Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation
Commission
HOME
EVENTS
DATA
Data List
Drilling
Production
Orders
Data Miner
Document Search
REPORTS
Reports and Charts
Pool Statistics
FORMS
LINKS
Links
Test Notification
Data Requests
Regulations
Industry Guidance Bulletins
How to Apply
ABOUT US
History
Staff
HELP
Loading...
The URL can be used to link to this page
Your browser does not support the video tag.
Home
My WebLink
About
AIO 042
AREA INJECTION ORDER 42 Docket Number: AIO-19-016 Southern Miluveach Unit 1. April 25, 2019 Brooks Range Petroleum application for Area Injection Order for Southern Miluveach Unit (Pages 27-29 and Page 31 held in confidential storage 2. May 1, 2019 Notice of hearing, affidavit of publication, email distribution, mailings 3. May 31, 2019 GOHFER frac modeling 4. June 4, 2019 Transcript, sign in sheet and presentation STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue Anchorage Alaska 99501 Re: THE APPLICATION OF Brooks Range ) Docket Number: AIO-19-016 Petroleum Corporation to gain ) Area Injection Order No. 42 authorization to inject fluids for pressure ) maintenance and enhanced recovery of ) Southern Miluveach Unit hydrocarbons in the Southern Miluveach ) Kuparuk River Oil Pool Unit, Kuparuk River Oil Pool ) North Slope Borough, Alaska June 12, 2019 IT APPEARING THAT: 1. By application dated April 25, 2019 (Application), Brooks Range Petroleum Corporation (BRPC) in its capacity of operator of the Southern Miluveach Unit (SMU) requested an Area Injection Order (AIO) authorizing injection of fluids for pressure maintenance and enhanced recovery of hydrocarbons from the Kuparuk River Oil Pool (KROP) within the SMU (the portion of the KROP within the SMU and the Affected Area of this order are referred to as the SMU-KROP). 2. Pursuant to 20 AAC 25.540, the Alaska Oil and Gas Conservation Commission (AOGCC) scheduled a public hearing for June 4, 2019. On April 30, 2019, the AOGCC published notice of that hearing on the State of Alaska's Online Public Notice website and on the AOGCC's website, electronically transmitted the notice to all persons on the AOGCC's email distribution list, and mailed printed copies of the Notice of Public Hearing to all persons on the AOGCC's mailing distribution list. On May 1, 2019, the notice was published in the ANCHORAGE DAILY NEWS. 3. No comments on the application were received. 4. BPRC submitted additional evidence in support of its Application during April and May 2019. 5. The hearing commenced at 10:00 a.m. on June 4, 2019. Testimony and other evidence were provided by BRPC. The hearing record was closed. FINDINGS: 1. Affected Area: The Affected Area lies onshore within the SMU, North Slope Borough, Alaska, about 45 miles west-southwest of Prudhoe Bay. The SMU-KROP is being developed from a gravel pad located in Section 2, Township (T) ION, Range (R) 7E, Umiat Meridian (UM). 2. Owners and Landowners: BRPC is the operator for the SMU. Working interest owners are Alaska Venture Capital Group, LLC; Brooks Range Petroleum Corporation; Caracol Petroleum LLC; Mustang Operations Center 1 LLC; Mustang Road LLC; Nabors Drilling Technologies USA, Inc.; and TP North Slope Development, LLP. The State of Alaska, Department of Natural Resources is the landowner of the Affected Area. 3. Exploration. Delineation. and Production History: During January 2012, BRPC drilled the discovery well—North Tarn lA (Permit to Drill No. 211-174)—into the Kuparuk Formation (Kuparuk) in Section 2, TI ON, R7E, UM, and encountered oil indicators. This discovery was AIO 42 June 12, 2019 Page 2 of 8 confirmed by the Mustang 1 exploratory well (Permit to Drill No. 212-174) in February 2012. To date, five wells have been logged across the Kuparuk reservoir within the SMU. Three-dimensional seismic survey and well log data have been used to determine the geologic structure and reservoir distribution for the SMU-KROP. Well log, well test, and Operator - supplied information were used to establish reservoir and fluid properties for the proposed pool. 4. Pool Identification: The KROP, defined in Conservation Order (CO) No. 432D, is the accumulation of oil that is common to and correlates with the accumulation found in the Atlantic Richfield Company West Sak River State No. 1 well between the depths of 6,474 and 6,880 feet. (Permit to Drill No. 171-003). Along with the SMU, portions of this expansive oil pool also lie within the adjoining Kuparuk River Unit (KRU) and the Milne Point Unit. 5. Geology: a. Structure: The Colville Anticline is the regional structural trap for the SMU-KROP. The SMU lies on a portion of that anticline. Within the SMU, the SMU-KROP ranges in depth from about -5,800 to -6,400 feet TVDSS.' b. Stratisrauhy: Within the SMU, Cretaceous -aged reservoir sandstones within the Kuparuk Formation are informally divided into two intervals, the Kuparuk C -Sand (C -Sand) and the underlying Kuparuk A -Sands. The Kuparuk C -Sand consists of bioturbated and burrowed glauconitic sandstones, shaley sandstones, siltstones, and shales. These sediments were most likely deposited in an offshore marine -shelf setting. The thickness of the C -Sand interval varies from 0 to 25 feet within the SMU, and this variation is believed to have been influenced by syndepositional fault activity. The regional Lower Cretaceous Unconformity separates the C -Sand from the underlying A -Sands, and it progressively truncates the A -Sand intervals from southeast to northwest across the SMU. Within the SMU, the A -Sands consist of two upward -coarsening intervals that were deposited in an offshore marine setting. Here, the A -Sands are subdivided into intervals informally named "A4" and "A3", in descending order. The thickness of A4 vanes from 0 to 36 feet from northwest to southeast across the SMU. Interval A3 vanes from 2 to 40 feet in thickness from northwest to southeast within the SMU. The thickness trends of the A -Sands do not appear to be influenced by faulting or the present-day structure. c. Rock Properties: The C -Sand comprises fine- to coarse-grained quartzose sandstone that contains up to 40 percent glauconite and is commonly cemented with secondary siderite. Porosity averages 22 percent and permeability ranges from 50 to several hundred millidarcies (md) and averages 70 md. Water saturation with the C -Sand can be as low as 20 percent. The underlying A -Sands consist of very fine- to fined -grained sandstone interbedded with siltstone and mudstone. Porosity averages 22 percent. Permeability ranges from less than 10 to 100 md, and averages 30 md. Water saturation in the A -Sands can be as high as 40 percent. ' To avoid confusion, when depths presented represent true vertical depth below sea level (subsea), the footage will be preceded by a minus sign and followed by the acronym TVDSS (e.g., 5,800 feet true vertical subsea is depicted as -5,800 feet TVDSS). AIO 42 June 12, 2019 Page 3 of 8 d. Faults: Two sets of faults cut the Colville Anticline within the SMU; one set trends north-northeast, and the other set trends west-northwest. The vertical displacement of faults cutting the proposed SMU-KROP ranges up to 85 feet, but is generally less than 30 feet. Because of the relatively thin -bedded nature of reservoir sands within the proposed pool, some faults may act as localized flow barriers and may result in reservoir compartments. e. Trap Configuration and Seals: Well log and seismic information indicate that structural dip controls the hydrocarbon accumulation within the SMU-KROP. The overlying Kalubik and HRZ Shales form the top seal for the oil accumulation within the proposed pool. 6. Reservoir Continuity: Many faults cut the KROP within the Affected Area. As mapped using 3D seismic, these faults have vertical displacements that are generally less than 30 feet. However, some compartmentalization of the pool is expected due to the thin nature of the reservoir strata, especially in the western portion of the Affected Area. 7. Reservoir Fluid Contacts: To date, no hydrocarbon contacts have been encountered in the Kuparuk reservoirs within the Affected Area. 8. Reservoir Fluid Properties: In the SMU-KROP area the initial producing gas oil ratio (GOR) is estimated to be about 600 scfstb. The API gravity of oil recovered from the proposed pool measured about 24° in the North Tarn 1 A well. Due to injection activities in the KROP within the adjoining KRU, pressure in the SMU-KROP measured as high as 3,850 psi. Bubble -point pressure is estimated to be 1,930 psi. The oil formation volume factor is estimated at 1.2 reservoir barrels per stock tank barrel of oil. 9. In -Place and Recoverable Volume Estimates: Hydrocarbon Resource Estimated Volume2 Original Oil in Place (OOIP) 70 MMSTB Primary Recovery (10-25% OOIP) 7-17.5 MMSTB Primary + Water Injection (Additional 10-25% OOIP) 7-17.5 MMSTB Incremental Primary + Water and Lean Gas Injection (Additional 1-5% 0.7-3.5 MMSTB OOIP above Primary + Water Injection) Incremental Primary + Water and Lean and Enriched Gas Injection 2.1-10.5 MMSTB (Additional 3-15% OOIP above Primary + Water Injection) Incremental These estimates are based on audited reserves and analogous developments. 10. Future Development Plans: BRPC plans to develop the pool using up to 11 horizontal production wells and 10 horizontal injection wells drilled parallel with the major faults that cut the pool. Some wells may be hydraulically fractured to enhance reserve recovery. 11. Confinine Lavers for Injection: Approximately 260 feet of Kalubik and HRZ shales overlie the SMU-KROP. Several hundred feet of shales assigned to the Miluveach and Kingak Formations underlie the SMU-KROP. 2 The acronym MMSTB signifies millions of stock tank barrels. A10 42 June 12, 2019 Page 4 of 8 12. Iniection Rates: The anticipated peak daily injection rate for individual wells within the SMU- KROP is 6,000 barrels of water per day (BWPD) and 6 million standard cubic feet of gas per day (MMSCFPD). 13. Infection Pressures: Injection pressures at the well head are estimated to be between 2,000 and 2,100 psig during water injection, and between 4,000 and 4,200 psig during gas injection. 14. Fracture Propagation and Confinement: A fracture propagation model showed that at the expected injection -pressure fractures would form in the injection interval but would be confined to the injection interval and not propagate into the confining layers. In order for fractures to propagate into the confining layers, surface pressures during water injection would have to exceed 2,700 psig. 15. Freshwater Strata: No porosity logs have been recorded across the shallow geologic section within the SMU. Accordingly, BPRC commissioned a formation water salinity determination using well logs from West Sak 25590-15, which is located about 3 miles east of the SMU development gravel pad. Well log calculations suggest that aquifers shallower than a depth of about 2,300 feet MD (-2,140 feet TVDSS) within the SMU may contain native formation waters that have total dissolved solids concentrations of less than 10,000 mg/1. However, BPRC will isolate these aquifers with cement from ground level to surface casing shoes that will be set at about -2,500 feet TVDSS. Shallow aquifers within the SMU are not considered Underground Sources of Drinking Water (USDWs) because they are situated at depths that make recovery of water for drinking purposes economically impractical, and they are situated at a location where they are not reasonably expected to supply a public water system. 