action based upon proof of compatibility with the reservoir and formation fluids. 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 Kuparuk River -Torok Oil Pool. Rule 5 Monitoring Tubing -Casing Annulus Pressure Inner and outer annulus pressure shall be monitored each day for all injection and production wells. Inner annulus, outer annulus, and tubing pressure shall be constantly monitored and recorded for all injection and production wells. The outer annulus pressures of all wells that are not cemented across the Kuparuk River -Torok Oil Pool and are located within a'/ -mile radius of a Kuparuk River -Torok Oil Pool injector shall be monitored daily. All monitoring results shall be documented and available for AOGCC inspection. Rule 6 Demonstration of Tubing/Casing Annulus Mechanical Integrity The mechanical integrity of each injection well must be demonstrated before injection begins and before returning a well to service following any workover affecting mechanical integrity. An AOGCC-witnessed MIT must be performed after injection is commenced for the first time in a well, to be scheduled when injection conditions (temperature, pressure, rate, etc.) have stabilized. Subsequent tests must be performed at least once every four years thereafter. The AOGCC must be notified at least 24 hours in advance to enable a representative to witness an MIT. Unless an alternate means is approved by the AOGCC, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1,500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, that shows stabilizing pressure and does not change more than 10 percent during a 30-minute period. Results of MITs must be readily available for AOGCC inspection. Rule 7 Well Integrity and Confinement Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by an injection rate, operating pressure observation, test, survey, log, or any other evidence (including outer annulus pressure monitoring of all wells within a one -quarter mile radius of where the Kuparuk River -Torok Oil Pool is not cemented), the Operator shall notify the AOGCC by the next business day and submit a plan of corrective action on a Form 10-403 for AOGCC approval. The Operator shall immediately shut in the well if continued operation would be unsafe or would threaten contamination of freshwater. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the AOGCC for all injection wells for which well integrity failure or lack of injection zone isolation is indicated. AIO 39 • July 22, 2016 Page 12 of 13 Rule 8 Annual Performance Reporting An annual surveillance report will be required by April 1st of each year subsequent to commencement of enhanced oil recovery operations. In addition to such other information as the AOGCC may require, the report shall include the following: a. progress of the enhanced recovery project and reservoir management summary including engineering and geological parameters; b. reservoir voidage balance by month of produced and injected fluids; c. analysis of reservoir pressure surveys within the pool; d. results and, where appropriate, analysis of production and injection log surveys, tracer surveys and observation well data or surveys; e. assessment of fracture propagation into adjacent confining intervals; f. summary of MIT results; g. summary of results of inner and outer annulus monitoring for all production wells, injection wells, and any wells that are not cemented across the Kuparuk River -Torok Oil Pool and are located within a 1/-mile radius of a Kuparuk River -Torok Oil Pool injector; h. results of any special monitoring; i. reservoir surveillance plans for the next year; and j. future development plans. Rule 9 Notification of Improper Class II Iniection Injection of fluids other than those listed in Rule 3 without prior authorization is considered improper Class II injection. Upon discovery of such an event, the operator must immediately notify the AOGCC, provide details of the operation, and propose actions to prevent recurrence. This requirement is in addition to, and does not relieve the operator of any other obligations under the notification requirements of any other State or Federal agency, regulation or law. Rule 10 Other Conditions If fluids are found to be fracturing the confining zone or migrating out of the approved injection stratum, the Operator must immediately shut in the injection wells and immediately notify the AOGCC. Injection may not be restarted unless approved by the AOGCC. Rule 11 Administrative Action Upon proper application, or its own motion, and unless notice and public hearing are otherwise required, the AOGCC may administratively waive the requirements of any rule stated herein or administratively amend this order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater. AIO 39 • w July 22, 2016 Page 13 of 13 Rule 12 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 July 22, 2016. CAly P oerster Daniel T. Seamount, Jr. Chair, eommissioner 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-lays 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, 2016 11:21 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)'; 'Frystacky, Michal (michal.frystacky@alaska.gov)'; 'Grimaldi, Louis R (DOA) (lou.grimaldi@alaska.gov)'; 'Guhl, Meredith (DOA sponsored) (meredith.guhl@alaska.gov)'; Herrera, Matthew F (DOA); 'Hill, Johnnie W (DOA)'; '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.pa lad ijczu k@ a laska.gov)'; 'Pasqua[, Maria (DOA) (ma ria.pasquaI@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 J (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'; 'Marquerite 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'; 'Tamers 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: Header A (DNR); Holly Pearen; Jamie M. Long; 'Von 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. Colornbie AO(7CC Special -Assistant .ACaska Od and Gas Conservation Commission g33 West 7" .Avenue -Anchovage, .ACaska 995o1 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 iodv.colombie@alaska.gov. 0 • 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 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 fy�&�Q L 1 v ��( 221 2 l� CLI--� S�Z�� Angela K. Singh INDEXES `I'I I I: S I':1 I 1 `ALASKA `e si'a` a,a<ivd rg Ir[I Y,'t�ril i.: t i, 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 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; AID 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 3 S 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. A10-16-011 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. nILA'yG //signature on file// //signature on file// //signature on file// Cathy P. Foerster Daniel T. Seamount, Jr. Hollis S. French 1 a Chair, Commissioner Commissioner Commissioner y°��q„ON,.A ` 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. !kle "-,*We me &a A 11 September 1s', 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 RE: Supplement to Request for Reconsideration Conservation Order No. 725, Kuparuk River -Torok Oil Pool, North Slope, AK Dear Commissioners: SEP 0 1 2016 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 Reconsideration of 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 ConocoPhillips August 1011, 2016 Alaska Oil and Gas Conservation Commission 333 W. 7th Ave #100 Anchorage, Alaska, 99501-3539 AUG 10 2016 Kazeem A. Adegbola AOO. C 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; 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). However, before the press, ire mamnteR ;RGe operatiORG GGFRmenne inieoforc will he predUGed to ensure adequate rese Neir voidan to annommortate water inientinn_ D,Finn this period there may he wells that evneed the GGR limit 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, 4 _1� Kazeem Adegbola Manager, GKA Development 0 ConocoPhillips May 241h, 2016 Commissioners Catherine Foerster and Daniel Seamount Alaska Oil and Gas Conservation Commission 333 W. 7th Ave #100 Anchorage, Alaska, 99501-3539 is MAY 2 4 2016 :C Kazeem A. Adegbola Manager, GKA Development North Slope Operations and Development ConocoPhillips Alaska, Inc. ATO-1326 700 G Street Anchorage, AK 99501 phone 907.263A027 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. 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 1 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 Area Injection Order May 2016 Page 4 of 11 CPA[ requests adoption of the Kuparuk sundry matrix, "Well Work Operations and Sundry Notice/Reporting Requirements for Pools Subject to Sundry Waiver Rules July 291', 2005", (Attachment 3 to this letter) in lieu of the proposed exemptions listed in the proposed Rule #7 of the "Application 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 page 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 Moraine Oil Pool injectors and to provide the logs to the Commission. Please contact Kasper Kowalewski (265-1363) if you have questions or require clarification of the information supplied in this letter or in the applications. Regards, Kazeem degbola Manager, GKA Development • • CPAI Supplement to Application for Moraine Pool Rules and Application for Moraine Oil Pool Area Injection Order May 2016 Page 5 of 11 ATTACHMENTS 0 • 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 ADL391 ADL38WO ADL389955 2M Arm 07 $373 µ1DL388 .�/ 2JAtryr6 ConocoPhillips AD1379301 Alaska Inc. ADt389960 AAt389959 A04389958 — _,. _. __ . _.. _._. _.__. __ . _ 925 Moraine Area aryection Order N Surface Rights and Leases ADL389954 ML38M 0 M 13 1.95 2b nda N PP ' 25% AD307 OD ADLVM AD ADL355030 Dt 24 3R AD13 i 125% 23 AM73301 i 30% NIPS Oooguruk 30 urn ADL38M2 ADL38M 1 3 Al"Lo 13 125% ADW25512 AM 25522 W% NPS 12.5% ADL355039 ADL355032 AF69w, ADL355038!`6.6679ii 8 H 125% ADL025521 L025 12.5% ADID25523 ADL0255241'4 1 ` L392113 Ku d ADLD25531 3J ADL39oa34 12.5% 12.5% 12.5% Rivi r Un H AD I ADLD 30 AOLD25528 ADL380IDO ADLD25532 AOLD25W 3L3 AMODS97 12.5% 12.5% 12.5% 12.5% ABLO25832 5L133 ADLO25W ADL380107 ADLO25W 3G 3 t391913 ADL392374 ADL391912 16AM7% 12-5 ADLM043 2W Placer ADL05% 5� AaD2% ' AMOM42 Unit ,zu AD 10 i ADL39102 21 i 2X R391024' 139154i ADL30150 16.66667% 12.5% 12. %� AD ADL392371 ADID255L18 ARID 509 ' Wel P ad Moraine Ado r Ur�t Bo�dary ADL3916Q ADL392o28 A ADLO25571 570 ADL02DW C LAKLeases ADHER JL39M AI i. 0 0 CPAI Supplement to Application for Moraine Pool Rules and Application for Moraine Oil Pool Area Injection Order May 2016 Page 7 of 11 ATTACHMENT 2: LOCATION OF EXISTING 3S WELLS AND MORAINE PHASE-2 PLANNED WELLS 161000OF E 162000OF E 163000OF E Legend Coastine-------- 4 .�. { t ° unit Boundary I lease BourKla y _ -- s a AlO and Pool Area _. --------- DO Site Pads y iia 'S i Phase 2 Wells - II 600000OF N i Top Monne of pod Penetration • 6000000F N 3S-613 35 620 3S-06 ♦ 3S-10 • MORAINE 1 i 3S4)6A • 3S-09 • 3S 1 3S-14 t 3S-17A 3S-07 j • • 3S-18 • 3�-26 i -03S-19 15AL I-o 111ODS 3S • ; 3S-16 3S-23A• 3S-22 3S-08B%3S-08A 3S-23 + 3S 03 nuc • 5990000F N 3S-08 5990000E N 3S-24A 3S.21 •• ;1 0 1 MILE a 598000OF N 598000OF N E m a O 0 m E to m Q 0 n- 0 a m 0 2 o c 0 v_ 0. 0- 0 c m m CL o U)Nco m a m Urn 0 0 (' N Z H ON a} W J W F LU OJ Z :3 oc �W co Z>� MQ to3 o}z Q 0 N Z Q ZM C ON E HO Fz a~ W LU °' w O O -� W Ym > O 3 N J -10 J O ul c. 30 �U. 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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 EA • 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? C 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. 4 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. 11 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 E 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 9 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 N. 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 11 -- 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 01 • 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 11 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], 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 it 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..... IN 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 11 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 11 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 NM • • 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 11 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 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..... it 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. 34 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 11 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 39 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, 35-613 and 35-620, 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 35-19 and the 35-620 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. 1f 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 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 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 48 • • 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 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 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 35-620 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 2 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. 11 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. • E 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 it 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 63 • • 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 1] • 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 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 • 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. M 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 •" 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; 70 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, Ind 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 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 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 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 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 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 78 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. 18 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 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..... 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 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 35-613, 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 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) 18 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..... 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- . 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) W 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 :3� 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 35-613 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) 87 1 C E R T I F I C A T E 2 UNITED STATES OF AMERICA ) 3 )ss 4 STATE OF ALASKA ) 5 6 I, Salena A. Hile, Notary Public in and for the 7 state of Alaska, residing in Anchorage in said state, 8 do hereby certify that the foregoing matter: Docket 9 No.: CO 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 ConocoPhillips • AOGCC Pool Rules and Area Injection Order Applications for the Moraine Oil Pool • May 10t" , 2016 w NO —Area Injection Order w API —American Petroleum Institute w BaSO4 — Barium Sulfate w CaCO3 — Calcium Carbonate 10 w CPAI — ConocoPhillips Alaska, Inc. m CPF — Central Processing Facility w DS — Drill Site w FWL — Free Water Level w GAPI — Gamma Ray American Petroleum Institute (Units) w GOHFER —Grid Oriented Hydraulic Fracture Extension Replicator 0 w GOR — Gas -oil Ratio w HC - Hydrocarbon w HRZ — Highly Radioactive Zone m HZ—Horizontal IWAG — Immiscible Water Alternating Gas w KRU — Kuparuk River Unit w LOT — Leak -off Test w MD —Measured Depth w MI — Miscible Injectant m MWAG — Miscible Water Alternating Gas w ODS — Oooguruk Drill Site m OOIP — Original Oil in Place m O/W — Oil/Water w PPG — Pound per Gallon w RDT — Reservoir Description Tool w RF — Recovery Factor m TOC—Top of Cement w TVDSS —Total Vertical Depth Subsurface w USBM — United States Bureau of Mines w WF — Waterflood w WI — Water Injection 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 A10 Rules (Kasper Kowalewski) Timeline w 1960's — 1980"s THETIS IS I �ikaitchuq ■ 3 wells and core (Colville 1, Colville Delta 2 & 3) O00%11RUK I W 1990's 000guruk IV'" IDST-39 ■ Vertical well test and core ODST-46 •KALUBIK 1 Li 3 gathering campaign (Kalubik T 3QN CO LV DELTA 2 1 & 2) 'ODO-47 30 2000's — 2010's 3M NL ,A I ■ Successful horizontal well J j --- — — ---- NuKtlptii -J 31 PIK tests and ODS Development Kupar k River 2013 — 2016 CPAI 35-620 3H 3J 3A • 3S-19 recomplete MORAINE1, .'"iALM"l 3S Legend 3S.19 • Moraine I core well Coastline ...... .... .. . ........ ■ Cored overburden for Unit Boundary......................... ......... . .......... COLVILLE I Lease Boundary ...................... ... geornechanical testing Pi Leases within AiO and Pool area but outside KRU .... ......... and reservoir L 2 AID and Pool Area .... .. ........................ ....... .. --------------- ------------------ containment study 2T Drill Site Pads ....... ... ..... • 3S-620 horizontal producer 2%F 2Z • 3S-613 (planned horizontal A I 2C injector) Significant Moraine Wells Shown Cono4hilfips 79301 AYPL Nikaitch q ADL3W17 41 a ADL392712 ADL392711 ADL389900 ADL389M ADL389M � ADL389W !I Unitwmi AM—AM18 i 67T AOM12U ' ADL 85 25M 24 ' p 1 ADL.389900 ADL355023 233 .� j 37 il':ERalltC 3 5030 0t4589 4179d3 R In Poin Logmd — weae Dean e� Rx 00?"^ fca"•ae.W CA M. AD. W01 Yuritipat Ent#lement Q!o. a+u:9 wOrrN tlC.E lOroWHwTM. P. �, a,4a7.egRM &.002 10*0wo. ATM R �ro.alTee3. YOrT, i0►! f0R0'A� ATM- P.. Easements O /�6. a1�fy7►EHl6t [V.7yfK�ll4DY0liit6 Y0�, 1n�rYllt L.lfndt f Si: Q ro_ yap0a sytlr Mlira'�ltlgrelSA.l !Oa. ne4YY.x EaeenpY, f al. Permk_or Lean ro: aoirt7. Canoolol.la wa4. a+c lurava:.t.t 0ra r, sae. —+0. a1za00, 6a•+e'v Ge�rvroetean.v+: roc? ntp :ta �uro JSSB� ro.a1te/0.WPn.M 4adrfa'•GTC OtaR:lNe Ca'a •;a3• PW w" M.rl Wrl OM mew Uurrcoal Land Entkkenents OC 4i"n NYT3W.bx9R A- PN—VOW.. Oro. 41-W N"leas fd0 AM0W.. Q 1m a1TM7,?YarT seat fang - Bureau d land Yamgurellt Native Albhnents O.Wr onsu Ac. 0"": ®"'O" o1un =Mo° 01mu =mc. Olum �ow. olms QM" clam =maw Cum =AO+ OtsSM �': Ne&EV OAT :q:fSn ►.a MG.104xa •X LM$" �c1+.a1 3S 40 L31 i ADL391546 AOL391548 j ADL3d2*2# AQt.025S71 3 �j 304� _ Unit P22 ADL025312 02551 30 ADL025514 _.. 25515 i 25517 55 ADL025521 25520 ADL025519 3J 2501 gDL02 80 AOL025M ADL025M 1f Kuparuk River Unit 38 ADL025032 5833 ADL025634 1R AOL02 35 y iA r ADL02WA2 ADLa25E43 ADl02 1 2W 2U AOL02 40 r ADL02 Conocol'hillips Alaska N Moraine Area Injection Order AOL02 55 AOL Surface Rights and Leases 0 05 1 lC�ei7ca 5 si�iii . ! �' ::.:' ��=%��_' ConocoPhillips .......... • 0 ConocoPhillips Geology and Pool Description r ConocoPhillips Well: PALM No. I Alaska, Inc. RecWivily Shel. 1 OHMM 100 Neutron Povosdy R"istivityMeo. 60 PU 0 D 1 OHMM 100 Denny^ Comma Ray 1 2700 MI R_es in'.ty Deep__._ 1 65 GiC3 2AS 0 GAPI 2001 11 OHMM 100 Member Formation -. 3500 - - 35M d I � 4Dow 1 4500 i 4500 t v Y saoo O 5000 55W semn. Mn _a Upper Moraine Lower `o Moraine g 8000 s oa3 n. Mn H RZ AGE M.Y. S.P. LITHOSTRATIGRAPHY sSISMIc OUENC NOIT U QUAT. GUBIK FM - N MU Z U.1 SAC'A"A.. IKF ICJK FAA,�.._r_-- z W YZ w a 100 NANII^ " - - BU U it - - rr'f "8i3LLSHALE •.•' -�- - RIFT OUENC CU 0 U N O UU) JURASSFC SA _ -��_ Sc KINGAK SiiAL£` - _- U M W ARROW SAND z 20D a-w= Jw U V) `—'�"a ...w..__,,.,=A1 RI ER �h." _Ti!_U6urF?,1 _ —� y IVISHAK FM' ECHdOKA FM; PU a z W U W2 W 0 380 W O p JJin LISSURNE GP N yQ N E: UJ W r W —1 gram 'T i 3TSL' �.�6NDICOfTG U Z� ZU 400 tTr Y Zo z OKPUK Stratigraphic column modified from Alaska. DO&G, 1996 m Moraine Oil Pool within Torok Formation ■ Cretaceous slope to basin floor turbidite deposits ■ Divided into two Members: Upper and Lower Moraine m Combination trap with Stratigraphic and structural 7 �� ,. ::••�� ConocoPhillips ..ee..... • • Conohillips Alaska, nc. Well: PALMNo.I Moraine Oil Poo Reaeua Sl,el. 1 OHMM 100 NauVon P0,06 ReaalM�Med._ 60 PO 0 TVD56 (e) MO (fll , ONMM 7Oo pena4�_ Gamma Re , : eA R" 1,66 G1Oo 2.65 Member Formebon I 0 GA 200 , UMMM 10U �50 5650 5100 56� 5.0n MD ... 5,50 5650 JIt C 5200 5700 G O 0 5250] 5750 d C O tw CL 5W_ 5a00 m 5W C 5050 C a1 5 {O 5900 r 0 ` Co 5400 5950 ZE } /r ty C 5450 6000 5500 5050 - a aJ a. MD N } 6100 5550 if k sy i 5600 i w 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) w Deposit dominated by very fine grained sand to coarse silt w Thin bedded reservoir (sub -inch to few feet), interbedded sandstones, siltstones, and mudstones w Expect poor vertical permeability due to the interbedded mudstones Do" -top OF 1r Fq j. t ifV � -• 11 � k.� y�� +�� . • +� !� \ ` N. Modified from Ford, T.D., 2002 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 w 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 of 5 mD 30% to 85% water saturation Peripheral Tarn deposits as local analog ModifiedfromFord, 00 9 .... ConocoPhillips Moraine Oil Pool Northine I Well •�'Borough, 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 - - i 15% to 28% porosity, arithmetic mean of 19% 0.5 mD to 93 mD permeability, with an arithmetic mean of 5 mD 30% to 85% water saturation f Peripheral Tarn deposits as local analog j name. -mv r r Ultraviolet Light Modified from Ford, T.D., 2002 10 °""""' Conoco -Phillips ConoeoPhiilips Alaska, Inc. 6040000FN Upper Moraine Depth Surface Structure Map N , OHMM iDU Neutron ,� \• '•% ____" • • • ♦ \ � \ � � 2 \ ` 80 PU 0I --- ,lI • AO\ - 1 • ,t`tM ReehS Mao. IwnA MD t OHMM 100 w,a- , m Int 1.55 GrCJ i 65 n (>API 20U t IJHMM 100Oobquruk . — 6020000E N Top Upper t�,1,..--',; g o, E f'\�SBo; • • • • • 02000OF N Moraine r_ ^o A, t i Structure (!r f a� saoo 1 -4940 SS It -5000 rn 5750 Top Moraine/ Y -5050 lOP upper Morane/ E -5100 •-+<j 1�' �\� \ 'l 5650 - i Top Pool 150 5200 N -5250 -Ssoo -� Kuj3atu •River szoo s7oo -5400 510 00 'iY� 5450 6000000E N •' i^f/t �� % -5550 �' • �� 1 ly�� • • 000000E N i _ - -5600 • D. C -- 550 5250 -.5650 5700 t 5 /•' • • ry • 1 �. a•Y _ �• 558 0 si°° VALM: f .5220 `:•,�� , : Top Pool/Top Moraine .... ssW-5900 - 0 •• • •5240 Irl•) 5a� 5140 ®�g -4,940 ft. to -5,880 ft. TVDSS _5'16 Sz p • • s� • s350: p • • ' 5900 r - o 1 z 00 t . _. __ -. s•ao 5�a I .. 5980000E N MILES 51�-0 B S.ipC • 80000F N f Placer S�qO° a° s c' �-✓ • o Legend 5150 eoso -- Coastline �-- ---, • ,ISO N • a' Unit Bound ~-:_. Bax Lower Moraine/ j, .5360 /�I \� �y ...... . ;... seoo- Gm- 9.. _: Baee Pooh 1 53g0 — ` �''^sue �0 Boundary ............... Top NRz 1 -S.i Lease I------`---- -. _. > N { 5400 , • • f :53ry�i D AIO and Pool Area ...... �� etoo Well Penetration • S a�e .r s�o � • • In Upper Moraine .................... stso -: 5960000E N " • Fault _.. 9ti0000F N z............. . r a QX 8 o p ti • • • • • Cowc(;faips Alaska, Inc. OnIm mn 1 N Re •Wft MW so PU 0 twAB mo oHmm 100 u 4Y -em - 1.05 GIC3 -2-66 11 CHW 100 50 "00- 5,50- -7 UVA - 52W.- Sj(XJ. _r Wo - Sip - seop -7 5."o- 5450 m - 6m5500 5550 tir 5600 f)0400WF N -Moraine Oil Pool 1, lsochore 14) J, Oo6gyruk 602.0001 N Moraine Oil Pool lsochore fJ Cl = loft. 640 top Wrain 95 550 fop Upper M..—/ r.p Pool 525 Soo 475 450 425 400 375 350 V 600000OF N 325 300 275 250 225 1775 50 125 100 O I 0 1 2 5980000F N MILES c Placer 1 1, '� Ba. L M.-W B.. Pmif Top HRZ x 5960000F N. S 504000OF N -31.0 502000OF N A6N —er * * upae7U4 Ri.vL r'u -R 000000F N Moraine Oil Pool Thickness 60 ft. to 640 ft. 598000OF N Legend Coastline . ..... : I `-------_----- Unit Boundary _ Lease Boundary . ...... . A10 ------------ and Pool Area...... ----------- j Well Penetration a in Moraine 00 Pool Fault . ... ......... .......... N LL 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 GAPI TVD55 MDmm rtivity 0........180 I.)!h.) .100 AIO/Pool Boundary; -------------------- 11 • Ol North to south 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 GAN TVDS MD ohmm 0........180 cnd (k.? 1......100 141, r N ruk Unit— "N • p3ri f . c F .a»- 4lw J154 ws9 ax aax- 1 >a» 'lijl �o uW 51 1a/S4 i }I ow 51» oA 1os5a 5t50 a: --, 7 mie Lj' �., A,1904 1 1395 o' S150- Slx- 06C1 ..5154 asw a1W- I —� I lu7 •� 0 ; OW,1 I 1 I } two- 110R 89W u }!»- 10 0ala. ( 9lw ar5a. I Y1550. N75a z1x 1091P 52•A 49W. }2x 0.50 tw . 521.' S:W 1OM Upper ' I t T re siR;. ll]!P I S ;,'5:•. 1P3 t19sa• Mo mine H 9lW -S/ a}W i 1NP I i .w -53x- 5359- 111SP aaos a9W l.L^a. 9.'65 I .9W. Milo. i {P1M H�A.- 1125P .,�0a i1x 4UY 41W_ ' _H 7pw� 90U3. 1 SaSil. I1C :1r10- i1W- i ,,•l -.: ]tli9- 7.1.- 12:40. IYMf- I � y].'A- llw l.SP Sa50 � i L-- 4.19 93'A� .. H•A .. • _'9PSQ- 1 -sSW- LIiSO- t9:AF 1 �. LDW2r ; .YW- HW' 9x0- ^}$a} 715a- is Saw Saw - 2T-36 IP--" ConocoPhillips • Resource and Recovery Details F, LegendJx.) Coastline_...__.... ........... _...... .__..... Unit Boundary Lease Boundary __.__.__ and Pool Area .__....__.._OS 00ogu ukAIO • Pads ...-.... _............._......_._. �'• •� • 30 Well Penetration in Moraine Oil Pool _ 3M Fault. / • . . 31 KuPar'ti River J ��.-ar ,•. •••. .. 3A • ' • . .3 �..r 8. 3s.. : • • • . • • 3B• o i z • . . . 