16. Aquifer Exemption Order: BPRC's Application contends that the U.S. Environmental Protection Agency's (EPA) Aquifer Exemption for the Kuparuk River Field (KRF)— described in Federal Regulation 40 CFR147.102(b)(3)— applies to the Affected Area of this AIO. A map titled "Alaska Oil and Gas Aquifer Exemptions," available on the EPA's Region 10 website at https://www.eya.gov/uic/aquifer-exemptions-may, indicates the KRF Aquifer Exemption applies to only the portion of the Affected Area that lies within one-quarter mile of the external boundary of the adjoining KRU. A past conversation between AOGCC and EPA staff confirmed EPA's depiction of the KRF Aquifer Exemption boundary that is shown on its "Alaska Oil and Gas Aquifer Exemptions" map. CONCLUSIONS: 1. An Area Injection Order is appropriate to authorize the injection of fluids for enhanced oil recovery purposes in the SMU-KROP within the SMU. 2. The existing Aquifer Exemption for the KRF—as described in Federal Regulation 40 CFR147.102(b)(3)—•applies to only the portion of the Affected Area for the proposed SMU AIO that lies within one-quarter mile of the external boundary of the adjoining KRU. An Aquifer Exemption Order is not required for the remainder of the Affected Area because BRPC's enhanced recovery injection operations—as described in BRPC's Application—will not impact any shallow aquifers, and none of the shallow aquifers within the Affected Area are considered USDWs. 3. Reservoir simulation modeling shows water and water -alternating -gas injection into the SMU-KROP will provide a substantial EOR benefit over primary recovery alone, maximize ultimate recovery from the SMU-KROP, and prevent waste. AIO 42 June 12, 2019 Page 5 of 8 4. The maximum possible wellhead injection pressures of 2,200 psig during water injection is well below the pressure needed to initiate fractures in the confining intervals. As such, the confining intervals will ensure that injected fluids remain in the SMU-KROP. NOW THEREFORE IT IS ORDERED: The underground injection of fluids for pressure maintenance and enhanced recovery is authorized in the following area, subject to the following rules and 20 AAC 25, to the extent not superseded by these rules: Affected Area: TI ON, R7E, UM TI IN, R7E, UM Sections: 1, 2, 3, 4, 9, 10, 11, 12 - All Sections: 24, 25, 26, 35, 36 - All Rule 1 Authorized Iniection Strata for Enhanced Recovery Within the Affected Area, Class II fluids may be injected for the purposes of pressure maintenance and enhanced recovery into strata defined as those which correlate with, and are common to, the formation found in the North Tarn 1 A well (Permit to Drill No. 211-051) between measured depths of 6,130 and 6,212 feet (see Figure 1, below). Rule 2 Fluid Iniection Wells The injection of fluids must be conducted through a new well that has been permitted for drilling as a service well for injection in conformance with 20 AAC 25.005, or through an existing well that AOGCC has approved for conversion to a service well for injection in conformance with 20 AAC 25.280. Rule 3 Authorized Fluids for Iniection for Enhanced Recovery Fluids authorized for injection are: a. Source water from the KRU seawater treatment plant; b. Produced water from the SMU-KROP, produced water from other as yet undefined oil pools in the SW if authorized administratively after showing they will be compatible with the SMU-KROP formation and fluids; AIO 42 June 12, 2019 Page 6 of 8 Figure 1. North Tarn 1A, Reference Log for the SMU Kuparuk River Oil Pool c. Enriched hydrocarbon gas (MI): a blend of KRU lean gas with indigenous and/or imported natural gas liquids; d. Lean hydrocarbon gas; e. Tracer survey fluids to monitor reservoir performance (e.g., chemical, radioactive, etc.); 501032063302 NORTH TARN 1A 2110510 2388 FSL 1780 FEL TWP: 10 N - Range: 7 E - Sec. 2 .6000 mw ._ ____________ __.___________ eso Kuparuk River Oil Pool 4100 A7 -L 4000 onformiry 4100 C -Sand _ r- ----------------- _ Lmrer Crew,.. Un A4 -Sand - M -Sand _ Figure 1. North Tarn 1A, Reference Log for the SMU Kuparuk River Oil Pool c. Enriched hydrocarbon gas (MI): a blend of KRU lean gas with indigenous and/or imported natural gas liquids; d. Lean hydrocarbon gas; e. Tracer survey fluids to monitor reservoir performance (e.g., chemical, radioactive, etc.); AIO 42 June 12, 2019 Page 7 of S f Fluids used to improve near wellbore injectivity (e.g., acid washes, scale inhibition treatments, etc.); g. Fluids used to seal wellbore intervals which negatively impact recovery efficiency (e.g., cement, resin, etc.); h. Fluids associated with freeze protection; and i. Standard oilfield chemicals. Rule 4 Authorized Injection Pressure for Enhanced Recovery Injection pressures shall not exceed the maximum injection gradient of 0.67 psi/ft to ensure containment of injected fluids within the defined Affected Area and injection interval. Rule 5 Monitoring Tubing -Casing Annulus Pressure Inner annulus, outer annulus, and tubing pressures shall be monitored and recorded at least daily, except if prevented by extreme weather condition, emergency situation, or similar unavoidable circumstances for all injection and production wells. The outer annulus pressures of all wells that are not cemented across the SMU-KROP and are located within a one-quarter mile radius of a SMU-KROP injector shall be monitored daily. All monitoring results shall be documented and available for AOGCC inspection. Rule 6 Demonstration of Tubinp-/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 (e.g., 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 SMU- KROP 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. Rule 8 Notification of Improper Class Il Iniection Injection of fluids other than those listed in Rule 3 without prior authorization is considered AIO 42 June 12, 2019 Page 8 of 8 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 9 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 must not be restarted unless approved by the AOGCC. Rule 10 Administrative Action Upon proper application, or its own motion, and unless notice and public hearing are otherwise required, the AOGCC may administratively waive the requirements of any rule stated herein or administratively amend this order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater. DONE at Anchorage, Alaska and dated June 12, 2019. ssie L. Chmielowski—Daniel T. Selaimount, Jr. Commissioner Commissioner 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 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION 333 West 7th Avenue Anchorage Alaska 99501 Re: THE APPLICATION OF Brooks Range ) Docket Number: AIO-19-016 Petroleum Corporation to gain ) Area Injection Order No. 42 authorization to inject fluids for pressure ) maintenance and enhanced recovery of ) Southern Miluveach Unit hydrocarbons in the Southern Miluveach ) Kuparuk River Oil Pool Unit, Kuparuk River Oil Pool ) North Slope Borough, Alaska June 12, 2019 IT APPEARING THAT: 1. By application dated April 25, 2019 (Application), Brooks Range Petroleum Corporation (BRPC) in its capacity of operator of the Southern Miluveach Unit (SMU) requested an Area Injection Order (AIO) authorizing injection of fluids for pressure maintenance and enhanced recovery of hydrocarbons from the Kuparuk River Oil Pool (KROP) within the SMU (the portion of the KROP within the SMU and the Affected Area of this order are referred to as the SMU-KROP). 2. Pursuant to 20 AAC 25.540, the Alaska Oil and Gas Conservation Commission (AOGCC) scheduled a public hearing for June 4, 2019. On April 30, 2019, the AOGCC published notice of that hearing on the State of Alaska's Online Public Notice website and on the AOGCC's website, electronically transmitted the notice to all persons on the AOGCC's email distribution list, and mailed printed copies of the Notice of Public Hearing to all persons on the AOGCC's mailing distribution list. On May 1, 2019, the notice was published in the ANCHORAGE DAILY NEWS. 3. No comments on the application were received. 4. BPRC submitted additional evidence in support of its Application during April and May 2019. 5. The hearing commenced at 10:00 a.m. on June 4, 2019. Testimony and other evidence were provided by BRPC. The hearing record was closed. FINDINGS: Affected Area: The Affected Area lies onshore within the SMU, North Slope Borough, Alaska, about 45 miles west-southwest of Prudhoe Bay. The SMU-KROP is being developed from a gravel pad located in Section 2, Township (T) ION, Range (R) 7E, Umiat Meridian (UM). 2. Owners and Landowners: BRPC is the operator for the SMU. Working interest owners are Alaska Venture Capital Group, LLC; Brooks Range Petroleum Corporation; Caracol Petroleum LLC; Mustang Operations Center 1 LLC; Mustang Road LLC; Nabors Drilling Technologies USA, Inc.; and TP North Slope Development, LLP. The State of Alaska, Department of Natural Resources is the landowner of the Affected Area. 3. Exploration, Delineation, and Production History: During January 2012, BRPC drilled the discovery well—North Tarn I (Permit to Drill No. 211-174�—into the Kuparuk Formation (Kuparuk) in Section 2, Tl ON, R7E, UM, and encountered oil indicators. This discovery was AIO 42 June 12, 2019 Page 2 of 8 confirmed by the Mustang 1 exploratory well (Permit to Drill No. 212-174) in February 2012. To date, five wells have been logged across the Kuparuk reservoir within the SMU. Three-dimensional seismic survey and well log data have been used to determine the geologic structure and reservoir distribution for the SMU-KROP. Well log, well test, and Operator - supplied information were used to establish reservoir and fluid properties for the proposed pool. 4. Pool Identification: The KROP, defined in Conservation Order (CO) No. 432D, is the accumulation of oil that is common to and correlates with the accumulation found in the Atlantic Richfield Company West Sak River State No. 1 well between the depths of 6,474 and 6,880 feet. (Permit to Drill No. 171-003). Along with the SMU, portions of this expansive oil pool also lie within the adjoining Kuparuk River Unit (KRU) and the Milne Point Unit. 5. Geology: a. Structure: The Colville Anticline is the regional structural trap for the SMU-KROP. The SMU lies on a portion of that anticline. Within the SMU, the SMU-KROP ranges in depth from about -5,800 to -6,400 feet TVDSS.' b. Stratigraphy: Within the SMU, Cretaceous -aged reservoir sandstones within the Kuparuk Formation are informally divided into two intervals, the Kuparuk C -Sand (C -Sand) and the underlying Kuparuk A -Sands. The Kuparuk C -Sand consists of bioturbated and burrowed glauconitic sandstones, shaley sandstones, siltstones, and shales. These sediments were most likely deposited in an offshore marine -shelf setting. The thickness of the C -Sand interval varies from 0 to 25 feet within the SMU, and this variation is believed to have been influenced by syndepositional fault activity. The regional Lower Cretaceous Unconformity separates the C -Sand from the underlying A -Sands, and it progressively truncates the A -Sand intervals from southeast to northwest across the SMU. Within the SMU, the A -Sands consist of two upward -coarsening intervals that were deposited in an offshore marine setting. Here, the A -Sands are subdivided into intervals informally named "A4" and "A3", in descending order. The thickness of A4 varies from 0 to 36 feet from northwest to southeast across the SMU. Interval A3 varies from 2 to 40 feet in thickness from northwest to southeast within the SMU. The thickness trends of the A -Sands do not appear to be influenced by faulting or the present-day structure. c. Rock Properties: The