1Q ZW. Placer • • • ;ZT ZX • ZA• - Phased development approach focused from existing infrastructure ■ Primary target — DS-3S area ■ Secondary target — new drill site to 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 16 Cono4hillips :....ease. Phase 3 Uevelopmerd Phase 4 bewlepTmV w Planned horizontal well length to range from 3,000-8,000 ft w Well spacing to range from 1,000 2,500 ft ivioraine Pool Properties (@-50001ftl TVDSS) Initial Pressure (psig) Temperature (F) GOR (scf/bbl) 26.5 2,134 1.2 2.5 1.2 100 — 500 MMSTB 100 — 300 MMSTB 10-40 Horiz. Line Drive 14-28 Horiz. Line Drive Estimated RF i 17 ••••••••••• Conoco -Phillips .. ........... • d 35 Z~ a 30 = 25 � a 0 20 'o C 15 U� 10 0 W6 5 0 :P 0.00 11 �4 0 0.00 Typcial Waterflood Recovery Efficiency (Moraine) 0.50 1.00 1.50 2.00 2.50 3.00 HCPV Water Injected (fraction) 0.50 1.00 1.50 2.00 2.50 HCPV Total: water+gas (fraction) 3.00 —IWAG --25% MGI --50% MGI ---75% MGI 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 001 P m MWAG incremental is expected to range from 3-15% of 001P ■ Tarn: 8-15% of 00113 ■ 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 m 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 to N .5250 4-� -5300 Q () -5350 r) -5400 -5450 -5500 -5550 2260 2270 2280 2290 2300 2310 2320 2330 2340 2350 2360 2370 2380 2390 2400 2410 2420 2430 2440 • ConocoPhillips Containment and Operations Details 20 Prevent leakage into oil, gas or freshwater zones (no freshwater zone is present) ■ Cased and cemented for zonal isolation Isolate pressure to injection zone ■ Casing, tubing and packer Verify mechanical integrity ■ Tubing and casing pressure tested ■ Daily monitoring 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 EN 111 : 111 "' ConocoPhillips • • 11 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 ..w w 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 ■ Enriched hydrocarbon gas (MI): Blend of KRU lean gas with indigenous and/or imported natural gas liquids ■ Lean gas m 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 24 :: ....... 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 0 ■ 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 m 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 Conoco~Phillips Well: PALM No. 1 Alaska, Inc. f2esistivity.5 h_ al. 1 OHMM 100 Neutron Parosly 60 PU 0 Resistivity Med. T"oSS MD Uenwty 1 OHMM 100 (ft') ie.t 1.65 G7C3 2.65 Gamma Ray1 . 7700 Resishv� Dee Member Formation 0 GAPI 200 1 OHMM 1GO 3500 3 3300 Q: _.. U) 4000 4000 4500 ,500 Y O L O - 1- 5000 5500 l' 5.6301t MO O Upper o a Moraine a % Lower Moraine i 6000 6[W n rug HRZ Palm 1 MO Geomechanical samples within overburden Gamma Ray ;wo Fracture Pressure 0 GAN 200 10 PPG 20 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 35-620 (red dot on fracture pressure curve) _s_ �. _ Hue Shale 4000- _ - 5000 Torok sow 560D - Moraine Oil Pool 6000 6500 HRZ equivalent stratigraphy sampled for geomechanical work in Moraine 1, highlighted in orange on Palm 1 • w Conducted internal containment assurance analysis ■ CPAI has subsurface containment assurance standard which includes a multi -discipline periodic containment review w 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 coasone ,>r*Bouad a Lease Bo-dwy ------------ aoand Pool ae. osPaas ..._____.............. 35 (ex.) . Well Peeeaa6w in M.— Oil Pad e Faua - - r W! Placer i 3n 30 Kupar�Yi�c eerr 1 ZW: •1G •xe • •2 V, . 7A• X Top Upper Moraine/Top Pool •w-r • �S '•;•�%r Palm No.1 (COPAI) UM Top UM Base LM Base : ref -2376 -792 792 Net Pressure (psi) Base Upper Moraine/Top Lower Moraine 2352 3936 5100.0 5220.0 v 5244.00 470.166 S 5266.00 C 610.183 0 5292.00 739.583 5316.0 5520 29 ConocoPhillips ........... • ►� C] Top Upper Moraine/Top Pool 0 • go mail Proppant Concentration (Ib/ft2) Base Upper Moraine/Top Lower Moraine 480 5124. 5148. 517 51 5220.0 v 5244.0 10 elt 5268.0 C 0 5292.0 5316.0 M 3.19301 0 n 3.99502 4.7920 a �. 5.5+ ell• N Top Ur-Ner Moraine/Top Pool ; -�,�r, r;Y r .� cif ,' t Net Pressure (' _� • : IV �%�I�N�I�N�tvl�l�ii��lE�1�IHN1iI�lUti Ilu�i/� 1 �i t, ■rt/i�1i�11liH1u11/m�Hnill ii anwn�t>twnn�t��unn�wwal 1 �n l� = : ; � nuuwuwlw�t��lwwwl>,w�uw�wu�t�N�nmli iint�wtwlt�uun�nnwn�wluluwuwtuunn�n i/i/Iiltllnitlil�i�t��initlttl(tl/I�tnl/Illtlt��lilw �IIl1I1WIN Hlu�mislttl�li>twwnlnuHtuwinn� , t' n1�1111f1iU/Ii�1�1��IntfH�l�tE�i�t/�It�l111H ��nl�numnw�n�luunnn��un�l utnml win nuu �IIIH�U�1#Hll�/III��If�lll/�i�l��lil><�1i101111f1� �!/ 1 llimom�ullow Il1llUnll� I�ISII111111 illlllll II Palm No.1 (COPAI) ' ' L i4- V i , -',G, UM Top + v, — -• ;:�:,: ;:;:'�L riiia.:n i, .,_µ � ; ;� '1L�'!t 1.}. i L�r UM Base u F LM Base f • � - fi I .�� }i _# _fit { (t 4 2:36 — ... ._. L_ L�.�i_�_0�.�!�l�-;. Base Upper Moraine/Top Lower Moraine 31 ""'0"" ConocoPhillips • iO • 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 w Average injection gradient: w Maximum injection gradient: m Overburden pressure gradient: w Overburden fracture gradient: w CPF-3 Fluid gradient (water): 0.62 psi/ft 0.67 psi/ft 0.72 psi/ft —0.82 psi/ft 0.442 psi/ft gradientGas 1 • 32 •...U: ConocoPhillips . ee::...... Rule 1. Field and Pool Names w The field is the Kuparuk River Field, and the pool is the Moraine Oil Pool. 40 Rule 2. Pool Definition im 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. MID and 6,043 ft. MID (-5,144 ft. and -5,486 ft. TVDSS respectively). 0 ............. 34 "'�.::::= ConocoPhillips ♦d 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. s"`":Cs::OtalO.. 35 �_;��••••••••••• ConocoPhillips 0 0 0 Rule 4. Drilling and Completion Practices 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. m 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. w 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 ConocoMUM— Phillips .: :e:::::::: 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. 0 Rule 6. Reservoir Surveillance 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. 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 m All pressure surveys will be reported annually, rather than monthly, to reduce paperwork due to the limited number of surveys. 38 "•MUM 6"" Conoco Phillips ........ 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 �. ��::::::i::eE.::. ConocoPhillips 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 1p at least every three months thereafter. Rule 9. 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, jeopardize correlative rights, and is based on sound engineering principles. i 41 °?:::=� ConocoPhilli s 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 S 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). • "'"°"'""""""" Conoco Phillips 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 40 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. • .............. ....:::. 43 =$ss�"Y�°""" ConocoPhillips ::...... R Rule 3. Authorized Fluids for Injection for Enhanced Recovery �► 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. • • 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 s 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. 0 Questions? 47 ............ ConocoPhillips ::ia`iroouuui w AIO —Area Injection Order w API —American Petroleum Institute w BaSO4 — Barium Sulfate w CaCO3 — Calcium Carbonate w CPAI — ConocoPhillips Alaska, Inc. w CPF — Central Processing Facility w DS — Drill Site w FWL — Free Water Level w GAPI — Gamma Ray American Petroleum Institute (Units) w GOHFER —Grid Oriented Hydraulic Fracture Extension Replicator w GOR — Gas -oil Ratio w HC - Hydrocarbon w HRZ — Highly Radioactive Zone w HZ— Horizontal IWAG —Immiscible Water Alternating Gas w KRU — Kuparuk River Unit w LOT — Lea k-off Test w MD —Measured Depth w MI — Miscible Injectant m MWAG — Miscible Water Alternating Gas w ODS — Oooguruk Drill Site w OOIP — Original Oil in Place w O/W — Oil/Water w PPG — Pound per Gallon w RDT — Reservoir Description Tool w RF — Recovery Factor w TOC — Top of Cement w TVDSS —Total Vertical Depth Subsurface w USBM — United States Bureau of Mines w WF — Waterflood w WI — Water Injection 2 Conoco .. Phillips :.........sous.. is • OnocoPhillips Well: PALM No. 1 Alaska, Inc. Resistivity Shal. 1 OHMM 100 Neutron Poros' 60 PU 0 Density Gamma Ray TVDSS (ft.) t : 2700 MD (ft) Resistivity Med. Member Formation 1 OHMM 100 Resistivity Dee 1.65 G/C3 2.65 0 GAPI 200 1 OHMM 100 3500 3500 W -- -- " 4000 i f ' 1 4000 - --- 4500 � ! i 4500 ►/ - 5000 LM 5000 — 5500 5,630 ft. MD o CL I� Upper Moraine _ s Lower Moraine O g 6000 6,043 ft. MD N.� H RZ A Defining well, Palm 1, highlighting Pool interval with respect to regional stratigraphy • • 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) Jo,D�I �G'arn�i� 1�0 GC C- LI 0IIv Umlatt� " I SMAMR yef . I-.02NA JZICHWND COP n f �kZ��M �}�E.l�►t3ui�A �P 1`� NAME AFFILIATION Testify (yes or no) cArl's cc, Vo lull xg.�r-- 52nA-A.nW,A cac�;s�'N Aoc., cc ✓`o 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 7`h 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. Daniel T. Seamount, Jr. Commissioner STATE OF ALASKA ADVERTISING ORDER NOTICE TO PUBLISHER SUBMIT INVOICE SHOWING ADVERTISING ORDER NO., CERTIFIED AFFIDAVIT OF PUBLICATION WITH ATTACHED COPY OFADVERIISMENT. ADVERTISING ORDER NUMBER t AO-16-018 FROM: Alaska Oil and Gas Conservation Commission AGENCY CONTACT: Jody Colombie/Samantha Carlisle DATE OF A.O. 04/05/16 1(907) AGENCY PHONE: 279-1433 333 West 7th Avenue Anchorage, Alaska 99501 DATES ADVERTISEMENT REQUIRED: COMPANY CONTACT NAME: PHONE NUMBER: 4/6/2016 FAX NUMBER: (907)276-7542 TO PUBLISHER: Alaska Dispatch News SPECIAL INSTRUCTIONS: PO Box 149001 Anchorage, Alaska 99514 T1�PFiQ LEGAL DISPLAY CLASSIFiEU OTHER(Specifybelow) I r., .... , DESCRIPTION PRICE CO 16-007 and AIO 16-011 Initials of who prepared AO: Alaska Non -Taxable 92-600185 31)BINii:AtVUI... ......G .. ..ERTiSINC: OHI)EI2N0.; CERTTFIED AFI7DAVIT 011! ? Pusiiraiioxwifn:nTfie- i> D'otirxor: .................................... iiDVERTI&Ititl Nr:�o::: »:::::: .................................... Department of Administration Division of AOGCC 333 West 7th Avenue Anchorage, Alaska 99501 Page 1 of 1 Total of All Pages $ - REF Type Number Amount Date Comments I pvN ADN84501 2 AD AO-16-018 3 4 FIN AMOUNT SY Appr Unit PGM LGR Object FY I DIST LIQ I 16 021147717 3046 16 2 3 4 -T Purc si gf±e)l i Purchasing Authority's Signature Telephone Number # and receiving agency name must a ear on au invoices and documents relating to this purchase. 2. h state is registered for tax free transaction nder Chapter 32, IRS code. Registration number 92-73-0006 K. Items are for the exclusive use of the state and not for re ON::::::::::::::::::::::::::::::::•::::::::::::::::::::::::::......:::::: :: T1IBUTI....................•.•.,.....,...,....., ebeiviii ....... ...........::::.. ..................................pied:.:.........r:(faxed);. .......... scal,......... g . ........ _ ............................... . Form:02-901 Revised: 4/5/2016 Colombie, Jody J (DOA) From: Colombie, Jody 1 (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 1 (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); AKDCWeIIIntegrityCoordinator; 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; Kazeem 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@a nadarko.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. 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); 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 Adeyeye; 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 O (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 (LAW); Talib Syed; Terence Dalton; Tina Grovier (tmgrovier@stoel.com); Todd, Richard 1 (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 0 is lodtl T. ( olombic Yc( laI _�sslstanI llaska (h( and yas ('oiiwi vaIion ( oin61ission Al horape, _"M aska ()95m 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 iodv.colombie@alaska.aov. • 0 James Gibbs P.O. Box 1597 Soldotna, AK 99669 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 Jack Hakkila 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 Darwin Waldsmith North Slope Operations and Development P.O. Box 39309 ConocoPhillips Alaska, Inc. Ninilchik, AK 99639 ATO-1326 700 G St. Anchorage, AK 99501 Yo,_t. (SL 4Vc:L fie, 2v\ce Angela K. Singh C7 RECOVED MAR 3 l 2016 Cono%&:.0Phillips March 31 st, 2016 Catherine P. Foerster, Chair Alaska Oil and Gas Conservation Commission 333 W. 7th Ave #100 Anchorage, Alaska, 99501-3539 Kazeem A. Adegbola O C 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 Area Injection Order for Moraine Oil Pool, North Slope, AK Dear Commissioner Foerster: In accordance with 20 ACC 25.402 (Enhanced Recovery Operations) and 20 AAC 25.460 (Area Injection Orders), 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 an Area Injection Order ("AIO") for the proposed Moraine Oil Pool, which is 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. First injection into the proposed Moraine Oil Pool is scheduled for July 2016. CPA[ 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) Cono(c0ouPhillips March 31st, 2016 Catherine P. Foerster, Chair 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 RE: Application for Area Injection Order for Moraine Oil Pool, North Slope, AK Dear Commissioner Foerster: In accordance with 20 ACC 25.402 (Enhanced Recovery Operations) and 20 AAC 25.460 (Area Injection Orders), 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 an Area Injection Order ("AIO") for the proposed Moraine Oil Pool, which is 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. First injection into the proposed Moraine Oil Pool is scheduled for July 2016. 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 degbola 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 Area Injection Order • March 2016 Page 1 of 49 ConocoPhillips APPLICATION FOR AREA INJECTION ORDER IN THE MORAINE OIL POOL March 31 st, 2016 Section A— Introduction Section B — Plot of Project Area 20 AAC 25.402(c)(1) Section C — Operator & Surface Owners 20 AAC 25.402(c)(2) Section D — Affidavit 20 AAC 25.402(c)(3) Section E — Description of Proposed Operation 20 AAC 25.402(c)(4) Section F — Pool Description 20 AAC 25.402(c)(5) Section G — Formation Geology 20 AAC 25.402(c)(6) Section H — Logs of Injection Wells 20 AAC 25.402(c)(7) Section I — Mechanical Integrity of Injection Wells 20 AAC 25.402(c)(8) Section J — Injection Fluids 20 AAC 25.402(c)(9) Section K — Injection Pressures 20 AAC 25.402(c)(10) Section L — Fracture Information 20 AAC 25.402(c)(11) Section M — Formation Water Quality 20 AAC 25.402(c)(12) Section N — Aquifer Exemption 20 AAC 25.402(c)(13) Section O — Hydrocarbon Recovery 20 AAC 25.402(c)(14) Section P — Confinement in Offset Wells 20 AAC 25.402(c)(15) Section Q — Proposed Area Injection Order Rules List of Figures/Exhibits B-1: Plot of the Moraine Oil Pool Area and all Existing Wells D-1: Affidavit F-1: Outline of AIO and Pool Area highlighting leases outside of the Kuparuk River Unit (KRU) F-2: Defining Well, Palm 1, highlighting Pool interval with respect to the upper and lower confining intervals F-3: Defining Well, Palm 1, highlighting Pool interval G-1: Moraine Oil Pool Isochore G-2: Upper Moraine Member Isochore G-3: Lower Moraine Member Isochore G-4: West to East Well Cross Section across the AIO G-5: North to South Well Cross Section across the AIO G-6: Upper Moraine Member Structure Grid G-7: Lower Moraine Member Structure Grid 1-1: Generic Moraine Injector Well Design J-1: Kuparuk Seawater Treatment Plant Water Composition J-2: CPF-3 Produced Water Composition J-3: Moraine Gas Injectant Compositions K-1: Moraine Oil Pool Injection Pressure Summary CPAI Application for Area Injecterder March 2016 Page 2 of 49 L-1: Water Injection without propped fracture in 1377 acre flooded area at 6,000 bpd L-2: Water Injection without propped fracture in 275 acre flooded area at 6,000 bpd L-3: Water Injection with propped fracture in 275 acre flooded area at 6,000 bpd L-4: MI Gas Injection with propped fracture in 275 acre flooded area at 6 mmscf/day M-1: Moraine Formation Water Composition 0-1: Moraine — Typical Waterflood Recovery vs. Time 0-2: Moraine — Typical Waterflood Recovery vs. Water Injected 0-3: Moraine — Incremental Gas Injection Recovery vs. Hydrocarbon Pore Volume Injected (HCPVI) 0-4: Moraine Incremental Recovery vs. Rich Gas Injected 9 CPAI Application for Area Injection Order • March 2016 Page 3 of 49 SECTION A — INTRODUCTION Document Scope This document is an application for an Area Injection Order ("AIO") submitted to the Alaska Oil and Gas Conservation Commission ("Commission") in accordance with 20 AAC 25.460 (Area Injection Orders). The purpose of this document is to gain authorization from the Commission to inject fluids for the purpose of pressure maintenance and enhanced recovery of hydrocarbons in the Moraine Oil Pool pursuant to 20 ACC 25.402. ConocoPhillips Alaska, Inc. ("CPAI"), in its capacity as Operator of the Kuparuk River Unit ("KRU"), submits this document to the Commission. This application has been prepared in accordance with 20 ACC 25.402 (Enhanced Recovery Operations) and 20 ACC 25.460 (Area Injection Orders). CPAI is concurrently, under separate cover, seeking a Conservation Order by the Commission regarding the classification and rules to govern the development of the proposed Moraine Oil Pool. Introduction The Moraine Oil Pool consists of a turbidite fan system deposited in the northwest portion of the KRU and beyond to the north and west. It is comprised of thinly bedded, laminated sandstones, siltstones, and mudstones. The Moraine Oil Pool lies between -4,940 ft. true vertical depth sub -sea ("TVDSS") and - 6,190 ft. TVDSS within the KRU. Development of the Moraine Oil Pool will be completed in discrete phases to mitigate risk 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. Current plans are to initially develop the field with 4-5 hydraulically fractured horizontal producers and 3-4 hydraulically fractured horizontal injectors. CPAI Application for Area Injectarder March 2016 Page 4 of 49 SECTION B — PLOT OF PROJECT AREA 20 AAC 25.402(c)(1) 20 AAC 25.402(c)(1) - An application for injection must include a plat showing the location of each proposed injection well, abandoned or other unused well, production well, dry hole, and other well within one -quarter mile of each proposed injection well Figure B-1 shows all existing injection wells, production wells, abandoned wells, dry holes, and any other wells within the requested Moraine Oil Pool as of December 315t, 2015. 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 Application for Area Injection Order March 2016 Page 5 of 49 SECTION C — OPERATOR & SURFACE OWNERS 20 AAC 25.402(c)(2) 20 AAC 25.402(c)(2) - An application for injection must include a list of all operators and surface owners within a one -quarter mile radius of each proposed injection well. CPAI is the designated operator of the KRU, which includes the 3S drill site from which initial Moraine wells will be drilled. The surface owners and operators within one -quarter mile radius of the proposed injection area are listed below. Surface Owners State of Alaska Department of Natural Resources Division of Oil and Gas Attention: Ms. Cord Feige, Director 550 West Seventh Avenue, Suite 1100 Anchorage, AK 99501-3557 AKFF 014589 AKFF 085282 AKFF 085283 AKFF 085536 AKFF 085603 Bureau of Indian Affairs 3601 C Street, Suite 1258 Anchorage, AK 99503 ADL 414829 ADL 417951 ADL 417963 North Slope Borough PO Box 69 Barrow, AK 99723 Operators Eni Petroleum US LLC 1200 Smith, Suite 1700 Houston, TX 77002 70&148, LLC 1421 Blake Street Denver, CO 80202 Caelus Natural Resources Alaska, LLC 3700 Centerpoint Dr. Ste. 500 Anchorage, AK 99503 ASRC Exploration LLC 3900 C. St. Ste. 801 Anchorage, AK 99503 Brooks Range Petroleum Corporation 510 L Street, Suite 601 Anchorage, AK 99501 - CPAI Application for Area Injectrder March 2016 Page 6 of 49 SECTION D — AFFIDAVIT 20 AAC 25.402(c)(3) 20 AAC 25.402(c)(3) - An application for injection must include an affidavit showing that the operators and surface owners within a one -quarter mile radius have been provided a copy of the application for injection. Exhibit D-1 is an affidavit showing that the operators and surface owners within a one -quarter mile radius of the proposed injection area have been provided a copy of this application. CPAI Application for Area Injection Order March 2016 Page 7 of 49 SECTION E — DESCRIPTION OF PROPOSED OPERATION 20 AAC 25.402(c)(4) 20 AAC 25.402(c)(4) - An application for injection must include a full description of the particular operation for which approval is requested. The Moraine Oil Pool will be developed initially from the existing KRU drill site 3S, which is connected to the KRU Central Processing Facilities-3 ("CPF-3"), with 4-5 hydraulically fractured horizontal producers and 3-4 hydraulically fractured horizontal injectors. Upon successful development of the Moraine Oil Pool from initial drill site 3S wells, additional development from 3S as well as additional development from 1-2 new drill sites may occur. 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. Due to the highly laminated nature of the reservoir, all the wells (including the injectors) within the development will likely be hydraulically fracture stimulated to enhance productivity and improve vertical injection sweep. 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. 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 could be followed later with either lean gas or miscible gas injection to further improve recovery. Production and injection will be managed to maintain reservoir pressure near the original measured pressure. Injection water will consist of either produced water or seawater. Injection gas will be sourced from the KRU processing facilities. Although the future availability of gas for injection purposes cannot be predicted, some form of Immiscible Water Alternating Gas ("IWAG") flood, Miscible Water Alternating Gas ("MWAG") or rich gas flood will occur on one or more injection patterns to enhance recovery from the reservoir. CPAI Application for Area Injectorder March 2016 Page 8 of 49 SECTION F — POOL DESCRIPTION 20 AAC 25.402(c)(5) 20 AAC 25.402(c)(5) - An application for injection must include the names, descriptions, and depths of the pools to be affected. Location As shown on Figure F-1, the affected area proposed for the Moraine Area Injection Order is the entire Moraine Oil Pool, as proposed, which is within the following land: Umiat Meridian T11N, R8E Sections 1-12 all T12N, R7E Sections 1-2 all, 11-14 all, 23-26 all, 35-36 all T12N, R8E Sections 1-36 all T13N, R8E Sections 1-3 all, 10-15 all, 19-36 all T13N, R9E Section 6 Pool Definition Injection of fluids for enhanced recovery is proposed for the correlative interval shown in Figure F-2, known as the Moraine Oil Pool (occasionally referred to as Moraine Reservoir). Within the requested areal extent, 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 ft. and 6,043 ft. (-5,144 ft. and -5,486 ft. TVDSS respectively) in the Palm No. 1 well (Figure F-3). Using well data, the 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 Oil Pool. The 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 F-2). Lower Confining Interval Below the Moraine Oil Pool is the HRZ shale. The HRZ ranges from approximately 100 ft. to 150 ft. thick in the proposed area of development, consisting of marine mudstones. Recommended Pool The top Moraine down to the top of the HRZ is one progradational package of turbidite deposits identified by seismic and well data. Using well data, the above defined Moraine Oil Pool is divided into two major Members: the younger, Upper Moraine Member and the older, Lower Moraine Member. Using seismic data, it is not possible to differentiate these internal member divisions. Total pool thickness can vary from 60 ft. to 640 ft. of sandstones, siltstones, and mudstones. The deposits are dominated by marine slope to basin floor turbidites. Sand content increases up section with the Upper Moraine Member consisting of more sandstone than the Lower Moraine Member. 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 ranges from approximately 300 ft. to 1,000+ ft. thick, consisting of claystones and tuffaceous mudstones. 0 0 CPAI Application for Area Injection Order March 2016 Page 9 of 49 SECTION G — FORMATION GEOLOGY 20 AAC 25.402(c)(6) 20 AAC 25.402(c)(6) - An application for injection must include the name, description, depth, and thickness of the formation into which fluids are to be injected, and appropriate geological data on the injection zone and confining zone, including lithologic descriptions and geologic names. Stratigraphy 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. Within the proposed development area, the total Moraine Oil Pool thickness varies from 60 to 640 ft. (Figure G-1). Individually, the Upper Moraine Member ranges from approximately 10 to 315 ft. thick (Figure G-2), and the Lower Moraine Member is approximately 50 to 325 ft. thick (Figure G-3). 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, 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 and is poorly developed at the paleoslope-basin interface to the west (Figures G-4 and G-5). Sedimentology Individual 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. Reservoir porosity values from core data range from 15-28% with an arithmetic mean of 19% while air permeability values from core data range from 0.5-93 mD with an arithmetic mean of 5 mD. The mudstones are dominated by day minerals, mainly illite with minor amounts of smectite, 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 values from core data for reservoir sandstones and siltstones range from 30% to 85%. Structure and Trap The Upper Moraine Member ranges in depth between -4,940 ft. and -5,880 ft. TVDSS. Likewise, the Lower Moraine Member ranges in depth between -5,240 ft. and -5,920 ft. TVDSS (Figures G-6 and G-7). Both Members generally dip to the southeast but are flexed over the Colville High. 