C -Sand comprises fine- to coarse-grained quartzose sandstone that contains up to 40 percent glauconite and is commonly cemented with secondary siderite. Porosity averages 22 percent and permeability ranges from 50 to several hundred millidarcies (md) and averages 70 md. Water saturation with the C -Sand can be as low as 20 percent. The underlying A -Sands consist of very fine- to fined -grained sandstone interbedded with siltstone and mudstone. Porosity averages 22 percent. Permeability ranges from less than 10 to 100 md, and averages 30 md. Water saturation in the A -Sands can be as high as 40 percent. To avoid confusion, when depths presented represent true vertical depth below sea level (subsea), the footage will be preceded by a minus sign and followed by the acronym TVDSS (e.g., 5,800 feet true vertical subsea is depicted as -5,800 feet TVDSS). AIO 42 June 12, 2019 Page 3 of 8 d. Faults: Two sets of faults cut the Colville Anticline within the SMU; one set trends north-northeast, and the other set trends west-northwest. The vertical displacement of faults cutting the proposed SMU-KROP ranges up to 85 feet, but is generally less than 30 feet. Because of the relatively thin -bedded nature of reservoir sands within the proposed pool, some faults may act as localized flow barriers and may result in reservoir compartments. e. Tran Configuration and Seals: Well log and seismic information indicate that structural dip controls the hydrocarbon accumulation within the SMU-KROP. The overlying Kalubik and HRZ Shales form the top seal for the oil accumulation within the proposed pool. 6. Reservoir Continuity: Many faults cut the KROP within the Affected Area. As mapped using 3D seismic, these faults have vertical displacements that are generally less than 30 feet. However, some compartmentalization of the pool is expected due to the thin nature of the reservoir strata, especially in the western portion of the Affected Area. 7. Reservoir Fluid Contacts: To date, no hydrocarbon contacts have been encountered in the Kuparuk reservoirs within the Affected Area. 8. Reservoir Fluid Properties: In the SMU-KROP area the initial producing gas oil ratio (GOR) is estimated to be about 600 scf/stb. The API gravity of oil recovered from the proposed pool measured about 24° in the North Tarn IA well. Due to injection activities in the KROP within the adjoining KRU, pressure in the SMU-KROP measured as high as 3,850 psi. Bubble -point pressure is estimated to be 1,930 psi. The oil formation volume factor is estimated at 1.2 reservoir barrels per stock tank barrel of oil. 9. In -Place and Recoverable Volume Estimates: Hydrocarbon Resource Estimated Volume Original Oil in Place (OOIP) 70 MMSTB Primary Recovery (10-25% OOIP) 7-17.5 MMSTB Primary + Water Injection (Additional 10-25% OOIP) 7-17.5 MMSTB Incremental Primary + Water and Lean Gas Injection (Additional 1-5% 0.7-3.5 MMSTB OOIP above Primary+ Water Injection) Incremental Primary + Water and Lean and Enriched Gas Injection 2.1-10.5 MMSTB (Additional 3-15% OOIP above Primary + Water Injection) Incremental These estimates are based on audited reserves and analogous developments. 10. Future Development Plans: BRPC plans to develop the pool using up to 11 horizontal production wells and 10 horizontal injection wells drilled parallel with the major faults that cut the pool. Some wells may be hydraulically fractured to enhance reserve recovery. 11. Confining Lavers for Injection: Approximately 260 feet of Kalubik and HRZ shales overlie the SMU-KROP. Several hundred feet of shales assigned to the Miluveach and Kingak Formations underlie the SMU-KROP. 2 The acronym MMSTB signifies millions of stock tank barrels. Al0 42 June 12, 2019 Page 4 of 8 12. Iniection Rates: The anticipated peak daily injection rate for individual wells within the SMU- KROP is 6,000 barrels of water per day (BWPD) and 6 million standard cubic feet of gas per day (MMSCFPD). 13. Iniection Pressures: Injection pressures at the well head are estimated to be between 2,000 and 2,100 psig during water injection, and between 4,000 and 4,200 psig during gas injection. 14. Fracture Propagation and Confinement: A fracture propagation model showed that at the expected injection -pressure fractures would form in the injection interval but would be confined to the injection interval and not propagate into the confining layers. In order for fractures to propagate into the confining layers, surface pressures during water injection would have to exceed 2,700 prig. 15. Freshwater Strata: No porosity logs have been recorded across the shallow geologic section within the SMU. Accordingly, BPRC commissioned a formation water salinity determination using well logs from West Sak 25590-15, which is located about 3 miles east of the SMU development gravel pad. Well log calculations suggest that aquifers shallower than a depth of about 2,300 feet MD (-2,140 feet TVDSS) within the SMU may contain native formation waters that have total dissolved solids concentrations of less than 10,000 mg/l. However, BPRC will isolate these aquifers with cement from ground level to surface casing shoes that will be set at about -2,500 feet TVDSS. Shallow aquifers within the SMU are not considered Underground Sources of Drinking Water (USDWs) because they are situated at depths that make recovery of water for drinking purposes economically impractical, and they are situated at a location where they are not reasonably expected to supply a public water system. 16. Aquifer Exemption Order: BPRC's Application contends that the U.S. Environmental Protection Agency's (EPA) Aquifer Exemption for the Kuparuk River Field (KRF)— described in Federal Regulation 40 CFR147.102(b)(3)— applies to the Affected Area of this AIO. A map titled "Alaska Oil and Gas Aquifer Exemptions," available on the EPA's Region 10 website at https://www.epa.gov/uic/aciuifer-exemptions-map, indicates the KRF Aquifer Exemption applies to only the portion of the Affected Area that lies within one-quarter mile of the external boundary of the adjoining KRU. A past conversation between AOGCC and EPA staff confirmed EPA's depiction of the KRF Aquifer Exemption boundary that is shown on its "Alaska Oil and Gas Aquifer Exemptions" map. CONCLUSIONS: 1. An Area Injection Order is appropriate to authorize the injection of fluids for enhanced oil recovery purposes in the SMU-KROP within the SMU. 2. The existing Aquifer Exemption for the KRF—as described in Federal Regulation 40 CFR147.102(b)(3)—applies to only the portion of the Affected Area for the proposed SMU AIO that lies within one-quarter mile of the external boundary of the adjoining KRU. An Aquifer Exemption Order is not required for the remainder of the Affected Area because BRPC's enhanced recovery injection operations—as described in BRPC's Application—will not impact any shallow aquifers, and none of the shallow aquifers within the Affected Area are considered USDWs. 3. Reservoir simulation modeling shows water and water -alternating -gas injection into the SMU-KROP will provide a substantial EOR benefit over primary recovery alone, maximize ultimate recovery from the SMU-KROP, and prevent waste. AIO 42 June 12, 2019 Page 5 of 8 4. The maximum possible wellhead injection pressures of 2,200 psig during water injection is well below the pressure needed to initiate fractures in the confining intervals. As such, the confining intervals will ensure that injected fluids remain in the SMU-KROP. NOW THEREFORE IT IS ORDERED: The underground injection of fluids for pressure maintenance and enhanced recovery is authorized in the following area, subject to the following rules and 20 AAC 25, to the extent not superseded by these rules: Affected Area: TION, R7E, UM TI IN, R7E, UM Sections: 1, 2, 3, 4, 9, 10, 11, 12 - All Sections: 24, 25, 26, 35, 36 - All Rule 1 Authorized Infection Strata for Enhanced Recovery Within the Affected Area, Class 11 fluids may be injected for the purposes of pressure maintenance and enhanced recovery into strata defined as those which correlate with, and are common to, the formation found in the North Tarn 1 A well (Permit to Drill No. 211-051) between measured depths of 6,130 and 6,212 feet (see Figure 1, below). Rule 2 Fluid Infection Wells The injection of fluids must be conducted through a new well that has been permitted for drilling as a service well for injection in conformance with 20 AAC 25.005, or through an existing well that AOGCC has approved for conversion to a service well for injection in conformance with 20 AAC 25.280. Rule 3 Authorized Fluids for Iniection for Enhanced Recovery Fluids authorized for injection are: a. Source water from the KRU seawater treatment plant; b. Produced water from the SMU-KROP, produced water from other as yet undefined oil pools in the SMU if authorized administratively after showing they will be compatible with the SMU-KROP formation and fluids; AIO 42 June 12, 2019 Page 6 of 8 Figure 1. North Tarn 1A, Reference Log for the SMU Kuparuk River Oil Pool c. Enriched hydrocarbon gas (Ml): a blend of KRU lean gas with indigenous and/or imported natural gas liquids; d. Lean hydrocarbon gas; e. Tracer survey fluids to monitor reservoir performance (e.g., chemical, radioactive, etc.); 501032063302 NORTH TARN 1A 2110510 2388 FSL 1780 FEL TWP: 10 N - Range: 7 E - Sec. 2 -soon C -Sand -_ ______________ __---- _----- __ /oorr l-re'm'u A4 -Sand n/onrr... Kuparuk River Oil A3 -sand Pool .6100 -0100 Figure 1. North Tarn 1A, Reference Log for the SMU Kuparuk River Oil Pool c. Enriched hydrocarbon gas (Ml): a blend of KRU lean gas with indigenous and/or imported natural gas liquids; d. Lean hydrocarbon gas; e. Tracer survey fluids to monitor reservoir performance (e.g., chemical, radioactive, etc.); AIO 42 June 12, 2019 Page 7 of 8 f. Fluids used to improve near wellbore injectivity (e.g., acid washes, scale inhibition treatments, etc.); g. Fluids used to seal wellbore intervals which negatively impact recovery efficiency (e.g., cement, resin, etc.); h. Fluids associated with freeze protection; and i. Standard oilfield chemicals. Rule 4 Authorized Infection Pressure for Enhanced Recovery Injection pressures shall not exceed the maximum injection gradient of 0.67 psi/ft to ensure containment of injected fluids within the defined Affected Area and injection interval. Rule 5 Monitorine Tubine-Casine Annulus Pressure Inner annulus, outer annulus, and tubing pressures shall be monitored and recorded at least daily, except if prevented by extreme weather condition, emergency situation, or similar unavoidable circumstances for all injection and production wells. The outer annulus pressures of all wells that are not cemented across the SMU-KROP and are located within a one-quarter mile radius of a SMU-KROP injector shall be monitored daily. All monitoring results shall be documented and available for AOGCC inspection. Rule 6 Demonstration of Tubine/Casine Annulus Mechanical Inteerity 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 (e.g., 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 Inteerity 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 SMU- KROP 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. Rule 8 Notification of Imurouer Class II Infection Injection of fluids other than those listed in Rule 3 without prior authorization is considered AIO 42 June 12, 2019 Page 8 of 8 improper Class lI 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 9 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 must not be restarted unless approved by the AOGCC. Rule 10 Administrative Action Upon proper application, or its own motion, and unless notice and public hearing are otherwise required, the AOGCC may administratively waive the requirements of any rule stated herein or administratively amend this order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater. DONE at Anchorage, Alaska and dated June 12, 2019. //signature on file// //signature on file// Jessie L. Chmielowski Daniel T. Seamount, Jr. Commissioner Commissioner 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 I0 -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 ran is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 Penny Vadla 399 W. Riverview Ave. Soldotna, AK 99669-7714 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 AOGCC 614/2019 ITMO: BROOKS RANGE PETROLEUM CORP. FOR AN AREA INIECTION ORDER D.&d No. A10-19-016 ALASKA OIL AND GAS CONSERVATION COMMISSION In the Matter of the Application of Brooks Range Petroleum Corporation for an Area Injection Order for the Kuparuk Oil Pool, Southern Miluveach Unit, Kuparuk C and A Sand Reservoirs. Docket number: AIO 19-016 PUBLIC HEARING Anchorage, Alaska June 4, 2019 10:00 o'clock a.m. BEFORE: Jessie Chmielowski, Commissioner Daniel T. Seamount, Commissioner Computer Matrix, LLC Phone: 909-243-0668 135 LTv¢ .. Dr., Ste. 2., Arch. AK 99501 F. 90)-243-14]3 Email: saluleft vet AOGCC 6/4/2019 ITMO: BROOKS RANGE PETROLEUM CORP. FOR AN AREA INJECTION ORDER Docks No. AIO-19-016 Compute Metria, LLC Ph :907-243-0668 135 Christman Dr., Ste. 2., Asch. AK 99501 Fax: 907-143-1473 Email 3ah11e@6ci.ea Page 2 1 TABLE OF CONTENTS 2 Opening remarks by Commissioner Seamount 03 3 Testimony by Mr. Vendl 08 4 Testimony by Mr. Gleason 20 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Compute Metria, LLC Ph :907-243-0668 135 Christman Dr., Ste. 2., Asch. AK 99501 Fax: 907-143-1473 Email 3ah11e@6ci.ea AOCICC 64/2M19 ITMO: BROOKS RANGE PETROLEUM CORP. FOR AN AREA MIECTION ORDER D.&d NO.A10-19-016 Page 3 1 P R O C E E D I N G S 2 (On record - 10:01 a.m.) 3 COMMISSIONER SEAMOUNT: I'd like to call this 4 hearing to order. The date is June 4th, 2019, the time 5 is 10:01 a.m. We are located at 333 West Seventh 6 Avenue, Anchorage, Alaska. That is the Office of the 7 Alaska Oil and Gas Conservation Commission. I'll 8 introduce the bench. To my right, your left, is 9 Commissioner Jessie Chmielowski and I am Commissioner 10 Dan Seamount. We have a quorum to make a decision on 11 the matter before us which is docket number AIO 19-016, 12 Southern Miluveach Unit, Kuparuk River Oil Pool. 13 Brooks Range Petroleum by letter dated April 14 25th, 2019, requests the AOGCC issue an area injection 15 order to authorize injection for enhanced oil recovery 16 purposes on the portion of Kuparuk River Oil Pool that 17 they operate. And that's defined by conservation order 18 432D. 19 Computer Matrix will be recording the 20 proceedings. You can get a copy of the transcript from 21 Computer Matrix Reporting. 22 So I'm looking at the sign -in sheet and it 23 looks like we have two people to testify and they're 24 both from Brooks Range it looks like. Is there anyone 25 else that wishes to testify? Computa Metrix, LLC Phone: 907-243-0668 135 Chdxt.. Dr., Ste. 2., An6. AK 99501 Fax: 907-2434473 Ematl: s ikcdgd.[ AOGCC 3 2 3 online? 4 5 6/42019 ITMO: BROOKS RANGE PETROLEUM CORP. FOR AN AREA INJECTION ORDER Docket No. A10-19-016 Page 4 (No comments) COMMISSIONER SEAMOUNT: Do we have anybody (No comments) COMMISSIONER SEAMOUNT: Okay. So we have two 6 testifiers. 7 The Commissioners will ask questions during 8 testimony, we may also take a recess to consult with 9 staff to determine whether additional information or 10 clarifying questions are necessary. If a member of the 11 audience has a question that he or she feels should be 12 asked please submit that question in writing to Jody 13 Colombie who's right there in the second row from the 14 back, and she'll provide the question to the 15 Commissioners. And if we feel that asking the question 16 will assist us in making our determinations we will ask 17 it. 18 For those testifying please keep in mind that 19 you must speak into the microphone so that those in the 20 audience and the court reporter can hear your 21 testimony. Also please remember to reference your 22 slides so that someone reading the public record can 23 follow along. For example refer to the slides by their 24 numbers and if they're not numbered by their titles. 25 And it looks like the slides are numbered so we're in Computer Matrix, LLC Ph..: 907-243-0668 135 Christ.. Dr., Sm. 2., Arch. AK 99501 Fax: 907-243-1473 Email: sahikC., i w 6/48019 ITMO: BROOKS RANGE PETROLEUM CORP. FOR AN AREA INJECTION ORDER DocketNo.A10-19-016 Page 5 1 really good shape right now. 2 We have a few ground rules on what is allowed 3 relative to testimony. And I probably don't need to 4 read these off, but I will just in case. First of all 5 testimony must be relevant to the purposes of the 6 hearing that I outlined a few minutes ago and to the 7 statutory authority of the AOGCC. So we're not going 8 to talk about traffic tickets or anything like that 9 today unless you want to. Anyone desiring to testify 10 may do so, but if the testimony drifts off the subject 11 like traffic tickets we will limit the testimony. 12 Additionally testimony may not take the form of cross 13 examination. That's what the questions for Jody would 14 take care of. And as I said before the Commissioners 15 will be asking the questions. And finally testimony 16 that is disrespectful or inappropriate will not be 17 allowed. And that's probably something I didn't need 18 to say because you're all respectful and appropriate. 19 well, almost all of you. 20 Commissioner Chmielowski, do you have anything 21 to add? 22 COMMISSIONER CHMIELOWSKI: No, thank you. 23 COMMISSIONER SEAMOUNT: Okay. I'll now swear 24 in the witnesses. If -- are both of you giving sworn 25 testimony? Computer Matrix, LLC Phoma: 907-243-0668 135 Christeaneu m., Ste. 2., Auch. AK 99501 Fax: 907-243-1473 Email: sahilettgdw AOGCC 6/4/2019 ITMO: BROOKS RANGE PETROLEUM CORP. FOR AN AREA INJECTION ORDER Dc,&d No. A10.19-016 Page 6 1 MR. GLEASON: I'm here for backup. 2 COMMISSIONER SEAMOUNT: Okay. Well, I'll swear 3 you in anyway. 4 So raise your right hands. 5 (Oath administered) 6 IN UNISON: I do. 7 COMMISSIONER SEAMOUNT: Okay. Would any of you 8 like to be recognized as experts? 9 MR. VENDL: (Indiscernible - away from 10 microphone)..... 11 COMMISSIONER SEAMOUNT: Okay. 12 MR. VENDL: I could be, but I'm not certified. 13 I'm not a certified geologist. 14 COMMISSIONER SEAMOUNT: You don't have to be a 15 certified geologist if you want to be an expert. 16 MR. VENDL: That would be the case because both 17 of us are representing our specific fields. 18 COMMISSIONER SEAMOUNT: Right. And there's 19 more credibility -- you get more credibility if you're 20 recognized as an expert. 21 So please state your name, who you represent, 22 what is the subject -- what kind of expert you are and 23 then give your qualifications. 24 MR. VENDL: My name's Lawrence Vendl. I'm a 25 geologist. I am also acting as the exploration and Compatd Matrix, LLC Ph.907-243-0668 135 Cltrixt. Dr., Sta. 2., Aach. AK 99501 Pax: 907-243-1473 Email: sahffa@, .d AOGC'C' 6.42019 ITMO_ BROOKS RANGE PETROLEUM CORP. FOR AN AREA INJECTION ORDER Docks No. AID 19-016 Page 7 1 subsurface manager for Brooks Range Petroleum. I have 2 about 40 years of experience in Alaska, mostly with BP 3 and the last 10 years with Brooks Range as a 4 exploration manager. 5 COMMISSIONER SEAMOUNT: Ms. Chmielowski, 6 questions or objections? 7 COMMISSIONER CHMIELOWSKI: No. question. 8 COMMISSIONER SEAMOUNT: I don't either. You 9 are recognized as an expert in petroleum geology I 10 assume, not just geology, but petroleum geology. 11 MR. GLEASON: My name is Daniel Gleason, I am 12 the senior project manager for Brooks Range Petroleum 13 Corporation. I have a master's in project management 14 from the University of Alaska, I have a bachelor of 15 science in chemical engineering from the University of 16 Kansas. I have worked for ARCO Alaska, ASRC, as a APC 17 and for BP and for Brooks Range Petroleum Corporation, 18 all in facility engineering, facility management, 19 construction management, construction engineering, 20 project management, project engineering and project 21 lead for facilities for BP. I am 37 years in Alaska 22 and 38 years in the business. 23 COMMISSIONER SEAMOUNT: Commissioner 24 Chmielowski. 25 COMMISSIONER CHMIELOWSKI: No questions. Thank Compatr Mavix, LLC Ph.aa 907-243/1668 135 Chhsteasm [X, Sm. 2., Aalh. AK 99501 F. 907-243-1473 FinaiL sahiiuoOmncl AOGCC 6/42019 ITMO: BROOKS RANGE PETROLEUM CORP. FOR AN AREA DUECTION ORDER Docks No. A10 -19-0I6 1 you. 2 COMMISSIONER SEAMOUNT: Where'd you go to 3 school? 4 MR. GLEASON: University of Kansas and UAA. 5 COMMISSIONER SEAMOUNT: Okay. 6 MR. GLEASON: I got my master's in project 7 management from UAA and my BS in chemical engineering 8 from University of Kansas. 9 COMMISSIONER SEAMOUNT: I forgot to ask that of 10 Mr. Vendl. 11 MR. VENDL: I have a bachelor's and master's 12 degree from Northern Illinois University in geology. 13 COMMISSIONER SEAMOUNT: Okay. And you, Mr. 14 Gleason, want to be recognized as an expert in facility 15 engineering? 16 MR. GLEASON: Facility engineering and project 17 management. 18 COMMISSIONER SEAMOUNT: Okay. And I have no 19 questions or objections so you're both recognized as 20 experts in your stated fields. 21 So please proceed. 22 LAWRENCE VENDL 23 previously sworn, called as a witness on behalf of 24 Brooks Range Petroleum Corporation, testified as 25 follows on: Computer Matrix, LLC Phom: 907-243-0668 _ 135 Chr .et Dr., Ste. 2, Amh. AK 99501 F. 907-243-1473 EmuiC sNiilew yantt AOGCC 6/4/2019 ITMO: BROOKS RANGE PETROLEUM CORP. FOR AN AREA 1N3ECTION ORDER Docks No. A1O-19-016 Page 9 1 DIRECT EXAMINATION 2 MR. VENDL: we were asked to come here today to 3 discuss the application for the area injection order, 4 Kuparuk Oil Pool, Southern Miluveach Unit. This 5 includes both the Kuparuk C and the Kuparuk A sand 6 reservoir. I'll refer us to page 2 which is the 7 section A of the application. 8 I've organized the presentation to be somewhat 9 brief, but I'd be glad to answer any detailed questions 10 you might have. You should have received both a copy 11 of the large slides and then there's another set which 12 has the detailed discussions that are included in the 13 area application order. So I've just copied those over 14 for your reference. You might be able to get more 15 detail from that if you need it at some point. 16 In section A we just state that this document 17 is an application for the area injection order which is 18 submitted to the AOGCC in accordance with the specific 19 regulations which are listed there. The purpose of the 20 presentation and the document is to gain authorization 21 from the Commission to inject fluids for pressure 22 maintenance and enhanced recovery of hydrocarbons 23 within the Southern Miluveach Unit which I'll refer to 24 as the SMU. 25 Brooks Range in its capacity as operator Com w Metrix, LLC Mom. 908243-0665 135 Chfim. a @., Ste. 2., Aaoh. AK 99501 F. 90]-243-14]3 Email: saWle@g6nd AOGCC 61412019 "0: BROOKS RANGE PETROLEUM CORP. FOR AN AREA INJECTION ORDER Docka No.Al0-19-016 Page 10 1 submits this document to the Commission that has been 2 prepared in accordance with the regulations for 3 enhanced recovery operations. Brooks Range is 4 operating the Southern Miluveach Unit, Kuparuk 5 Reservoir under the current Kuparuk pool rules. We are 6 working under the assumption that we were and are a 7 part of the Kuparuk pool and so the pool rules that are 8 in place for the Kuparuk River Unit pool are also the 9 same rules that we're working with in the SMU. If 10 that's not the case, you know, or we need to do 11 something, that should probably be brought to our 12 attention because there wasn't a separate application 13 put out there for the Kuparuk pool and the SMU. 14 I should point out that the acreage that is 15 included in the Southern Miluveach Unit at one time was 16 part of the Kuparuk River Unit. 17 COMMISSIONER CHMIELOWSKI: I'm sorry, Larry, 18 could you speak into the microphone..... 