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 (refer to Figure F-2). Defining Net Pay The thin -bedded deposits within the Moraine Oil Pool are often below the vertical resolution of standard well logging tools. The thin bed effect on well log data 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 Area Injection Or March 2016 Page 10 of 49 SECTION H — LOGS OF INJECTION WELLS 20 AAC 25.402(c)(7) 20 AAC 25.402(c)(7) - An application for injection must include the logs of the injection wells if not already on rile with the commission. To date, no injection wells have been drilled. Well 3S-613 is planned as an injection well in the Moraine Oil Pool with spud estimated for April 2016. The logs associated with the drilling and completion of this wellbore will be filed with the Commission once available and as required. CPAI Application for Area Injection Order March 2016 Page 11 of 49 SECTION I — MECHANICAL INTEGRITY OF INJECTION WELLS 20 AAC 25.402(c)(8) 20 AAC 25.402(c)(8) - An application for injection must include a description of the proposed method for demonstrating mechanical integrity of the casing and tubing under 20 AAC 25.412 and for demonstrating that no fluids will move behind casing beyond the approved injection zone, and a description of (A) the casing of the injection wells if the wells are existing; or (B) the proposed casing program, if the injection wells are new. The well designs for the Moraine Oil Pool wells (Figure 1-1) are similar to the Kuparuk Oil Pool with surface casing to be set below the West Sak interval and cemented to surface. Within the planned development area, the base of permafrost is interpreted to be between -500 ft. and -1,700 ft. TVDSS. Intermediate 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 little evidence of thick sandstones. Any significant hydrocarbon bearing zones in the borehole above the Moraine Reservoir will be isolated in accordance with Commission regulations. 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). The Moraine Oil Pool will likely be developed 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. Due to the relatively low permeability and limited vertical connectivity of this layered system, all producers and injectors will likely require fracture stimulation. Both injection and production wells will likely be completed with 4-1/2 inch tubing to facilitate hydraulic stimulation. Based on the well performance, tubing size is subject to change. In lieu of the packer depth requirement under 20 AAC 25.412(b) specifying packer depth within 200 ft. measured depth from above the top of the perforations, CPAI requests 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. Since the Moraine Oil Pool well injectors are planned as horizontal wells, stimulation optimization efforts and well work feasibility may be impeded if the packedisolation equipment depth is required to be within 200 ft. measured depth from above the top of the perforations/open interval. The tubing/casing annulus pressure of each injection well will be tested in accordance with 20 ACC 25.412(c). Drilling and completion operations will be performed in accordance with 20 AAC 25. In accordance with 20 AAC 25.412(d), cement quality logs, or other data approved by the Commission, will be provided for all injection wells to demonstrate isolation of the injected fluids to the approved interval. All Moraine Oil Pool injection wells will: • Be cased and cemented above the reservoir interval to prevent leakage and contamination into oil, gas, or freshwater sources • Be equipped with tubing and a packer or with other equipment that isolates pressure to the injection interval, unless the Commission approves the use of alternate means to ensure that injection of fluid is limited to the injection zone • Be pressure -tested to demonstrate the mechanical integrity of the tubing and packer (or with other equipment that isolates pressure to the injection interval) and of the casing immediately surrounding the injection tubing string • Have a cement quality log or other well data approved by the Commission to demonstrate isolation of the injected fluids to the approved interval GPAI Application for Area Injectionr • March 2016 Page 12 of 49 SECTION J — INJECTION FLUIDS 20 AAC 25.402(c)(9) 20 AAC 25.402(c)(9) - An application for injection must include a statement of the type of fluid to be injected, the fluid's composition, the fluid's source, the estimated maximum amounts to be injected daily, and the fluid's compatibility with the injection zone. Waterflooding will be implemented as the initial enhanced recovery mechanism for the proposed Moraine Oil Pool with the use of either produced water or seawater. Additionally, waterflooding may be followed later with either lean gas or miscible gas injection to further improve recovery. Other fluids may also be injected for: reservoir stimulation, reservoir performance evaluation, freeze protection, or chemical inhibition; however, these fluids are not planned for continuous injection as a means for enhanced recovery. The volumes of these other fluids are expected to be less than 0.1 % of the total volume injected and are not expected to hinder the recovery efficiency of the proposed Moraine Oil Pool. Types and sources of fluids requested for injection are (compositions included for fluids that may be dedicated injection fluids): • Source water from the Kuparuk seawater treatment plant (composition listed in Figure J-1) • 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 (composition of CPF-3 produced water listed in Figure J-2) • Enriched hydrocarbon gas (MI): Blend of KRU lean gas with indigenous and/or imported natural gas liquids (composition listed in Figure J-3) • Lean gas (composition listed in Figure J-3) • 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.) Fluid Compatibility Although the Moraine Reservoir has a high clay content, the majority of the day occurs in laminar sheets between the reservoir sandstone beds where fluids for FOR will be injected. Dispersed clay in the sandstone layers is not prone to swelling when in contact with typical injection water salinities expected to be used in the Moraine Oil Pool. Analyses of formation water samples collected from the Moraine producers 3S-19 and 3S-620 indicate the potential for moderate scaling during production and when the formation water mixes with seawater. The specific scale risks are listed below. • CPF-3 Produced Water Injection o BaSO4 and CaCO3 o Scale risks are minimized as the injection water going deeper into formation • CPF-3 Seawater Injection o BaSO4 risk is high from wellbore throughout the mixing zone o CaCO3 risk is minor in reservoir beyond the near wellbore area Scaling mitigation measures include placement of aqueous and solid phase scale inhibitors in fracture treatments, conventional squeeze treatments, and chemical injection in the wells and at the surface. The analyses of the formation water samples listed above indicate that the scale risk is expected to be controlled utilizing these measures. Field injectivity data from analogous fine-grained turbidite reservoirs (Tam in the CPA[ Application for Area Injection• r March 2016 Page 13 of 49 Kuparuk River Field and Nanuq in the Colville River Field) suggest limited permeability degradation will occur with properly treated injection fluids. No compatibility issues between KRU injection gas and Moraine Reservoir fluids have been identified. Fluids used for hydraulic stimulation are planned to include a mixture of water (freshwater, seawater, or produced water), gelling agents added to make the fluid thicker and slicker, and larger grain ceramic sand to improve and sustain conductivity within the fracture through the life of the well. Hydraulic stimulation operations will be performed in accordance with 20 AAC 25.283. Hydraulic stimulation formulations may be adjusted as new technologies emerge and as the reservoir characterization is further defined. Injection Volumes Estimated maximum injection rate for each injector is estimated at 6,000 barrels of water per day and 6 million standard cubic feet of gas per day; however, injection rates will be confined by injection pressures as to not exceed the overburden pressure gradient and cause fractures to penetrate through the confinement layer. OPAI Application for Area Injectionr • March 2016 Page 14 of 49 SECTION K — INJECTION PRESSURES 20 AAC 25.402(c)(10) 20 AAC 25.402(c)(10) - An application for injection must include the estimated average and maximum injection pressure. CPAI proposes to develop the Moraine Oil Pool using IWAG flood, with the option to convert to an MWAG or rich gas flood to enhance recovery from the reservoir. Injection rates will be managed to replace offset production voidage and will be controlled by surface chokes. The overburden pressure gradient, based on the Moraine 1 core data, is 0.72 psi/ft. To ensure containment of injected fluids within the Moraine Oil Pool, injection pressures will be managed as to not exceed the maximum injection gradient of 0.67 psifft. Average injection pressures will follow the fracture closure pressure gradient at sand face of 0.62 psi/ft. Figure K-1 lists the estimated wellhead pressures and bottom -hole pressures. 0 CPAI Application for Area Injection Oder • March 2016 Page 15 of 49 SECTION L — FRACTURE INFORMATION 20 AAC 25.402(c)(11) 20 AA 25.402(c)(11) - An application for injection must include evidence to support a commission finding that each proposed injection well will not initiate or propagate fractures through the confining zones that might enable the injection fluid or formation fluid to enter freshwater strata. An internal containment assurance analysis, conducted by CPA[, indicates that the estimated maximum injection pressures for the Moraine wells (listed in Section K) in IWAG or MWAG service will not initiate or propagate fractures through the confining strata and therefore, will not allow injection or formation fluid to enter any freshwater strata. The internal containment assurance analysis involved the use of a frac model built based on Moraine 1 well log data and calibrated by using data from core sample geo-mechanical tests and pressure history matched data from the 3S-620 frac results. The simulations of the hydraulic fracturing stages and long-term water injection cases were run and indicate that fracture growth is contained within the Moraine Oil Pool without risk of breaking through overburden or under -burden containment zones. The frac modelling software used was version 8.2.5 of Grid Oriented Hydraulic Fracture Extension Replicator (GOHFER), due to its reliability and common use within ConocoPhillips as well as in the fracturing industry. GOHFER is a planar 3-D geometry fracture simulator developed by Barree & Associates in association with Stim-lab and is commercially available throughout the industry for performing hydraulic fracture simulation work. To study how fractures are initiated during injection in the Moraine Reservoir and whether they can be effectively contained within the target interval, the following cases were simulated for a horizontal well: 1) Water Injection without propped fracture in 1377 acre flooded area at 6,000 bpd (Figure L-1) 2) Water Injection without propped fracture in 275 acre flooded area at 6,000 bpd (Figure L-2) 3) Water Injection with propped fracture in 275 acre flooded area at 6,000 bpd (Figure L-3) 4) MI Gas Injection with propped fracture in 275 acre flooded area at 6 mmscf/day (Figure L-4) The above simulations indicate that injection induced fractures will be contained within the Moraine Reservoir; no breakthrough of the overburden or under -burden containment zones will occur. CPAI Application for Area Injectionr March 2016 Page 16 of 49 SECTION M — FORMATION WATER QUALITY 20 AAC 25.402(c)(12) 20 AAC 25.402(c)(12) - An application for injection must include a standard laboratory water analysis, or the results of another method acceptable to the commission, to determine the quality of the water within the formation into which fluid injection is proposed. Laboratory analysis of the Moraine Reservoir water sample collected from the core acquisition well Moraine 1 measured total dissolved solids of 21,362 mg/I, which is above the 10,000 mg/I cut off for freshwater. CPAI also calculated the salinity of the Moraine Reservoir water in Moraine producers 3S-19 and 3S-620, and found a salinity range from approximately 16,000 to 20,000 mg/l NaCl. Based on this information, the Moraine Reservoir is not a source of drinking water. Composition of the Moraine Reservoir water composition is listed in Figure M-1. CPAI Application for Area Injection tr March 2016 Page 17 of 49 SECTION N —AQUIFER EXEMPTION 20 AAC 25.402(c)(13) 20 AAC 25.402(c)(13) - An application for injection must include a reference to any applicable freshwater exemption issued under 20 AAC 25.440. The EPA has adopted an aquifer exemption for the "portions of aquifers on the North Slope described by a % mile area beyond and lying directly below the Kuparuk River Unit oil and gas producing field." 