19 MR. VENDL: Sure. 20 COMMISSIONER CHMIELOWSKI: .....people in the 21 back can't hear you. 22 MR. VENDL: I should put out that the Southern 23 Miluveach Unit at one point was part of the Kuparuk 24 River Unit back in the early 1980s when the unit was 25 originally formed. As such it was recognized that the Compata Matrix, LLC Ph.907-243-0668 135 Chriatenaea M., Ste. 2., Aach. AK 99501 F. 907-243-1473 Email: s ile(m6ci.oel AOGCC 6/42019 ITMO: BROOKS RANGE PETROLEUM CORP. FOR AN AREA INIECTION ORDER Docket No. A10-19-016 Page 11 1 geology was an extension of the Kuparuk pool and that's 2 the rationalization for us just working within the 3 current pool rules because it was part of the unit at 4 one point in time. 5 COMMISSIONER CHMIELOWSKI: Right. I think that 6 the pool rules covered under conservation order 432D 7 covered its geographic region. 8 MR. VENDL: Correct. 9 COMMISSIONER CHMIELOWSKI: Yeah. 10 MR. VENDL: And refer to page 3. The Kuparuk 11 oil pool within the SMU as I've pointed out is a 12 continuation of the deposit of the Kuparuk C and the 13 Kuparuk C sands adjacent to the southwest portion of 14 the Kuparuk River Unit. It's comprised of sandstones 15 and siltstones and shales that lie between about 16 approximately 5,800 feet true vertical depth subsea and 17 about 6,400 feet true vertical depth within the SMU. 18 COMMISSIONER CHMIELOWSKI: Do you want to 19 forward your slide for that one? 20 MR. VENDL: Sorry. 21 COMMISSIONER CHMIELOWSKI: Yeah. 22 MR. VENDL: The development of the Kuparuk oil 23 pool in the SMU will be completed in discrete phases of 24 drilling to mitigate risk and improve recovery 25 efficiencies. The reservoir targets will be accessed Computer Matrix, LLC Phone %7-243-0668 135 Christensen Dr., Ste, 2., Anch. AK 99501 F. 907-2434473 EmuO: sshilefteinet AOGCC 6/412019 ITMO: BROOKS RANGE PETROLEUM CORP. FOR AN AREA MIECTION ORDER Dockd No.A10-19-0I6 Page 12 1 from the SMU drill site called the Mustang pad. 2 Current plans are to initially develop the field with 3 up to 11 horizontal producers and up to 10 horizontal 4 injectors. Of course there's economics associated with 5 those wells, that would be an up to number for the 6 total number of horizontal wells. Some of the 7 producers may be hydraulically fractured to enhance 8 production and ultimate recovery. 9 Page 4. This figure which is included in the 10 application shows all the existing injection wells, 11 production wells and abandoned wells and dry holes and 12 any other wells within the requested Southern Miluveach 13 Unit within the Kuparuk oil pool. I won't list all the 14 wells off here, but we have submitted all the well data 15 that we have been required to submit to the AOGCC for 16 their reference. And I've been working with Dave Roby 17 and Steve Davies and others, if there's any other 18 information they need I'll be glad to dig out of the 19 files if we didn't have it on file. And specific 20 approvals for any new injection wells or existing wells 21 to be converted to injection will be obtained pursuant 22 to the proper regulations as we permit those wells to 23 be drilled. 24 COMMISSIONER CHMIELOWSKI: Just to confirm, the 25 well in the bottom I think is 2L-03..... Computer Mazrix, LLC Phone: 907-243-0668 135 amste en Dr.. Ste. 2.. Aoch. AK 99501 Fas: 907-243-1473 Email: sehild��gci.od AOG( C 6/4/2019 ITMO: BROOKS RANGE PETROLEUM CORP. FOR AN AREA 1N3ECTION ORDER Docket No. AIO-19-016 Page 13 1 MR. VENDL: Right. 2 COMMISSIONER CHMIELOWSKI: .....has been P&A'd? 3 MR. VENDL: Yes. 4 COMMISSIONER CHMIELOWSKI: Yeah. 5 MR. VENDL: That was a Kuparuk River Unit well 6 that was drilled from the Tarn pad back in 2001. And 7 at the time that we had leased this area that well was 8 still a suspended well and it was P&A'd I think three 9 or four years ago. 10 COMMISSIONER CHMIELOWSKI: Okay. 11 MR. VENDL: Permanently P&A'd. 12 COMMISSIONER CHMIELOWSKI: Okay. Thanks. 13 MR. VENDL: Page 5 just lists the operators and 14 adjacent surface owners. The surface owners of course 15 are State of Alaska, Department of Natural Resources. 16 Current operators adjacent to the unit are 17 ConocoPhillips who operate the Kuparuk River Unit and 18 recently Repsol acquired as part of the Repsol Oil 19 Search Armstrong Consortium, the acreage to the west 20 and northwest of the unit that lies outside of the SMU. 21 COMMISSIONER CHMIELOWSKI: Don't forget to 22 forward your slides, sir. 23 MR. VENDL: That's listed on page 5. Page 6 is 24 just a description of the proposed operation. As I 25 mentioned we'll be drilling up to 10 horizontal Compmer Matrix, LLC Phone: 907-243-0668 135 Clniateosea De., Ste. 2., Anch. AK 99501 Far: 907-2434473 Email: s ile@gu.oet AOGCC 6/4/2019 ITMO: BROOKS RANGE PETROLEUM CORP. FOR AN AREA INION ORDER Docket No. A10-19.016 Page 14 1 producers, I'll have a map of this later, 11 horizontal 2 injectors. They will be drilled in a north/south 3 orientation which is parallel to the geologic 4 structure. This is a commonly accepted practice now 5 similar to shark tooth that has been developed in other 6 areas that have been developed. 7 Jessie, you're probably familiar with the 8 structural orientation of the Kuparuk, the producers 9 and the injectors line up according to the major 10 structural features. 11 Production will be both from the C and the A 12 Kuparuk reservoir sands in alternating rows of 13 producers and injectors to form a line drive flood 14 pattern. The inter -well spacing is approximately 1,500 15 feet, but it does honor the geology. 3D models that we 16 have generated from the coverage that we have over the 17 unit was used for well placement. Plans for both 18 waterflood and eventual lean or miscible gas flood are 19 in place or are in the making. Produced water and 20 seawater injection will be from produced water from the 21 field as well as makeup water coming from the seawater 22 pipeline at Kuparuk. The gas source -- the main gas 23 source for the SMU processing facilities will be 24 produced gas from the field. 25 Page 7 shows the pool location with regard to Compute Matrix, LLC Pb... 907-243-060 135 Chda. @., SW. 2., A . AK 99501 F. 907-243-1473 Erna: euhRe&6.d AOGCC 6/4/2019 ITMO: BROOKS RANGE PETROLEUM CORP. FOR AN AREA W=GN ORDER Docks No. A1O49-016 Page 15 1 the -- and the log that is here shows the Kuparuk C 2 which is the upper sand as labeled and then the lower 3 section is the Kuparuk A section which we'll discuss 4 here in a minute. 5 The confining layers will become important 6 later when we talk about fracture containment. The 7 Kalubik shale is the upper confining layer and the 8 Miluveach shale is the lower confining layer which 9 underlies the Kuparuk. 10 Page 8 is a schematic diagram which 11 demonstrates the location of the SMU and the Mustang 12 pad in relation to the geologic -- regional geology. 13 You can see from this diagram that the Kuparuk C sands 14 overlay the lower Cretaceous unconformity in a rather 15 thin, up to 30 or 40 feet perhaps of this transgressive 16 sand. It's underlain by the Kuparuk A sand, the lower 17 Cretaceous unconformity pinches out the Kuparuk A sands 18 progressively from east to west. And you'll see a map 19 here in a minute which will demonstrate that. I 20 mentioned the Miluveach shale which underlies as a 21 thick shale, regional shale, forming the lower 22 confining layers and the Kalubik shale is about 110 23 feet thick here overlaying the Kuparuk. 24 Section 9 is addressing section G which is the 25 formation geology. This map shows a relative perceived Computer Matrix, LLC Phone: 907-243-0668 135 Christ. Dr., Ste. 2., An& AK 99501 F. 907-243-1473 Email sahile ftei.rxl AOGCC 6/4/2019 [ MO: BROOKS RANGE PETROLEUM CORP. FOR AN AREA INJECTION ORDER Dockd No. AIOAM16 Page 16 1 thickness variation of the Kuparuk C in the area of the 2 SMU which is outlined in black on the slide. The 3 orange areas and the yellow areas are perceived to be 4 the thicker zones in the Kuparuk C. The greens and the 5 blue areas are the thinner zones and you can see a 6 calibration on the left in the color bars which shows 7 that we have zero to over 25 feet of peg (ph) or of 8 sand I should say, of sand. 9 Underlying that shown on page 10 is the 10 continuation of section G on the formation geology. I 11 mentioned we have the Kuparuk A sands underlying the C 12 Sands. Based on well control in the area from 2M of 13 the KRU and to the south where we have control points 14 and to the west as you move out of the unit, we've 15 generated these isopach maps, gross isopach maps of the 16 Kuparuk A. We have two units of the Kuparuk A which 17 I've labeled A3 and A2. They both pinch out as they 18 move to the west. I mentioned that they probably pinch 19 out somewhere about the middle of the unit, but they 20 are significant targets and will be exploited for 21 development. 22 Page 11 is just the lower A sand which extends 23 slightly further to the west across the unit and is up 24 to 45 feet thick -- excuse me, up to 35 feet thick 25 within the unit. ComPuta Mmtix, LLC Phone: %7-243-0OW 135 Chita.. Dr., Ste. 2., A h. AK 99501 Fax: 907-243-1473 Email: sahf.((g6.M AOGCC 6'4 2019 ITMO_ BROOKS RANGE PETROLELM CORP. FOR AN AREA INJECTION ORDLR Docks Na. Alp -19-016 Page 17 1 Page 12 and I apologize for the lack of being 2 able to see this at this scale simply shows a regional 3 section from west to east across the area starting with 4 the Mustang 2L-03 area, across the North Tarn 1 and lA 5 wells over through the M-02 injection well through 6 Mustang number 1 which is a delineation well in the 7 field and then extends over to the east into and shows 8 the correlation to the Kuparuk section in 2M which is 9 under development at the Kuparuk River Unit. Again 10 demonstrating that we're just an extension of the 11 Kuparuk pool 12 Page 13 is a continuation of section G which 13 basically shows a postage stamp size map of the 14 structure at the top of the Kuparuk C. I mentioned 15 earlier that the C sand in the Kuparuk exist from a 16 depth of about 5,800 feet TVD subsea to about 6,400 17 feet TVD subsea. To date we tested oil down to 60,105 18 feet subsea and that'll become important when we talk 19 about reserves and volumetrics because we've been 20 audited for our reserves and they used that down to 21 number as a known oil contact to date. As we drill 22 deeper there'll be additional reserves associated with 23 that. 24 Page 14 just states the current logs that are 25 on record with the Commission. To date two wells Compma Matrix. LLC Phooc 907-24341668 135 Chrfstmveu Dr..SR, 2._Avch_AK 99501 Fax 907-243-1471 EmaiP. sah k(a ai,rd AOGCC 6/42019 IWO: BROOKS RANGE PETROLEUM CORP. FOR AN AREA MJECTION ORDER Docket No. AIO-19-016 Page 18 1 within the SMU have been drilled by Brooks Range and 2 they are intended to be utilized for injection. This 3 would be the North Tarn 1 which will be -- 1A, excuse 4 me, North Tarn lA which will be preproduced initially 5 upon field startup as will M-02. And then those wells 6 are intended in the long run to be injection wells to 7 be used in the unit for water and gas injection. And 8 as I said before the well logs and well histories for 9 all the wells have been submitted and are on file with 10 the Commission. 11 Section I deals with the design and mechanical 12 integrity of the injection wells. And what you see 13 here is just a schematic of a generic SMU Kuparuk pool 14 injector with what we call a four string casing well 15 design which we'll be utilizing for all future wells in 16 the field. Those casing -- that casing design is 17 similar to and is being utilized at 2M pad in the 18 Kuparuk River Unit and it's been deemed to be the best 19 design which mitigates drilling issues associated with 20 the various levels of drilling in the well. This shows 21 that the injectors will be completed largely with 22 slotted liner, four and a half slotted liner, through 23 the production of a horizontal injection interval. 24 COMMISSIONER CHMIELOWSKI: Are you planning to 25 use a steerable liner in your drilling? Computer Matrix, LLC Phone: 907-243-066S 135 Christatmen p., Ste. 2.. Anch. AK 99501 Fax 907-243.1473 Email: sah6eCOg6m, AOGCC 1 MR. VENDL: No. 6/42019 ITMO: BROOKS RANGE PETROLEUM CORP. FOR AN AREA INJECTION ORDER Docks No.AI0-19-016 Page 19 2 COMMISSIONER CHMIELOWSKI: Okay. 3 MR. VENDL: No, I know that's been something 4 that's recently brought to the Slope recently, but we 5 don't plan to utilize it here as far as the current 6 thinking goes, yeah. 7 COMMISSIONER CHMIELOWSKI: Okay. 8 MR. VENDL: I'll mention on the production side 9 of the equation this four and a half inch slotted liner 10 might be replaced by a liner that has sliding sleeves 11 that are up to maybe 10 frac sliding sleeve ports 12 that'll be used for the multi -stage fracs. We feel 13 that it's completely -- to be efficient about draining 14 the A sands that we'll probably need to do multi -stage 15 fracs in those wells where the A sand is present to be 16 able to recover that oil. 17 Pages 16, 17 and 18 are included here in the 18 slide pack and I know that they're not -- it's not able 19 to be read by human eyes at the scale it's at, but in 20 the application under section J we were asked to 21 provide a chemical composition for both the seawater, 22 for produced water and any of the injection fluids that 23 may be injected into the formation. This is taken 24 directly from sample analyses from the Kuparuk River 25 Unit lab and it was included in I believe the recent Compma Matrix, LLC PMne: 907-243-0668 135 Cl tc Dr., Ste. 2., An& AK 99501 Fac 907-243-1473 Email: s ile@Bci m AOGCC 6/4/2019 ITMO: BROOKS RANGE PETROLEUM CORP. FOR AN AREA MIECTION ORDER Docks No.AIOAM16 Page 2 0 1 1 area injection order the same day it was requested. 2 Section K is a table which we constructed to 3 demonstrate the injection pressure parameters that are 4 going to be utilized for secondary recovery and 5 pressure support. And I might ask Dan Gleason to 6 address this. Just in general, Dan, what are your 7 operator parameters that you're going to be working 8 under for both gas and water injection? 9 DANIEL GLEASON 10 previously sworn, called as a witness on behalf of 11 Brooks Range Petroleum Corporation, testified as 12 follows on: 13 DIRECT EXAMINATION 14 MR. GLEASON: For water injection we'll 15 probably have around 2,000 psi at the surface. For the 16 gas injection the estimated gas injection pressure will 17 be around 4,000 to 4,200 psi to inject the gas down 18 hole at the surface. This says bottom hole pressures, 19 but that's actually the -- oh, surface protect [sic] is 20 the 4,000 pounds and it'll be 4,600 pounds 21 approximately at the bottom hole pressure. And around 22 2,000 so it'll be about 20 -- oh, about 3,000 pounds at 23 bottom hole pressure. So those are -- so we hope to 24 have less pressure or less at the surface because it's 25 less stress on the piping, less stress on the pumps. C.m tm Matrix, LLC Phom 907-243-0668 135 Christ.. Dr., Sw. 2., Asch. AK 99501 Fax: 907-243-1473 Email: aahileTlp a.W AOGCC 6;42019 ITMO: BROOKS RANGE PETROLEUM CORP. FOR AN AREA DUECTION ORDER Dockd No.A10-19-016 Page 21 1 But, yeah, it'll be about 2,000 pounds at the surface 2 for water injection and for the gas that's about 4,000 3 pounds to 4,200 pounds at the surface for the gas 4 injection. 5 COMMISSIONER CHMIELOWSKI: So you've mentioned 6 that gas injection would happen maybe later in field 7 life. So can you tell me about how much gas you expect 8 initially and when you might start gas injection? 9 MR. GLEASON: Gas injection probably about -- 10 we plan to burn what we produce initially so we don't 11 flare. And so we'll probably produce about 500 12 barrels..... 13 COMMISSIONER CHMIELOWSKI: Burn as -- burn as 14 fuel gas? Right. 15 MR. GLEASON: Burn as fuel gas, yeah. We got 16 in line heaters, we got generators and that's gas 17 generator for electricity. And so we'll -- and we have 18 also what's called hot heads, the secondary vertical 19 separators with a indirect fire heater underneath them. 20 Just like a modified well test vert -- a vertical 21 separator. And those will all burn the fuel gas and we 22 hope to have the compressors within 60 days after we 23 start production. 24 COMMISSIONER CHMIELOWSKI: Okay. So just be a 25 couple of months..... Compotes Matrix, LLC Ph.: 907-243-0666 135 Chis[ Dr., Ste. 2, Asch. AK 99501 Fax:9W-243-1473 Email: sahileftdd AOGCC 6/4/2019 ITMO: BROOKS RANGE PETROLEUM CORP. FOR AN AREA M3ECTION ORDER Docks No, A10-19-016 Page 22 1 MR. GLEASON: Couple of months. 2 COMMISSIONER CHMIELOWSKI: .....before you 3 start gas injection? 4 MR. GLEASON: Yeah. 5 COMMISSIONER CHMIELOWSKI: Okay. Thanks. 6 MR. GLEASON: Yeah. And hopefully the -- our 7 initial rates we'll have, you know, 2,000 or 2 million 8 to 3 million cubic feet a day injection. 9 COMMISSIONER CHMIELOWSKI: Okay. Thank you. 10 MR. VENDL: Moving on, page 20 which deals with 11 the fracture containment modeling that was done to help 12 support the representation -- or not the 13 representation, the -- show the ability to maintain 14 injection within the Kuparuk -- within the confining 15 layers of the Kalubik and the Miluveach. We contracted 16 with a company that runs a fracture containment model, 17 the acronym is GOHFER, G -O -H -F -E -R. And for the life 18 of me I don't remember the acronym right now. 19 The summary from that work suggests that the 20 hydraulic fractures can be created and extended within 21 the Kuparuk A4 and in the C and there are illustrations 22 here on the next pages which demonstrate that. If 23 water injection is conducted at surface pressures above 24 1,700 to 2,000 psi and as Dan said we'd probably be 25 operating in the 2,100 range for injection pressures. Com wMatrix, LLC ft.. 907-243-0668 135 Chrim.. Dr., Ste. 2., A b.. AK 99501 Fax: 90]-243-14]3 Email: s ileggci vet AOGCC 6/4/2019 ITMO: BROOKS RANGE PETROLEUM CORP. FOR AN AREA DUEC DON ORDER Docks No. A10 19-016 Page 23 1 MR. GLEASON: Two thousand. 2 MR. VENDL: Two thousand. So we'll be within 3 that area to where we'd be able to frac and contain the 4 frac within the zone. This modeling indicates that the 5 created fractures would be contained within the Kuparuk 6 interval unless the surface injection pressure rises to 7 more than about 2,700 to 3,000 psi which we don't 8 anticipate having to do to maintain that fracture. 9 I'm going to point out in the second bullet 10 point that modeling is based on a worst case scenario 11 for fracture containment which is a single point of 12 injection rather than multiple injection points within 13 the Kup C. And what that really means and I'm not a 14 fracture containment expert, but that means when they 15 modeled they modeled it as if it's a single point 16 injection which is the most likely case where if you're 17 putting that much pressure on a formation it would 18 propagate a fracture from that single perf. Of course 19 we're drilling horizontal wells and the ability to get 20 water away is going to be a lot easier at lower 21 pressures because of the fact you're drilling 22 horizontal and you have all that much more exposure to 23 the formation. 24 Page 21 through about page 27 are just screen 25 captures of the various cases that were run for the Compula Matrix, LLC Phone: 907-243-0668 135 Chriml ca Dr., Ste. 2., Aach. AK 99501 Fu: 907-243-1473 Email: s ile(gBcine AOGCC 6AM19 ITMO: BROOKS RANGE PETROLEUM CORP. FOR AN AREA INJECTION ORDER Dodd No, AIO�19-016 Page 24 1 mechanical model. They used a shark tooth 2S pad 2 Kuparuk River Unit well as a basis for design for the 3 fracture because they do fracture those well -- they 4 had multi -stage fracturing going on down there. And 5 what you can see from this and if we just fast forward 6 to page 24 is a model of fracture geometries within the 7 Kuparuk unit at injection rates of 3,000 barrels a day 8 from a single point injection. And I think what is 9 demonstrated by their graphics are that we're contained 10 within the overlying Kalubik and certainly the 11 underlying Miluveach shales. But most of the injection 12 in this model, flooding the upper zones. 13 We also modeled the injection pressure at a 14 high rate of 6,000 barrels a day and you can see from 15 page 26 that there is also a very good sweep generated 16 from a single point injection at a rate of 6,000 17 barrels per day. 18 I'm on slide 26. I breezed through those 19 because I just included these in the packet because it 20 would -- demonstrates the work that was done for the 21 fracture modeling. 22 Page 27 is taken out of the report that was 23 provided to us. And I guess the important thing here 24 is that bullet three is based on the experience with 25 other water injection and disposal projects, continuous Compotes M . LLC Phooe: %7-243-0668 135 Cheim. Dr., Ste. 2., AnOh AK 99501 Fax: W-243-1473 Email: eahile ftd od AOGCC 6!4/2019 ITMO: BROOKS RANGE PETROLEUM CORP. FOR AN AREA INJECTION ORDER Docket No. A10.19-016 Page 25 1 monitoring of injection pressures is recommended to 2 ensure that we're injecting within zone and not 3 exceeding our recommended parameters. 4 Moving on to page 28, section M of the 5 application has to do with formation water quality. We 6 have samples that have been examined from the North 7 Tarn lA well which demonstrate the water chemistry and 8 the oil chemistry of the formation at SMU. We also 9 have samples that are included in the application which 10 were taken from the Kuparuk River Unit in areas where 11 they had -- and below the oil/water contact. And that 12 is available publicly. 13 COMMISSIONER CHMIELOWSKI: Uh-huh. 14 MR. VENDL: I believe I included those in the 15 application, if I didn't I can provide them. 16 Moving on to page 29, section N has to do with 17 demonstrating that we do not have a shallow aquifer 18 within the area of the SMU. As I mentioned before in 19 1986 when the original area injection order was issued 20 for the Kuparuk River Unit, this area was part of the 21 unit and was provided an aquifer exemption at that 22 time. It was stated as an area within a quarter mile 23 of the original unit outline. But as the unit 24 contracted to its current outline we're now outside of 25 that aquifer exemption area. So we were asked to Computa Matrix, LLC Phone: 907-243-0668 135 Chrla. Dr., Ste. 2., Anch. AK 99501 F. 907-243-1473 EmnR: anhileLeci,w AOGCC 6 4 2019 RMO_ BROOKS RANGE PETROLEUM CORP. FOR AN AREA INJECTION ORDER D.rk. No AID -19-016 Page 26 1 actually do a salinity study of the water in the 2 shallow section of the well from below permafrost to 3 above the first hydrocarbon occurrence and that 4 analysis was done by Schlumberger. Their methodology 5 is outlined here and if more information is needed I 6 can put you in touch with the person from Schlumberger 7 who did this work. 8 COMMISSIONER CHMIELOWSKI: Did the EPA request 9 this? 10 MR. VENDL: No, it was actually requested 11 mainly because we were no longer within the original 12 aquifer exemption area as defined as -- currently is 13 defined as the unit boundary of the Kuparuk River Unit. 14 So it was actually AOGCC that asked us to do this 15 methodology. And I got in touch with Schlumberger and 16 said can you do this for us and they said, yeah, we've 17 commonly done that work. They ran the salinity 18 calculations and provided us a salinity log which I did 19 file with the AOGCC recently. 