40 CFR 147.102(b)(3). The Commission has adopted that exemption by reference 20 AAC 25.440(c). All of the proposed Moraine Oil Pool and the area to which the proposed AIO applies is within the KRU and within the scope of the aquifer exemption, with a special caveat for two leases discussed below. Two leases proposed for inclusion in the Moraine Oil Pool and the AIO are ADL392374 and ADL392371, depicted on Figure F-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. CPAI Application for Area Injection r March 2016 Page 18 of 49 SECTION O — HYDROCARBON RECOVERY 20 AAC 25.402(c)(14) 20 AAC 25.402(c)(14) - An application for injection must include the expected incremental increase in ultimate 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 North Slope with consistent success. The Moraine Oil Pool will employ a horizontal well line drive pattern IWAG flood, with the option to convert to an 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 sandstone 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 sandstones 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. CPA[ estimates that primary recovery will recover approximately 5% of the original oil -in -place ("OOIP") and that waterflood recovery will range from 5-25% incremental recovery OOIP, yielding a total recovery after waterflood of 10-30% (Figures 0-1 and 0-2). 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 0-3). 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 Interval. 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 0-4). Resource recovery for floods is heavily dependent on injection throughput, waterflood recovery efficiency, and gas injection recovery efficiency. CPAI Application for Area Injectiontr March 2016 Page 19 of 49 SECTION P - CONFINEMENT IN OFFSET WELLS 20 AAC 25.402(c)(15) 20 AAC 25.402(c)(15) - An application for injection must include a report on the mechanical condition of each well that has penetrated the injection zone within a one -quarter mile radius of a proposed injection well. The following wells intersect the Moraine Oil Pool within a one -quarter mile radius of proposed injection well 3S- 613: - Moraine 1 - Plugged and abandoned vertical well drilled from an ice pad located -725 ft. away from the planned 3S-613 wellbore; was plugged and abandoned in 2015 at the completion of data acquisition objectives related to coring and logging The producer that the 3S-613 injector will support, 3S-620, is located -1450 ft. from the planned 3S-613 wellbore. There are no other existing wells within one -quarter mile of the initially planned injection well. 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. GPAI Application for Area Injectionr March 2016 Page 20 of 49 SECTION Q — PROPOSED AREA INJECTION ORDER RULES The rules set forth apply to the following area referred to in this order: Umiat Meridian T11N, R8E Sections 1-12 all T12N, WE Sections 1-2 all, 11-14 all, 23-26 all, 35-36 all T12N, R8E Sections 1-36 all T13N, R8E Sections 1-3 all, 10-15 all, 19-36 all T13N, R9E Section 6 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). 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. Rule 3. Authorized Fluids for Injection for Enhanced Recovery Fluids authorized for injection are: a. Source water from the Kuparuk seawater treatment plant b. 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 c. Enriched hydrocarbon gas (MI): Blend of KRU lean gas with indigenous and/or imported natural gas liquids d. Lean gas e. Fluids used during hydraulic stimulation f. Tracer survey fluids to monitor reservoir performance (chemical, radioactive, etc.) g. Fluids used to improve near wellbore injectivity (via use of acid or similar treatment) h. Fluids used to seal wellbore intervals which negatively impact recovery efficiency (cement, resin, etc.) i. Fluids associated with freeze protection (diesel, glycol, methanol, etc.) j. 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. Rule 5. 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 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. CPAI Application for Area Injection OFder March 2016 Page 21 of 49 List of Figures/Exhibits B-1: PLOT OF THE MORAINE OIL POOL AREA AND ALL EXISTING WELLS D-1: AFFIDAVIT F-1: OUTLINE OF A1O AND POOL AREA HIGHLIGHTING LEASES OUTSIDE OF THE KUPARUK RIVER UNIT (KRU) F-2: DEFINING WELL, PALM 1, HIGHLIGHTING POOL INTERVAL WITH RESPECT TO THE UPPER AND LOWER CONFINING INTERVALS F-3: DEFINING WELL, PALM 1, HIGHLIGHTING POOL INTERVAL G-1: MORAINE OIL POOL ISOCHORE G-2: UPPER MORAINE MEMBER ISOCHORE G-3: LOWER MORAINE MEMBER ISOCHORE G-4: WEST TO EAST WELL CROSS SECTION ACROSS THE A1O G-5: NORTH TO SOUTH WELL CROSS SECTION ACROSS THE A1O G-6: UPPER MORAINE MEMBER STRUCTURE GRID G-7: LOWER MORAINE MEMBER STRUCTURE GRID 1-1: GENERIC MORAINE INJECTOR WELL DESIGN J-1: KUPARUK SEAWATER TREATMENT PLANT WATER COMPOSITION J-2: CPF-3 PRODUCED WATER COMPOSITION J-3: MORAINE GAS INJECTANT COMPOSITIONS K-1: MORAINE OIL POOL INJECTION PRESSURE SUMMARY L-1: WATER INJECTION WITHOUT PROPPED FRACTURE IN 1377 ACRE FLOODED AREA AT 6,000 BPD L-2: WATER INJECTION WITHOUT PROPPED FRACTURE IN 275 ACRE FLOODED AREA AT 6,000 BPD L-3: WATER INJECTION WITH PROPPED FRACTURE IN 275 ACRE FLOODED AREA AT 6,000 BPD L-4: MI GAS INJECTION WITH PROPPED FRACTURE IN 275 ACRE FLOODED AREA AT 6 MMSCF/DAY M-1: MORAINE FORMATION WATER COMPOSITION 0-1: MORAINE — TYPICAL WATERFLOOD RECOVERY VS. TIME 0-2: MORAINE — TYPICAL WATERFLOOD RECOVERY VS. WATER INJECTED 0-3: MORAINE — INCREMENTAL GAS INJECTION RECOVERY VS. HYDROCARBON PORE VOLUME INJECTED (HCPVI) 0-4: MORAINE INCREMENTAL RECOVERY VS. RICH GAS INJECTED CPA[ Application for Area Injection Order March 2016 Page 22 of 49 FIGURE B-1: PLOT OF THE MORAINE OIL POOL AND ALL EXISTING WELLS W W W W LL LL LL QQQNv O O S O pp O 6040000E N r� �{ a y 04000OF N ti� (�'{1 tr �Y i I mot.• . ryY— ruk Unit .ram 7-1 6020000E N J l f t1 ..%i.%' °Y. •� •fly.,,. `L S.. . .'Y"W..• �A , f f rti w; it j�- 7 ,.,y-`y �'� � � ,�.;.�iVY:�„ • pN' 'M' Y "�• .�. t u � r �.� .- r Y•�' ray 1'ar[u Riaer nit 8000000E N ; f� # ,� :. "� w v ,^{ ! w F N 4 r —^ ^r �`p y 4h _ f : ' '; "fir` sr•_ ,rl .,y:, ,� w• ; h•• ,.,,.y.. w ,w, ''�:. ,. ,y, "'+. ''y' r� . y� r ,y.. �•r •µ+ 9,. 9' K r , .,.' w- Legend Onu Boundary....... ......... _... .............. ...... �.:iv; �11; •" Lease ff-WXT.._..................__. ................. l- J -.,p. ` ">� Y" �`�� "r'• AtO rvw r•uul aua i _ MILES Wells __� - -- 5980000F N "ry^ �'�" 980000E N _...._.K�,,..__ y,'�. ,. •r z Compkxea wmer inpecla ..... P ' l PlacNr Unit i. swowa. 0'~ _ • " 'ii ..•� Jw*ed 6 ADOfIdg1180 0•i EIIOWf ............... <+ AN-1 1 ............................... Unknam O � t ... � " SUlIIenOF11 QI Rlxl Gr5 NMA � 5960000E N " -, •y+_.....:ai •w• "1„y;,. .__..,y. 960000E N LL 0 Ll CPAI Application for Area Injectiontr 0 March 2016 Page 23 of 49 EXHIBIT D-1: AFFIDAVIT STATE OF ALASKA THIRD JUDICIAL DISTRICT I, Kazeem A. Adegbola, declare and affirm as follows: 1. 1 am the Greater Kuparuk Area Development Manager for ConocoPhillips Alaska, Inc., the designated operator of the Kuparuk River Unit, and as such have responsibility for Moraine operations. 2. On 03 t 2016, 1 caused copies of the Moraine Area Injection Order application to be provided to the following surface owners and operators of all land within a quarter -mile radius of the proposed injection areas: Surface Owners: ADL 414829 ADL 417951 State of Alaska ADL 417963 Department of Natural Resources North Slope Borough 550 West 7th Avenue, Suite 1100 PO Box 69 Anchorage, AK 99501 Barrow, AK 99723 AKFF 014589 Operators: AKFF 085282 AKFF 085283 Eni Petroleum US LLC AKFF 085536 1200 Smith, Suite 1700 AKFF 085603 Houston, TX 77002 Bureau of Indian Affairs 3601 C Street, Suite 1258 70&148, LLC Anchorage, AK 99503 1421 Blake Street Denver, CO 80202 Dated: 1"" S I s 1 , 2016. Kazeem A. Ad gbola Caelus Natural Resources Alaska, LLC 3700 Centerpoint Dr. Ste. 500 Anchorage, AK 99503 ASRC Exploration LLC 3900 C. St. Ste. 801 Anchorage, AK 99503 Brooks Range Petroleum Corporation 510 L Street, Suite 601 Anchorage, AK 99501 Declared and affirmed before me this 31 day of , �ij Ct t. 1 2016. RX1111111(/r AO� -"J �t C6 :G'N Notary Public in and for Alaska NOTARY = My commission Expires: PUBLIC fir' • s��'` CPA[ Application for Area Injection Order March 2016 Page 24 of 49 FIGURE F-1: OUTLINE OF AIO AND POOL AREA HIGHLIGHTING LEASES OUTSIDE OF THE KUPARUK RIVER UNIT (KRU) 604000OF 602000OF 6000000E 596000OF KRU outline displayed here is the 11'h expansion W W W y W N N N N • 1 CPA[ Application for Area Injection Order • March 2016 Page 25 of 49 FIGURE F-2: DEFINING WELL, PALM 1, HIGHLIGHTING POOL INTERVAL WITH RESPECT TO THE UPPER AND LOWER CONFINING INTERVALS Conocokillips Well: PALM No. 1 Alaska, Inc. 1 C7HMM 10c; Resistivity Shal. 1 OHMM 100 Neutron Porosity Resistivity Med. 60 PU 0 TwSS (ft.) MD Density 1 OHMM 100 t65 G/C3 2.65 Gamma Ray t 2700 tft) Resistivity Dee Member Formation 0 GAP] 200 1 OHMM 100 3500 i 3500 A_-- V+ 4000 4000 4500 4500 5000 O iL 0 5000 5500 5,630 ft. MD o If Upper a Moraine � Lower ca Moraine 0 M 6000 6,043 ft. MD 55 H RZ CPAI Application for Area Injectiorder March 2016 Page 26 of 49 FIGURE F-3: DEFINING WELL, PALM 1, HIGHLIGHTING POOL INTERVAL ✓ ConotoPhillips Alaska, Inc. Well: PALM No.1 Resistivity Shal. Neutron Porosity 1 OHMM 100 ResistivityResisbvity Med. 60 PU 0 Gamma Rayf TV0S8 (ft) 600 MD (ft) Density Formation 1 OHMM 100 DeepMember 1.65 GIC3 2.65 0 GAR 200 1.Resistive 1 OHMM 100 5050 5550 5100 5600 1 5.630 ft. MD 5150 5650 R 5200 5700 L 0 O J d 5250 5750 C. O C. = L Ssoo _ �• 5300 O d 5850 d C = 5350 la R 5900 L 0 >` 5400 5950 4) 3 0 5450 6000 J 6050 6.643 ft MD 5500 5550 6100 �— N t t t 6150 5600 CPAI Application for Area Injection Order March 2016 Page 27 of 49 ConocoPhillips Alaska, Inc. Palm N1r) 1 R—""ty 'nr" OHMM IDO Neutron Poros� R—My Mad 60 PU 0 rvo� 100 Dens 1 0KMM 100 G;,Ray_ r') I "' R..Wty Deep , S "Api 200 1 01110M 100 5050- 55 50- 5600- Soso. 5200- 5700- 57W 5250- , jr 5400jj - - 5250- - zs- 50. Sm- 5500- 6050- 4- 5550- 6100- 6150- Top Moraine/ Top Upper Moraine! Top Pool -Base Lower Moraine/ Base Pool/ Top HRZ BNO00017 602000OF 600000OF 598000OF 596000OF KRU outline displayed here is the 11 th expansion LU W W W LL C) I Figure G-1: Moraine Oil Pool lsochore with faults, mapped interval is highlighted in yellow on the Palm 1 log for reference CPAI Application for Area Injection Order March 2016 Page 28 of 49 ConocoPhillips Alaska, Inc. 001M Kln 1 R nr.ry S-t f 1HMM 100 NauVon Pa , Y_ H at�7 MeE_ 80 PU 0 iVosa MD 1 OHM 100 D-1 Gamma Ray lM 1 ap j51 _R sl vty Deems 1 05 G'C3 2 65 0 GAPI 200 1 OHMM 100 5050 5550 5100 560 51.W w t 5200 5700 5250 S750 s 5560 5350 rr � 5900 5soo 5950 (j} 5r50 6000 6050 5500 5550 B100 �� 5150 W W W W i 0040000FN Upper Moraine Isochore - Vdoguruk Unit f70 1 «f 6020DOOF N '4 $� ` , Upper Moraine? ' _ 1 '• ! , ` �_._ L_ Isochore �! •f` .. , Cl = 10 ft. (. T • 314300 275 250 r � 225 io Q V 2U0 ; U . • '°� ' pai u'River nit rop Moralney "-,,.� •. 175 U ��' Q _7/�, r�r !' y •7 ,11'..,} rop Upper Moraine! rop Pool 600WWF N 125 150 i + 10075 �,�, 1 . • • , • • • 50 25 ~ ✓ Zti �'' 10 00 �Q q h� 2 • •• • • • • I 0 1 2 _ {� oQi •• • •• • =R/r • ' • • • • • • I MILES '5 598000OF N ' v T _° O f 1 6 r ,. Legend ............ti / Coastline ................ Plac r Unit Unit Boundary . 0 ' �l f j ' • ' Lease Boundary ........ b• • •---------- s / / J> • A10 and Pool Area L--------- Ba-Loeser Moralise / - Well Penetration Bse Hpil w E in Upper Moraine .......... Fault 5960000E N KRU outline displayed U. 8 g LL here is the 11t' 8 N 10 expansion DOF N N Figure G-2: Upper Moraine Isochore with faults, mapped interval is highlighted in yellow on the Palm 1 log for reference CPAI Application for Area Injection Order March 2016 Page 29 of 49 Conlool; hiilips Ala ka I 6040OMr- W W LL LL I N � � n rn Palm No.1 % R—lih Snai. I OMMM 1o0 Neutron PWMIIY 60 PU 0 lwss MD _R.1i0ftMW 1 ONMM 100 Dens ty Gamma Ray (C) I — (10 Reirishmty Dee 165 GiC3 265 C t,PI 200 1 OMMM 100 — 5050 S _ 5560 5/00 5600 5150 _}} Jc s2ao s700 > f 5750... ?- 5250 — 1 _ s500. s3oo 1'� z 2 r z , t r 5350 'r _ 5800 e "DO I J b0W i 6050 l t 6100 t also —+-- W W LL LL 8 S 10 o g 8 Lower Moraine j Isochore ,y 1 ,, oguru ni �° . t• • lOA c 7-611 602000OF N Lower Moraine ' Isochore a = io tt. ry • r 330 00, • °,i . • 300 275 250 Top Moraine/ Top Uppor Moraine/ Top Pool ,•' 225 !+ 200 ".. ' �s yti .-2 . '�',r _, __ -__._ .l+j� % • `. /N • obi • . • • t Rupp ruk I •E .,..._ •Uly Aliver nit %•-� 1CX gJ0 p0 • 1 2i0 p 'X 22 I i 600000Or N r' 1752. 