20 COMMISSIONER CHMIELOWSKI: Okay. 21 MR. VENDL: It demonstrates that there aren't 22 any significant thick reservoir sections in the up hole 23 section which you might want to point to that could be, 24 could be, areas of freshwater. These would be zones 25 that are below permafrost so they're in excess of 2,000 Compwer Matrix. LLC Phoa, 907-2430668 135 Clt,it, e m Dr.. S(e. 2., Arch. AK 99501 Fax 907.243-1473 Email: sahile(a gci.ma AOGCC 6/4!2019 ITMO: BROOKS RANGE PETROLEUM CORP. FOR AN AREA INJECTION ORDER D.&N No. AKO IM16 Page 27 1 feet deep and they're very thin. Their analysis shows 2 that those areas have total dissolved contents that are 3 largely above the limits that you would consider to be 4 portable or potable water. So we're making the case 5 there are no known shallow water aquifers within the 6 area of the SMU. 7 COMMISSIONER SEAMOUNT: But what is the TDS 8 that's been calculated, is it..... 9 MR. VENDL: In the salinity logs? 10 COMMISSIONER SEAMOUNT: Yeah. 11 MR. VENDL: I'd have to go back and refer to 12 the logs. I think by definition as I understand it the 13 total dissolved solids would be above 3,000 to be 14 considered not potable. And I know that a lot of these 15 sands have water calculations in the range of 10,000 or 16 greater. 17 COMMISSIONER SEAMOUNT: Yeah, I think the 18 definition of freshwater does go to 10,000 parts per 19 million. 20 MR. VENDL: So we'd be able to look at that 21 from the log results. I just wouldn't be able to quote 22 you foot by foot what we've seen in the log. 23 COMMISSIONER SEAMOUNT: Yeah, I would recommend 24 that you talk to our staff as to whether it would be 25 wise to go for an aquifer exemption. It's not a big Comp w Matrix, LLC Phone: 907-243-0666 135 C iste en @., Ste. 2., Arch. AK 99501 Fax: 907-243-1473 F ail: sahileft6nN 906(C 1 deal, but..... 2 MR. VENDL: Yeah. &4/2019 ITMO: BROOKS RANGE PETROLEUM CORP. FOR AN AREA INJECTION ORDER DocketNo.A10-19-016 Page 28 3 COMMISSIONER SEAMOUNT: .....it might be a way 4 to protect yourself in case something bad..... 5 MR. VENDL: And it was unclear to me if we 6 would need to apply for a specific aquifer exemption 7 for the SMU or if it would be some sort of an 8 administrative order which recognized that we were part 9 of the original aquifer exemption area. But because of 10 the unit contraction and the aquifer exemption being 11 specific to the operator that we would need to do that 12 and we could work with you on that. 13 COMMISSIONER SEAMOUNT: Okay. I -- yeah, I 14 think you got..... 15 MR. VENDL: I..... 16 COMMISSIONER SEAMOUNT: .....you got time on 17 that. 18 MR. VENDL: Yeah, we have time and actually if 19 we had any significant shallow aquifers that would be 20 in low salinity water we'd be on it tomorrow because 21 for source makeup water it would be a lot more 22 expeditious for us to drill wells for source water for 23 injection like they do on other parts of the Slope, 24 Prince Creek for instance at Milne Point, rather than 25 actually having to buy seawater from the seawater Compute Matrix, LLC Phone: 907-24341A68 135 Chrinemen Dr., Sm, 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahilermgci.net AGGCC 6/42019 1TM0: BROOKS RANGE PETROLEUM CORP. FOR AN AREA INJECTION ORDER Docket No. AIO0.19.016 Page 29 1 plant. So I think we can work with Dave Roby and 2 others to demonstrate -- and I have been on the phone 3 with him talking with him about this the last couple 4 weeks so we can -- we can work through that. 5 Did that answer your question there? 6 COMMISSIONER CHMIELOWSKI: Yeah. 7 MR. VENDL: There's a snapshot here of the 8 salinity log, but it's not in its entirety, but it is 9 provided. 10 And then moving on to section O which is 11 hydrocarbon recovery. On page 31 is a map showing the 12 initial directional plans for the horizontal producers 13 in green, if you can see that, and then the injection 14 wells in blue. In this diagram there should be the 11 15 and 10 count that I talked about earlier. And you can 16 see they're oriented like I mentioned before in a north 17 to south direction according to the major structural 18 features in Kuparuk. 19 It was pointed out to me that some of the well 20 trajectories get within legal limits of the legal 21 boundary especially on the western side there, they 22 cross out of the unit, that was pointed out to me last 23 week. And we originally had the leases on the west 24 side of the SMU, now they mostly are leased by Repsol 25 and Oil Search Armstrong. Certainly when these wells Compmer Manu, LLC Ph..: 907-243-0668 135 Claistemeo Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Emil: s eh igci.m AOGCC 6{42019 ITMO: BROOKS RANGE PETROLEUM CORP. FOR AN AREA RUEMON ORDER Docks No.A10-19-016 Page 30 1 are permitted we'll have to go through the sundry 2 permit process about getting them legally spaced. 3 And then finally on section 0 addressing 4 hydrocarbon recovery and oil in place. You see in the 5 upper part of this table there are what are called 1P, 6 2P and 3P reserve categories. That's proven, probable 7 and possible. I mentioned earlier that we tested oil 8 down to 6,105 feet TVD subsea. When the company that 9 did our reserves audit did their audit, they used that 10 as a depth of known oil. Nominally they use 30 percent 11 recovery in the 1P category which is the commonly used 12 number for average recovery under normal waterflood 13 conditions. That equates to a 21.2 million barrel full 14 recovery and if you back that out at 30 percent I 15 believe it comes out to 70.6 million barrels in place. 16 To get to the 2P and 3P reserves they assume they we 17 completely develop the field, we push the oil/water 18 contact down to a deeper level at the extent of the 19 unit boundary and we increase our recovery efficiencies 20 by tertiary recovery methods to 35 percent in the 2P 21 case and then they up it to 40 percent in the 3P case. 22 And that's how they resolve the gross recoverable 23 reserves. And you can -- we can back calculate oil in 24 place if that's what's needed from that. 25 COMMISSIONER CHMIELOWSKI: Are you planning to Computer Mmm, LLC Phow 907-243-0668 135 Chrismosen Dr., Ste. 2., Auch. AK 99501 Fu: 907-243-1473 E.H: saN16 gci.nm AOGCC 6/48019 ITMO: BROOKS RANGE PETROLEUM CORP. FOR AN AREA DUECTION ORDER D kn No.A10-19-016 Page 31 1 drill a pilot hole or do anything to sort of more 2 formally establish an oil/water contact or..... 3 MR. VENDL: What we'll be doing with most of 4 the drilling in my opinion is we'll be utilizing this 5 four string casing design and in the third intermediate 6 section of the hole, that section will be extended down 7 into the Kuparuk and will be drilled through the 8 Kuparuk to establish the present thickness of the C and 9 the A sands. And that way we'll know exactly where 10 we're at vertically in the stratigraphic section and 11 we'll know from log analysis what we can hang our hat 12 on as far as net pay. At that point we would back up, 13 plug back to a point and kick off and drill the 14 horizontal sections of the production hole. So that 15 would be nominally what we would do until we were 16 absolutely sure we knew what -- where we were. There 17 may be some wells as in (indiscernible) 2S pad where 18 they don't need to drill the pilot holes anymore 19 because they have enough geologic control. 20 COMMISSIONER CHMIELOWSKI: Okay. 21 MR. VENDL: I think that concludes the review 22 -- quick review of the sections in the application. 23 I'd be glad to answer any questions that we can answer 24 here or follow-up with anything that may need to be 25 followed up on such as the aquifer exemption. Compute Metria, LLC Ph..: 901-243-0668 135 Christemeo Dr., Ste. 2., Anoh. AK 99501 Fee: 901-243-1413 Email: eahile.�§gdue AO CC 6/42019 1TM0: BROOKS RANGE PETROLEUM CORP. FOR AN AREA M3ECrION ORDER Docks No.A10 M16 Page 32 1 COMMISSIONER SEAMOUNT: Ms. Colombie, have you 2 gotten any questions? 3 MS. COLOMBIE: No. 4 COMMISSIONER SEAMOUNT: Okay. Commissioner 5 Chmielowski, do you see any reason to take a recess? 6 COMMISSIONER CHMIELOWSKI: No, I don't see a 7 reason. 8 COMMISSIONER SEAMOUNT: Do the staff? 9 COMMISSIONER CHMIELOWSKI: Does staff want a 10 recess? 11 COMMISSIONER SEAMOUNT: We want to take a 12 recess. 13 MR. ROBY: A very short one. 14 COMMISSIONER SEAMOUNT: Okay. We'll take -- 15 the time is 10:44 according to the clock on the wall. 16 We'll be back at hopefully 10:55, 10 minutes. 17 (Off record) 18 (On record) 19 COMMISSIONER SEAMOUNT: Okay. It's 11:03 and 20 who's the guy in charge with Brooks Range is it Mr. 21 Armstrong? 22 UNIDENTIFIED VOICE: (Indiscernible - away from 23 microphone)..... 24 COMMISSIONER SEAMOUNT: Well, who's in charge? 25 UNIDENTIFIED VOICE: (Indiscernible - away from CompmaM &, LLC PMne: 907-243-0668 135 CMimenaw @., Ste. 2., Arch. AK 99501 F.: 909-243-1473 Email: mhile@gci.nm AOGCC 614/2019 ITMO: BROOKS RANGE PETROLEUM CORP. FOR AN ARBA MIECPION ORDER M&d N0. A10-19-016 Page 33 1 microphone)..... 2 COMMISSIONER SEAMOUNT: Armfield I mean -- 3 Armstrong. I'm sorry. 4 UNIDENTIFIED VOICE: (Indiscernible - away from 5 microphone)..... 6 COMMISSIONER SEAMOUNT: Armstrong made the big 7 discovery. Okay. So you're the guy in charge, right, 8 please come forward. 9 MR. ARMFIELD: Green light's on, can you hear 10 me? 11 COMMISSIONER SEAMOUNT: Please identify 12 yourself. 13 MR. ARMFIELD: Bart Armfield, Brooks Range 14 Petroleum president and CEO. 15 COMMISSIONER SEAMOUNT: Okay. There's been a 16 question of confidentiality that's come up. So we need 17 to get that taken care of. So could you please 18 identify who you would like to stay in the room and 19 we'll take a short -- we'll do a short confidentiality 20 session. 21 MR. ARMFIELD: Confidentiality regarding what 22 topic? 23 COMMISSIONER SEAMOUNT: Certain displays that 24 we're shown today. 25 MR. ARMFIELD: Okay. Com uta Mavis, LLC Phone: 901-2430668 135 Chr .v . @, St<. 2., A & AK 99501 F.: MI -243-1473 Email: suhik�mgd. AOGCC 6/4Y 019 ITMO: BROOKS RANGE PETROLEUM CORP. FOR AN AREA INJECTION ORDER Docket No. A10.19-016 Page 34 1 COMMISSIONER SEAMOUNT: Okay. They were marked 2 confidential on the application, but not -- but they 3 were shown today. 4 MR. ARMFIELD: Right. 5 COMMISSIONER SEAMOUNT: So we need to know how 6 that -- how important it is to Brooks Range that they 7 continue to be confidential or whether we should 8 request the people that have copies of those 9 displays..... 10 MR. ARMFIELD: Return them, yeah. 11 COMMISSIONER SEAMOUNT: .....be returned. 12 MR. ARMFIELD-. But relative to anybody in the 13 room they're all part of the project, right, Larry? 14 UNIDENTIFIED VOICE: (Indiscernible - away from 15 microphone)..... 