150 ) 1po 11 �0�0 200 1 ' _ + •� I i • • l • ,•"' 10 75 OHO 2 r• ti�'ti� ti O• i 17O so "SO.................... _ 1 _._. • • • • gr '1 • •� • 0 11--�2 �'� ' • • • • 5980000E N MILES o ti01 1• • • Legend =LL• {-- Coastline Plac r Unit � R i � 0� Unit Boundary .__ ._..._..... Lease Bounds m • _.___-_-�- I Lower Moraine/ Base Base p 1RZ Pool/ a q' t j Y J = 1 r'� �, O " - -. , ' i�0 A10 and Pool Area ,,,,,,,,,,, r I Well Penetration W C - 1 In tower Moraine ......_».... Fault 5960000E N • • KRU outline displayed here is the 11 th g expansion N DOF N 0 N N Figure G-3: Lower Moraine Isochore with faults, mapped interval is highlighted in yellow on the Palm 1 log for reference 0 CPAI Application for Area Injection Order March 2016 Page 30 of 49 West to East Structural Cross Section Gamma Ray Resistivity GAN -rVDSS MD ohmm 0........180 Itt.) (ft.) 1......100 W - 5350 - - 9800 �'•.� .' `. - 5250 - •4950 - 8300 8350 -4950 5100 - -4950 - 9850 fl` * •� y4.�y. k - 5300 8400 - - - 9900 - 9950 - ,V '. i - - 5350 - 'Sono �" B450 5000 _ 5450 � _ .5000 _ 10000 8500 - -_ 5500 - • 5050 - 30050 10100 -- N ��.,� v, .f5450 5400 5050 8550 - -5050 5550 10150 „ '� - _ •530051005100 Boon -. " 10200.-. 1 mile-% • l.L •�R;. •r.--c6, • 5500 - .. 5600 ... - 10250 .. •a . _._s- •5150 8700 ... _ • 5650 .5150 - - 10300 10350 ..� .. 1 r. 0 -. ,.. 5150 - Sao - - 8750 30400- �� •5200 8800 -" 5200 - .... 5700 - -5200 - 10450 - 5200 -. - 6700 - ; 5200 -� 5650 - - - 8850 I 30500- - 6750 5700 •5250 - 8900 ( -5250 5750 - ". .._ ' -5250 5750 _ 5300 8950 _ _ _ _ _ _ 5300 _ 58fl0_-_ _ 5300 '- 10850 • ' 5300 5800 _ _ _ _ _ _ _ - 8sD0__ _ _ _ _ . 5850 iII. 10700 6895000 - - - _ _ _ _ _ 5 - .5350 9050 -5350 5350- m- 5350 .55345000 . 5900 6950 5950 9100 - 10800 -- - 9150'- 3100 5950 3400 10850- 540 5950- -5400 5150 9200 150 6000 5450 -" 706010900 ; 5450 6000 - 9250 - 10950 7100 8050 5500 — 5500 -5500 .. 11000 -- .5500 -5500 - „ _ 6100 I'll �, - 11050 - 7150 _ 5550 - 9350 5550 .. - I - 5550 - 11,00- .- 5550 7200 6150 9400 - 5500 11150 - .5600 7250 ; - .5600 8200 5800 f •5800 6200 _" 11200-- " 7300 - - 6250 _ 9450 - - - -_ -5650 •5650 6250 - i 5850 -_ 11250 5650 7350 - Sfi50 -" 8300 _ - 9500 �!! •5T00 - - •5700 6300 - •57005700 11300 -- - - 7/00 _ t5700-- 8350 _ 9550 - - 11350 .- - 7150AM ; 8400 6350 - 3S-19 Palm 1 3S-08 3G-17 ; 3A-08 A10/Poor Boundary ; t------------------I Figure G-4: West to East 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) CPAI Application for Area Injection Order March 2016 Page 31 of 49 North to South Structural Cross Section T Gamma Ray Resistivity GAPI TVDSS MD ohmm 0........180 (ft.) (ft) 1......100 5250 - lOBOb 8900- 8400 5250 -5250--10950 -5250- 8950- •5250 "8450 5300 10900a" Upper 9000 8500 530 . 530 10950- 11000-" Moraine 5300-- 9050 530 9550 5350- -11050- 1100- 9100- 8600 5350 - 5100 --5350"- 11150 11200 - .5350- -9250" - - - -5350 - 8850 510 510& 11250 - 51 9200- - 9250- . 5100-. 8700 5150 "11300- - •5150 11350 ` •5/50 - 9300 -5/50 - -8800 5500 550 11/50- A1500. ( Lower 550 9400 55 --_- -8850 - 8900 - 5550- _ 3155.9 _ . LMOrallle� 9150- BgsO 11600- FI T5550- 95005550 _ 9000 _5650505550 -5800 - _ _ _ 1• aann_ 11650- ., aan 9550.. aan 9050 ruk Unit I , N �„ b 1 mile L-- -16 L 6900 -4350- -5351 6950. 5/0 7000 7050 - 5151 - -- EM liillliilll1aW !I 5750 5750 _11950- -5756 9800 5750 -•5750 7410 •5750 12550- -5750 1515 9850 -. - 7500 _.4260 52058 5800. 3200 5B0 9900 58 56 _ -- 7550 580 12650- 580152505850 SB50 - 5900 5850- 12050- 210 5650- 9950 - -5850 _ J93 '5950 7600 .5S50 270 :12750- '5850 15350590 1215 590 _000 590 :" 590 _7650590 260595010050- "12850- 590 510 f 5950 220 .5950 010 -5950 "507750.5950 7700- 2900-0000d225 "1515950 � . -2950-00 600010150-1230 - B006000 6050 - E. Harr. Bay 1 3M-23 3W-07 3H-22 3G-17 2T-23 2T-36 Figure G-5: North to South cross section across the A10 area (outlined in dashed red), curves shown here include gamTa ray, TVDSS, measured depth (MD), deep resistivity (black curve), and shallow resistivity (gray curve) CPAI Application for Area Injection Order March 2016 Page 32 of 49 ConocoPhilllps Alaska, Inc. Palm NA 1 H env�ty Sna' 1-- 0111,4M 100 NeUVon P-11y_ R •al Men. 80 PU 0 TV o59 MD 1 OHMM 100 Dam Ga ma_.... f61 1 eoo (81 _._Rnacmty Deep 165 G'C3 265 0 GAM 200 i UHMM.- 100 5050 _ 5550 s100 5150 �� SBsO i6 = $200 5700 s25o 5750`' swa � 5850 a050 aB00 t _ 5400 59so (( — 5450 e000 ssoo eos6 .3 e1o0 r} r. a550 _. 6150 seoo W W W W ` 8 604000OFNEUpper Moraine Depth - a0000FN Surface Structure Map S wit • ,g •Ordoguruk Unita. ;• 6020000F N Top Upper Moraine t ` r' Structure i CI=20ft. `" �o r • 4940 -5000 !' 5050 i -5100 5150 •5200 5250 r vi :5300 Top Moraine/ Top Upper Moraine/ '- '`: ' 5350 -5400 - Top Paoi f -5450 6000000F N i '; 5500 -5550 r -5600 f -5650 -5700 -5750 -5800 -5850 -5900 o L z 598000OF N MILES 1 it if w 10 •_, ' ` o lktkpprulkoRlver Unit 0,. f � rho r ! ( a •n'� 1 O$ PALM 1~'1 _5100 � � • J ''?fr o f • i 0 .g240 ! b + • • u .516 Sd t a Legend • h. — - r" ' --� Coastline ----t . ., . "�`'� �'�o�\ • Umt Boundary ... Lease Boundary ,_ yr' J l%:� • - l Base Lower M«ainel I y'; A10 and Pool Area r r Base Pool Top HRz y ', Well Penetration s r. in Upper Moraine t ' Fault .. ........ .......... 5960000F N1 UJ LU KRU outline displayed U. LL LL here is the 11tn gg expansion 8 10 10 Unit OF N 0 N N Figure G-6: Top Upper Moraine with faults, marker is highlighted on Palm 1 log for reference CPAI Application for Area Injection Order March 2016 Page 33 of 49 W W W W LL I'----- ....,,......_ I ...._. 604OMFNLower Moraine Depth Surface Structure Map _. cmooai,illilps 't • Ocioguruk Unit 4 Alaska, Inc. ��• • ' Palm No.1 y --ss� •,...• _� ResaW y $hal. i OHMM 100 !Wren Po,- Re••1m Mee 60 PU 0 rvoss Mo De—ty 1 OMMM 100 Garr—Ra 101 1 eoa (fl) ResnNvly Dee 165 GIC3 285 0 GAPI 200 1 OHMM 100 5050 l 5550 5100 5eo0 �� s15o ` 5200 5700 5750 8280 SEVEN 5300 — 5650 S� 5350 - �..� S — 5000 5400 5s50 1 5450 6000 I'm 5500 5550 6100 — t 6150 56ao J21' i000F N O • 7o x,." f i • • • • • t • • 6020OMF N o tiro Lower s;!„, r : Moraine $ \ ; 0 020000E N Structure rA� L, J i _ `' CI = 20 ft. ~' o' asp .� $� • � ' 5180 • �+;`� o Ile -5250 5300 -G f -5350 • : \ 370 �0 `Wp S ' t4. •IA • _ IA 5450 -- -55°° _. �---,/�\ 1 " ^ '�?�, ��, ; x� alru 'River nit -Top Morainel Top Upper Moraine! ' ,,�" -5550 (� ' Top Pool 6000000E N / 4+ -5600 ' •5650 1. h�$d C i • �' 0000OF N ,••'r 5700 r., \(i . .5800 w f -5850 tPAI q0 ' ' -5900 -5940 - 320 • • / ♦ t�� ; 9�' • •• ' • . • • • �— Top Lower .534 rp • �i d p• Moraine 59800DOF N MILES - _- /530 �. h1 • ' ' • _ 980000F N Legend r M> SZ _Coastline ---------------- - __, • \� (Placer Unit s4g0 4P unit Bound" 0 ' h� 4I� • _-"'"•-. Lease Boundary ......._...... At0 and Pool Area --_ _--_- a __._.___--r Base Lower Moraine/ Base Pool/ Top HRZ I N' - ` _e ! .. • �j3AOy3 Well Penetration _ • In Lower Moraine ,_...._. ........ ' Fault 5960000E N $ i i • • • • • 595000OF N l U. U. KRU here outline displayed o o is the 11th expansionio Figure G-7: Top Lower Moraine with faults, marker is highlighted on Palm 1 log for reference CPAI Application for Area Injectorder March 2016 Page 34 of 49 FIGURE 1-1: GENERIC MORAINE INJECTOR WELL DESIGN 4 %7 Tubing Nipple 4 !:" Orange Peel Shoe • 0 CPAI Application for Area Injection Order March 2016 Page 35 of 49 FIGURE J-1: KUPARUK SEAWATER TREATMENT PLANT WATER COMPOSITION Sample Number: S-160203-00063 Sample Name: STP Seawater Plant Discharge Location: Area: KUPARUK Unit: STP Sample Point: STP SPD Sampled Date: 2/2/2016 3:50:00PM Matrix Id: WATER- SEA Reviewed By,. Carville, Daniele Date; 02/24/2D16 Analysis Results: Test Pararreter Result UOM BACTERIAATP ATPASE 31692 RLU D 10 N EX I C • ACETATE ACETATE <5.0 mg/I 010 NEX IC • BUTYRATE BUTYRATE <5.0 mg/I DID NEX IC • CHLORIDE CHLORIDE 18447.8 mg/I DIONEX IC • FORMATE FORMATE <5.0 mg/I DID NEX IC' PROPIONATE PROPIONATE <5.0 mg/I DION84IC' SULFATE SO4(SULFATE) 2500.0 mg/I ICP METALS' AL(ALUMINUM) AL(AWMINUM) 0.04 mgll ICP METALS • B (BORON) B(BORON) 4.65 mg/I ICP METALS' BA(BARIUM) BA (BARIUM) 9.15 mg/I ICP METALS • CA (CALCIUM) CA (CALCIUM) 42B.59 mg/I ICP METALS' CR (CHROMIUM) CR (CHROMIUM) 0.01 mg/I ICP METALS' FE(MON) FE(IRO N) 0.07 mg/I ICP METALS • K (POTASS IUM) K (POTASSIUM) 391.42 mg/I ICP METALS' LI (LITHIUM) LI (UTHIUM) 0.22 mg/I ICP METALS' MG (MAGNESIUM) MG (MAGNESIUM) 1110.38 mg/I ICP METALS' MN (MANGANESE) MN (MANGANESE) 0.009 mg/I ICP METALS • NA (S ODIUM) NA (SODIUM) 9973.70 mg/I ICP METALS • P (PHOSPHORUS) P (PHOSPHORUS) 0.03 mg/I ICP METALS' SI (SILICON) SI(SILICON) 1.43 mg/I ICP METALS' SR (STRONTIUM) 0 CPAI Application for Area Injectiarder • March 2016 Page 36 of 49 FIGURE J-1: KUPARUK SEAWATER TREATMENT PLANT WATER COMPOSITION (CONTINUED) Sample Number: S-160203.00063 Sample Name: STP S eawater Plant Dsctl arge Location: Area: KUPARUK Unit: STP Sample Point: STP SPD Sampled Date: 2/2/2016 3:50:OOPM Matrix Id: WATER- SEA Reviewed By. Carville, Daniele Date: 02/24/2016 Analysis Results Test Parameter Result UOM S R CSTRONTIUM) 8.28 mg/I ICP METALS' ZN (ZINC) ZN(ZINC) 0.02 mg/I S-2320 ALKAUN IrY' TOTAL BI CAR BO NAT E (H 00 3) 191.8 mg/1 CARBONATE (CO3) 0.0 mg/I S-2510' CONDUCTIVITY CONDUCTIVITY 53800 uS/= S-2520SALINITY ' SP GRAV S PEaFIC GRAVITY 1.0269 5-4500 PH (B)PH PH 7.12 S-450 0 S 2- (F) • S U LF1 D E BY TITR SULFIDE 1.8 mg/I ' CPAI Application for Area InjectionOrder March 2016 Page 37 of 49 FIGURE J-2: CPF-3 PRODUCED WATER COMPOSITION Sample Nuwnber. S-160203-00058 Sample Nance CPF-3 Prod Water Tan k Outlet Location: Area: KUPARUK Unit: CPF3 Sample Pant: CPF3 PWT OUT Sampled Date: 2/2/2016 2:15:00PM Matrix Id: WATER- PRODUCED Reviewed By. Dorothy Colegrove Data: 02,/08/2016 Analysis Res>Wts Test Lararneter Result UOM DIONEX IC' ACETATE ACETATE 203.7 mg/I DIONEXIC• BUTYRATE BUTYRATE <5.0 mg/I DID NEX IC' CHLORIDE CHLORIDE 24399.9 mg/I DID NE%IC* FORMATE FORMATE <5.0 mg/I DIDNDL IC • PROPIONATE PROPIONATE 14.3 mg/I 010NEX IC • SULFATE SO4ISULFATE) 245.5 mg/I ICP METALS • AL (ALUMINUM) AL(AUJMINUM) 0.06 mg/I ICP METALS • B (BORON) 8(BORON) 17.44 mg/I ICP METALS • BA (BARIU M) BA (BARIUM) 31.03 mg/I ICP METALS' CA (CALCIUM) CA (CALCIUM) 129.29 mg/I ICP METALS • CR (CHROMIUM) CR (CHROMIUM) 0.02 mg/I ICP METALS • FE (IRON) FE(IRON) 0.29 m5/1 ICP METALS • K (POTASSIUM) K (POTASSIUM) 89.79 mg/I ICP METALS • LI (LITHIUM) LI (LITHIUM) 1.12 mg/I ICP METALS • MG (MAGNESIUM) MG (MAGNESIUM) 187.21 mg/I ICP METALS • MN (MANGANESE) MN (MANGANESE) 0.032 mg/I ICP METALS • NA (SODIUM) NA(SODIUM) 9079.32 mg/I ICP METALS • P (PHOSPHORUS) P (PHOSPHORUS) 0.60 mg/I ICP METALS • SI (SILICON) SI(SILICON) 16.69 mg(I ICP METALS' SR (STRONTIUM) SR(STRONTIUM) 8.19 mg/I ICP METALS • ZN (ZINC) CPAI Application for Area InjectiallrOrder March 2016 Page 38 of 49 FIGURE J-2: CPF-3 PRODUCED WATER COMPOSITION (CONTINUED) Sample Number: S-1602D34M8 Sample Name: CPF-3 Prod Water Tank Outlet Location: Area: KUPARUK Unit: CPF3 Sampled Date: 2/2/2016 2:15:00PM Matrix Id: WATER- PRODUCED Reviewed By- Dorothy Colegrove Date:O2/08/2016 Analvsis Results: Test N rarneter ZN (ZINC) 5-2320 ALKAUN fry' TOTAL 81CAR BO NATE (HC0 3) CARBONATE (CO3) 5-2510' CONDUCTIVITY CO NDUMVITY 5-2520 SALINITY' SP GRAY SPECIFIC GRAVITY 5-4500 PH (B)' PH PH 5-4500 S2- (F)' SULFIDE BY TITR S ULFIDE Sample Poi nt: CPF3 PWT OUT Result U0M 0.08 mg/I 1559.2 mg/I 0.0 mg/I 43600 uS/an 1.019E 7.91 18.3 mg/I CPAI Application for Area Injection Order March 2016 Page 39 of 49 FIGURE J-3: MORAINE GAS INJECTANT COMPOSITIONS (MOLE %) t,01 CO2 0.40 1.26 1.05 N2 0.01 0.34 0.26 C1 7.57 83.21 66.56 C2 7.14 7.31 7.45 C3 15.67 4.08 6.88 iC4 9.08 1.01 2.93 nG4 25.45 2.05 7.62 iC5 10.40 0.24 2.61 nC5 5.60 0.29 1.03 C6 9.69 0.11 2.51 C7 4.92 0.06 1.30 C8+ 4.08 0.05 1.12 2015 data averages CP1 and CPF2 together Notes 1) Initial gas injectant is planned to be Kuparuk MI 2) Potential leaner gas injectant blends are possible based on changes in Kuparuk 1D and 1E WAG Injection and future NGL imports from Prudhoe. CPAI Application for Area Injector rder March 2016 Page 40 of 49 FIGURE K-1: MORAINE OIL POOL INJECTION PRESSURE SUMMARY I njection 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 X AVERAGE INJECTION GRADIENT: X MAXIMUM INJECTION GRADIENT: X OVERBURDEN PRESSURE GRADIENT X CPF-3 FLUID GRADIENT (WATER): X GAS GRADIENT (MI): 0.62 PSI/FT 0.67 PSI/FT 0.72 PSI/FT 0.442 PSI/FT 0.15 PSI/FT CALCULATION X BHP = DEPTH (FT) X INJ. GRADIENT (PSI/FT) X HYDROSTATIC PRESSURE = DEPTH (FT) X FLUID GRADIENT X WHP = BHP — HYDROSTATIC PRESSURE CPAI Application for Area Injection Order March 2016 Page 41 of 49 FIGURE L-1: WATER INJECTION WITHOUT PROPPED FRACTURE IN 1377 ACRE FLOODED AREA AT 6,000 BPD Top Upper Moraine/Top Pool — - - ..-Top . � Net Pressure (psi) 5100.00 5880 -9760 -3640 2360 8480 Base Upper Moraine/Top Lower Moraine 5124 5148. 5172. 5196. 52 4-4.i i 5268. z m r} 220.366 _% (A 349.766 N 479.166 A 610.183 739.583 5316.00 14600 0 CPAI Application for Area Injection Order March 2016 Page 42 of 49 FIGURE L-2: WATER INJECTION WITHOUT PROPPED FRACTURE IN 275 ACRE FLOODED AREA AT 6,000 BPD Top Upper Moraine/Top Pool — - Net Pressure (psi) 5100.00 0 0 0 0 0 5124.0 -56T008 • 5148.00 .•:':' 5172.00 �_;•;•; 89.3 . . :- •• (D 5196.00 r'F' 220.366 fD 5220.00 N i 349.7 i�;�;�;�;�li✓ 5244.00 rlv 479.166 5268.00 P/v 610.183 .. . •5242.00 739.583 5_16.iin •. �� -2376 -792 792 2352 3936 5520 868.983 Base Upper Moraine/Top Lower Morainemm �J • CPAI Application for Area Injection Order March 2016 Page 43 of 49 FIGURE L-3: WATER INJECTION WITH PROPPED FRACTURE IN 275 ACRE FLOODED AREA AT 6,000 BPD Top Upper Moraine/Top Pool 1 Proppant Concentration (Ib/ft2) -2360 -800 Base Upper Moraine/Top Lower Moraine 5100.001 0.00 5124.00 5148.00 5172.00 96) 5196.00 A 5220.00 3.99502 -% 5244.n i O 4.79203 5268.0n Cr 5. 6.396 5316.0 5480 • 9 CPA] Application for Area Injection Order March 2016 Page 45 of 49 FIGURE M-1: MORAINE OIL POOL FORMATION WATER COMPOSITION Cations Test Method (myA) MW Valence PAW Banum Be +2 ICP 44 137.34 2.0 0.64 Calcium Ca +2 ICP 165 40.08 2.0 8.28 Copper Cu +2 ICP <0.009 63.55 2.0 0.00 Iron dissolved Fe +2 ICP <0-01 55.85 2.0 0.00 Iron lotat Fe +2 ICP 0.38 55.85 2.0 0,01 Lead Pb +2 ICP <2.2 207,20 20 000 Magnesium Mg +2 ICP 40 24.31 20 3,29 Manganese Mn +2 ICP 0.19 5494 2.0 0.01 Nickel M +2 ICP 1.5 58.69 2.0 0.05 Potassium K+ ICP 415 39A0 1.0 10.57 Silicon Si +4 ICP 17 28.09 4.0 2.42 Sodium Ne + ICP 7,320 22,99 1.0 318.27 Strontium Sr +2 ICP 12 87.62 2.0 027 Vanadium V +2 ICP <0.01 50,94 2,0 0.00 Zinc Zn +2 ICP 0.13 65.39 2.0 000 Anions Test Method (myf) MW Valence woo Akalin as Bicarbonate HCO3 - Tdrabon 3,990 61.02 1 A 65.41 Borate OH - ICP 20 78.84 1.0 0.25 Bromide Br - Tdrabon / IC 84 79,90 1.0 1.05 Carbonate CO3 -2 Titration 1 00 6001 20 000 Chloride CI - Tdrabon ! IC 9,210 35A5 1.0 259,84 Iodide i - Tdrabon / IC 38 126.90 1.0 0.30 Sulfate SO4 -2 IC 4.4 96.06 2.0 0.09 Sulfide IS-2 IC 0.0 32.06 2.0 0.00 Total Cation M s 344 Total Anion Me<s 327 TDS l) 21,362 TDS ) 21,073 Ion Balance 0.025 Resi Ohm -Meter) 0 77 °F 0-34 Conductivity, microSie wWcm 29.800 iriC 60160 -F 1.0147 Stability Index 100 T -0.47 Stability Index tD 200 T 142 °a Dewabon in Meg. Bal. 2.52 °o Deviation an TDS 0.54 QA/QC Run ID's ICP 5012015 IC - Anions 5012015 IC CiManic Acids WA Tdradions - Bicarbonate and Chloride 5012015 CPAI Application for Area Injection Order March 2016 Page 46 of 49 FIGURE 0-1 : MORAINE —TYPICAL WATERFLOOD RECOVERY VS. TIME Typical Waterflood Recovery Efficiency (Moraine) a� 0.35 a 0.3 a 0.25 O O 0.2 o r_ 0.15 o v 0.1 °o = 0.05 L 0 0 10 20 Year 30 • L CPAI Application for Area Injection Order March 2016 Page 47 of 49 FIGURE 0-2: MORAINE — TYPICAL WATERFLOOD RECOVERY VS. WATER INJECTED Typcial Waterflood Recovery Efficiency (Moraine) 0.35 c 0.3 = a 0.25 O �- O 0.2 0 c 0.15 0.1 o 4- y 0.05 0 �a 0.50 1.00 1.50 2.00 2.50 3.00 HCPV Water Injected (fraction) • • 9 CPA] Application for Area Injection Order March 2016 Page 48 of 49 FIGURE 0-3: MORAINE — INCREMENTAL GAS INJECTION RECOVERY VS HYDROCARBON 0.12 .r a� 0.10 c CA 0 0.08 O O 4- 2:- c 0.06 a > o. c o ( W' 0.04 � T c 0.02 a� a 0.00 c PORE VOLUME INJECTED (HCPVI) 0.00 0.50 1.00 1.50 2.00 2.50 3.00 HCPV Total: water+gas (fraction) —IWAG 25% MGI - 50% MGI gwmmw - 7 5% M G 1 0 CPAI Application for Area Injection Order March 2016 Page 49 of 49 FIGURE 0-4: MORAINE INCREMENTAL RECOVERY VS RICH GAS INJECTED Incremental Recovery vs. Enriching Fluid Injected 0.12 0.1 KIM M 0.02 0 1.00E+13 5.10E+14 Cumulative Rich Gas C4+ Injected (moles) 1.01E+15 L • • • 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), CPA[ 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 KownLEWSKI I Petroleum Engineer (Moraine) CoP Alaska Business Unit I CPF2 — A, B, & C CPF3 — Moraine 700 G Street, Anchorage, AK 995011 ATO-1356 Office/Cell 1 +1.907.265.1363/ +1.907.231.0369 kasper.kowalewski@cop.com • 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 [mailto: Kasper. Kowalewski@conocophillips.com] Sent: Wednesday, April 27, 2016 8:21 AM To: Wallace, Chris D (DOA) Cc: Umlauf, 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, 1" sentence AlO Application — page 9 of 49, paragraph 3, 5th sentence Kindest Regards, KASPER KoWALEWSKI I Petroleum Engineer (Moraine) CoP Alaska Business Unit I CPF2 — A, B, & C CPF3 -- Moraine 700 G Street, Anchorage, AK 995011 ATO-1356 Office/Cell 1 + 1.907.265.1363/ +1.907.231.0369 kasper.kowalewski@cop.com ■ Complete items 1, 2, and 3. Also 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 mailpiece, or on the front if space permits. 1. Article Addressed to: -Rob Kinnear BP Exploration Alaska1m. 900 E. Benson Bouloord Anchorage, AK 99508 A. Signature ,, ,L . ❑Agent X 1- ., 4 ❑ Addrem B. Rr by"n erne) II C. Date of Delive D. Is delivery address different from item 1? 0 Yes ff YES, enter delivery address below: ❑ No 3. Service Type Ioertifiecl Mai* ❑ Priprity Mail Express'" ❑ Registered ❑ Return Receipt for Merchandi; ❑ Insured Mail ❑ Collect on Delivery 4. Restricted Delivery? {Extra Fee) ❑ Yes 2. Article Number 7 014 015 0 0000 6333 7422 (Transfer from service label) PS Form 3811. July 2013 Domestic Return Receipt i_ ■ Complete items 1, 2, and 3. Also complete Item 4 if Restricted Delivery is desired. 8 Print your name and address on the reverse 91 Su'�Y �r11��(�� l X� 1, C Q0 Agent Addre g q by tinted Nam) 2 A fG� C ate f I so that we can return the card to you. 0 Attach this card to the back of the mailpiece, or on the front if space permits. D..Isfiellvery address different from item 1? If VIES, enter delivery address below: ❑Yes ❑ No 1. Article Addressed to: G. C. Fredrick Chevron U.S.A. Inc. 310 K Street, Suite 406 Anchorage, AK 99501 i S. Service Type Al Certified Mal* ❑ Priority Mail ExpresC [3-Registered ❑ Return. Receipt for Merchandl: ❑ insured Mail ❑ Collect on Delivery 4. Restricted Delivery? (Extra Fee) ❑ Yes 2. Article (1Fansfer frfrom omservice /abeq - 7014 0150 0000 6333 7439 PS Form 3811, July 2013 Domestic Return Receipt I ■ Complete items 1, 2, and 3. Also complete Item 4 if Restricted Delivery is desired. to Print your name and address on the reverse so that we can return the card to you. 8 Attach this card to the back of the mallplece or on the front if space permits. 1. Article Addressed to: Gilbert Wong E>xxonMobil Alaska Prod uc#aWlnc. 3301 C Street, Suite 400 Anchorage, AK 99519 i A Sig re X'00 "eceived by (P Name) D. Is delivery rffererri If YES, enter. g8 ry adA 013 Agent ❑ Addrem ? ❑ Yes ❑ No 3. Service Type 20 Certified Mai* ❑ Priority Mall Express- ❑ Registered etum Receipt for Merchandis ❑ insured Mail ❑ Collect on Delivery 4. Restricted Delivery?? (6dra Fee) ❑ Yes 2. Articlf""mber marmirvinservkOmw 7014 0150 0000 6333 7415 PS Form 3811, July 2013 Domestic Return Receipt ■ Complete items 1, 2, and 3. Also complete item 4 If Restricted Delivery is desired. III Print your name and address on the reverse so that we can return the card to you. 9 Attach this cans to the back of the mailpiece, or on the front If space permits. 1. Article Addressed to: State of Alaska Department of Natural Resources 550 West 7th Avenue, Suite 1100 Anchorage, AK 99501 B. Recqved by Anted ame)17 D e of Delive t n 12. - D. Is delivery address different from item 1? Yes If YES, enter delivery address below: lr No 3. Service Type ALCerGfied Mai" ❑ Priority Mali Express' ❑ Registered E3 Return Receipt for Merchandli ❑ insured Mall. ❑ Collect on Delivery 4. Restricted Delivery? (Extra Fee) ❑ Yes 2. Article Number 7014 0150 0000 6333 7392 (Transfer from service taboo Ps Form 3811, July 2013 Domestic Return Receipt i ■ Complete items 1, 2, and 3. Also 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. r Attach this card to the back of the mailpieoe, or on the front If space permits. 1. Article Addressed to: Bureau of Indian Affairs 3601'C.Street, Suite 12-58 Anchorage, AK 99503 A Signature X Agent z.-- ❑ Address( ecetved b (Print9cr ) C. Date of ReliD. Is slivery address from item 1? es If YES; enter delivery address below: ❑ No 3. Service Type. I,Certftd Mall' ❑ Priority Mall Express'" ❑ Registered ❑ Return Receipt for Merchandl; ❑ Insured Malt ❑ Coiled on Delivery 4. Restricted Delivery? (Extra Fee) 0 Yes 2. Article Number (Aansfer from senfte /abeq 7014 0150 0000 6333 7385 Ps Form 3811, July 2013 Domestic Return Receipt ■ Complete items 1, 2, and 3. Also complete A. Signature item 4 If Restricted Delivery is desired. ❑ Agent ■ Print your name and address on the reverse X ❑ Address( so that we can return the card to you. B lied by (Printe20�d Name) C. Date of Relive 0 Attach this card to the back of the mailpiece, �� eo _�� or on the front if space permits. re _ 1. Article Addressed to: D. Is deliveryaddress differerrt from item 1? ❑ Yes If YES, enter delivery address below: ❑ No North Slope Borough PO Box 69 Barrow, AK 99723 3. Service Type WCersfied Mail° ❑ Priority Mail Express' ❑ Registered ❑ Return Receipt for Merchandl: ❑ Insured Mall ❑ Collect on Delivery 4. Restricted Delivery? extra Fee) ❑ Yes 2. Article Number 7014 0150 0000 6333 7408 (Transfer from service label) Ps Form 3811, July 2013 Domestic Return Receipt ■ Complete items 1, 2, and 3. Also complete VP I A, 11�jature Item 4 if Restricted Delivery is desired. 1 ■ 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 maiipiece, or on the front If space permits. 1. Article Addressed to: Eni. Pet-rol um- ,uS ` .,C:. _ 12DGSmitlt 5-Wte-1-70W' 'Houston, TX 77002 j i I i I D. Is delivery ad If YES, enter ❑ Agent of Delive from Urn 1? m Yes rss below: ❑ No 3. Service Type Mail° ❑ Priority Mail Express'" Registered 0 Return Receipt for Merehandk ❑ Insured Mail ❑ Collect on Delivery 4. Restricted Delivery? Pdr'e Fee) ❑ Yes 2. Article(rmm rftm, 7014 0150 . 0000 6333 7583 (Transfer from service label) PS Form 3811, July 2013 Domestic Return Receipt ■ Complete Items 1, 2, and 3. Also 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. w Attach this card to the back of the maiiplece, or on the front if space permits. 1. Article Addressed to: Caelus Natural Resources Alaska, LLC 3700 Centerpoint Dr. Ste. 500 Anchorage, AK 99503 A. ❑ Agent B. Receivekbby ( nfed Name) - C. Date of Delive D. Is delivrmss different from item 1? ❑ Yes 1f ekjr;8ddressbelow: ❑ No 0 3. Mull•':'- E3 Priority Mail Express- ❑ Registered ' Ca Return Receipt for Merchandk ❑ Insured Mai{ 13 Collect on Delivery 4. Restricted Delivery? (Extra Fee) ❑ Yes 2. Article 7014 0150 0000 6333 7613 Ps Form 3811, July 2013 Domestic Return Receipt ■ Complete Items 1, 2, and 3. Also complete Item 4 if Restricted Delivery Is desired. III Print your name and address on the reverse so that we can return the cans to you. ■ Attach this card to the back of the mailplece, or on the front If space permits. 1. Article Addressed to: _. 70&19,,NL -' C 1421 Blake Street Denver, CO 80202 A. Si natu x i ��. Wit, B. Received by (Printed Name) 10. Dgte)61 pay D. Is delivery address different from item 19 U Y& If YES, enter delivery address below: 13 No 3. Type iTI-Certifiled Marla ❑Priority Mail Express'" ❑ Registered ❑ Return Receipt for Merchandle ❑ Insured Mail ❑ Collect on Delivery 4. Restricted Delivery? (EOv Fee) ❑ Yes 2. roman ferftoom�sendbe/aW 7014 0150 0000 6333 7590 Ps Form 3811, July 2013 Domestic Return Receipt ■ Complete Items 1, 2, and 3. Also 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 mailpiece, or on the front if space permits. 1. Article Addressed to: ASK Exploration LLC 3900 C. St. Ste. 801 Anchorage, AK 99503 i I A. Signature , B. Received by (Printed Name) C. Date of Deliver 016ee'c- D. Is delivery address different from item 1? 0 Yes If YES, enter delivery address below: ❑ No 3. Service Type '7 Certified Mail® 13 Priority Mali Express'" �0 Registered ❑ Return Receipt for Merchandli ❑ Insured Mail ❑ Collect on Delivery 4. Restricted Delivery? (Extra Fee) ❑ Yes 2- Article Number 7014 0150 0000 6333 7606 (rrartsfer from service Ps Form 3811, July 2013 Domestic Return Receipt ■ Complete Items 1, 2, and 3. Also complete Item 4 if Restricted Delivery Is desired. Print your name and address on the reverse so that we can return the cans to you. r Attach this card to the back of the mailpleee, or on the front If space permits. 1. Article Addressed to: Brooks Range Petroleum Corporation 510 L Street, Suite 601 Anchorage, AK 99501 W !�� Q �tit .2._46i eName) AHDa)so/P/ `4 D. Is delivery address different from item 1? 13 1'es If YES, enter delivery address below: ❑ No 3. Liype ad Maife ❑ Priority Mail Express - Registered ❑ Return Receipt for Memhandla ❑ Insured Mail ❑ Collect on Delivery 4. Restricted Delivery? (Extra Fee) ❑ Yes 2. Article Number 7 014 0150 0000 6333 7378 manster fmm service faw PS Form 3811, July 2013 Domestic Return Receipt