16 MR. ARMFIELD: Yeah, but you're media, right? 17 COMMISSIONER SEAMOUNT: We have the press here. 18 MR. ARMFIELD: Okay. I'm sorry, but I've had 19 that happen before. 20 UNIDENTIFIED VOICE: (Indiscernible - away from 21 microphone)..... 22 MR. ARMFIELD: Yep. Is that all right? 23 UNIDENTIFIED VOICE: (Indiscernible - away from 24 microphone)..... 25 MR. ARMFIELD: Okay. Thank you. C.ngouw Metrix, LEC Phone: 907-243-0668 135 Chn9.e R., Sle. 2., Avch. AK 99501 Fu: 907-243-1473 Email: while Wgci vet AOGCC 6/42019 ITMO: BROOKS RANGE PETROLEUM CORP. FOR AN AREA INJECTION ORDER DmId No. AI619-016 Page 35 1 UNIDENTIFIED VOICE: (Indiscernible - away from 2 microphone)..... 3 COMMISSIONER SEAMOUNT: Sorry, Kristin. 4 MR. ARMFIELD: She's been there before, I'm 5 sure. 6 COMMISSIONER SEAMOUNT: Okay. It looks like 7 your slides number 27 to 29 were marked confidential on 8 your application, but not on the handouts today. How 9 important is it..... 10 UNIDENTIFIED VOICE: (Indiscernible - away from 11 microphone)..... 12 COMMISSIONER SEAMOUNT: Oh, wait a minute, 13 they're different here. 14 COMMISSIONER CHMIELOWSKI: It might have been 15 pages on the application and different pages on the 16 presentation. 17 COMMISSIONER SEAMOUNT: Okay. On the 18 presentation..... 19 COMMISSIONER CHMIELOWSKI: 9 through 11. 20 COMMISSIONER SEAMOUNT: .....9 through 11. 21 MR. ARMFIELD: 9, 10..... 22 COMMISSIONER CHMIELOWSKI: Is it 9 through 11, 23 Dave? 24 MR. ROBY: This map, that map and this map. 25 These were marked confidential in the application. Compute Mmrix, LLC Phone: 907-243-0668 135 Chdawmam Dr., Ste. 2., Aach. AK 99501 Fax: 907-243-1473 Email: sehile(a6ci.nd AOGCC 6/4/2019 ITMO: BROOKS RANGE PETROLEUM CORP. FOR AN AREA IN3ECTION ORDER Doc4H No.Al0-19-016 Page 36 1 COMMISSIONER CHMIELOWSKI: 9 through 11 and 13. 2 MR. ARMFIELD: Can I confer with..... 3 COMMISSIONER SEAMOUNT: Yes, please. 4 MR. ARMFIELD: So I don't think we need to 5 retract anything. 6 COMMISSIONER SEAMOUNT: Okay. I'm glad you 7 said that. 8 MR. ARMFIELD: Yeah. 9 COMMISSIONER SEAMOUNT: Otherwise we'd be in a 10 quandary. 11 MR. ARMFIELD: No, I think we -- we're fine. 12 COMMISSIONER SEAMOUNT: All right. Somebody 13 get Kristin back in here. 14 MR. ARMFIELD: All right. Thank you. 15 COMMISSIONER SEAMOUNT: Thank you, Mr. 16 Armfield. Okay. Members of the public, it has been 17 decided that these will not be kept confidential and we 18 won't tell you which ones they are. 19 Okay. Do we need to keep the record open for 20 anything? 21 (No comments) 22 COMMISSIONER SEAMOUNT: Oh, there's one more 23 thing I wanted to say. It appears that you think that 24 the old EPA area injection order..... 25 COMMISSIONER CHMIELOWSKI: Aquifer exemption. Computes Matra, LLC Phone: 907-243-0668 135 Chdrtenven Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email:e HeCgci,m AOGCC 6/4/2019 ITMO: BROOKS RANGE PETROLEUM CORP. FOR AN AREA INJECTION ORDER 0.&d No.A10-19-016 Page 37 1 COMMISSIONER SEAMOUNT: .....aquifer exemption 2 is valid, but we disagree with that so you should 3 probably talk to our staff and determine whether you 4 want an aquifer exemption or not. That's what you need 5 to talk to staff about, do you need one. 6 MR. VENDL: Yeah, we can follow-up on that I 7 think after the meeting and see what the next steps 8 are. We did go through the process just for your 9 information of contacting the EPA..... 10 COMMISSIONER SEAMOUNT: Oh. 11 MR. VENDL: .....and pointing out that in their 12 1986 aquifer exemption that was included in the AIO for 13 the Kuparuk River Unit was granted. Unfortunately they 14 couldn't find the maps that demonstrated that within 15 the EPA and they were standing by the need to honor the 16 outline of the Kuparuk River Unit as the boundary. So 17 you can see our quandary is that we know it was in the 18 original exemption, but as per their definition today 19 their electronic version shows we're outside of that. 20 So..... 21 COMMISSIONER SEAMOUNT: Okay. Well, that's 22 what..... 23 MR. VENDL: .....we'll just need to work 24 through it and see what you want to do. 25 COMMISSIONER SEAMOUNT: Yeah, you need to talk Ca.Pa1Q M . LLC P .: 907-243-0668 135 C irteaaea Dr., Su. 2., A 6. AK 99501 Fac: 907-243-1473 Email: s Ie(ygci..= AOGCC 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 642019 ITMO. BROOKS RANGE PETROLEUM CORP. FOR AN AREA INILCr10K ORDER Dockm No_A10.19-016 Page 38 to our staff and maybe we have the information that you're looking for. Do we need to leave the record open? COMMISSIONER CHMIELOWSKI: I don't believe so. I believe we have a complete application. So I have no further questions. COMMISSIONER SEAMOUNT: We have a complete application? COMMISSIONER CHMIELOWSKI: Right. COMMISSIONER SEAMOUNT: All right. Very good presentation and thank you for your participation, Mr. Gleason, Mr. Vendl and Mr. Armfield. Do I hear a motion to adjourn. COMMISSIONER CHMIELOWSKI: I so move. COMMISSIONER SEAMOUNT: And I second. This hearing is adjourned at 11:11. (Hearing adjourned - 11:11 a.m.) (END OF PROCEEDINGS) Computer Matrix. LLC Phone: 907-243-0668 135 Chn,aim m Dr_ Sm. 2.- Arch. AK 99501 Fax_ 907-243-1473 pound suhile. g,, re, AOGCC 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 6/4/2019 ITMO: BROOKS RANGE PETROLEUM CORP. FOR AN AREA INECTION ORDER Docks No. MO -19-0I6 Page 391 TRANSCRIBER'S CERTIFICATE I, Salena A. Hile, hereby certify that the foregoing pages numbered 02 through 39 are a true, accurate, and complete transcript of proceedings in Docket number: AIO 19-016, transcribed under my direction from a copy of an electronic sound recording to the best of our knowledge and ability. Compuw Metrix, LLC Phov : 901.243-0668 135 Chri .. Dr., &e. 2, Asch. AK 99501 Fax: 907-243-1473 Emeil: aahile@gci.en STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Docket Number: AIO-19-016 Southern Miluveach Unit, Kuparuk River Oil Pool The application for Area Injection Order June 4, 2019 at 10:00 am NAME AFFILIATION Testify (yes or no) ;�" y Lc,06UW p1\1 5+e i'VlrzoLy+ -L)oG �b Application for Area Injection Order Kuparuk Oil Pool Southern Miluveach Unit (Kuparuk "C" and "A" Sand Reservoirs) L. Vendl, L. Smith, D. Gleason Section A -Introduction 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 pressure maintenance and enhanced recovery of hydrocarbons in the Southern Miluveach Unit, Kuparuk Oil Pool pursuant to 20 ACC 25.402. Brooks Range Petroleum Corporation ('BRPC"), in its capacity as Operator of the Southern Miluveach Unit (SMU), 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). BRPC is operating the SMU Kuparuk Reservoir under the Current Kuparuk Pool Rules that govern the development of the Kuparuk Pool. AYNN Introduction The Kuparuk Oil Pool within the SMU is a continuation of the deposit of Kuparuk "C" and Kuparuk "A" Sands adjacent to the southwest portion of the Kuparuk River Unit. It is comprised of sandstones, siltstones, and shale that lies between -5800 ft. true vertical depth sub -sea ("TVDSS") and -6400 ft. TVDSS within the SMU. Development of the Kuparuk Oil Pool in the SMU will be completed in discrete phases to mitigate risk and improve recovery. The reservoir targets will be accessed from the SMU "Mustang" drill site. Current plans are to initially develop the field with up to 11 horizontal producers and up to 10 horizontal injectors. Some of the producers may be hydraulically fractured to enhance production and ultimate recovery. Section B — Project Area Figure B-1 shows all existing injection wells, production wells, abandoned wells, dry holes and any other wells within the requested Southern Miluveach Unit, Kuparuk Oil Pool. 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. /Ni Section C & D — Operator & Adjacent Surface Owners BRPC Is Me designated operator W the SMU, which Included the Mustang art ells from which the Kupamk developmem wells will be drilled. The Sudeceowners and operators within one-quarter mile redIUS of Me proposed Infection area are listed below. Surface Owners State of Alaska Depamment of Natural Resources Division of Oil and Gas Attention: Jame. Beckham, Director 550 West Seventh Avenue, Suite 1100 Anchorage, AK 9 95 01-35 5 Ocaratom CanocoPhillipe 700 G Street Anchorage, Alaska 99501 Repsol 3800 Centerpoint Dr. Anchorage, Alaska, 99503 Section E - Description of Proposed Operation • Up to 10 horizontal producers & 11 horizontal Injectors • Drilled in north/south Orientation, parallel geologic structure • Production from both "C" and "A" Kuparuk reservoir sands • Alternating rows of producers and Injectors • "Line drive" flood pattern • Approximately 1500' inter -well spacing • 3D model guides well placement • Plans for both waterflood and eventual lean or miscible gas flood • Produced water and seawater injection (CPAI seawater pipeline) • Gas sourced from SMU processing facilities The Kuparuk Oil Pool within the Southern Miluveach Unit will be developed from the existing SMU Mustang drillsite and produced through the SMU processing facilities. Current plans call for 10 horizontal producers and up to 11 horizontal injection wells. Depending on expected reservoir quality, some of the producers may be hydraulically fractured to stimulate production and enhance ultimate recovery. As needed, additional wells may be drilled to optimize reservoir performance Most of the development wells will trend North to South parallel to the direction of the major fault patterns that cut through the reservoir. The length of the horizontal sections of the wells are planned to range in length up to 6000' within the reservoir. Some of the wells will produce from both the Kuparuk "C' and the Kuparuk "A" reservoirs. In these wells it is expected that hydraulic fracture stimulation may be needed to enhance productivity and improve vertical injection sweep. The wells will be arranged end-to-end to form alternate rows of producers and injectors in a line -drive flood pattern. Initial studies, which include a computer-generated reservoir simulation study, suggest a nominal 1500' inter -well spacing will fit within and between the major faults which cut through the Kuparuk reservoir and will most likely cause some interference to a conformable waterflood. Based on well performance, some infill drilling may be needed to optimize reservoir performance and maximize recovery. To evaluate the performance of the Kuparuk Reservoir, a 3-D model, based on the available 3D seismic surveys, was constructed covering the entire development area to demonstrate reservoir performance using a waterflood for enhanced recovery. Additionally, waterflooding may 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 will most likely consist of either produced water or seawater injection. The seawater injection source water will come from the nearby CPA] operated Alpine seawater pipeline. Gas will be sourced from the SMU 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 may occur in the future on one or more injection patterns to enhance recovery from the reservoir. An economic evaluation of future IWAG and MWAG projects will determine the feasibility of utilizing these enhancement techniques within the SMU. ^11� Section F — Pool Location and Description Deflning Well, North Tern I0. hlghllghting Pool Interval whh respect tc the upper end lower confining Inlemels Location As shown on Figure F-1, the affected area proposed for the Southern Miluveach Unit, Kuparuk Oil Pool Area Injection Order is the entire Kuparuk Oil Pool, as proposed, which is within the following land: Location As shown on Figure F-1, the affected area proposed for the SMU Kuparuk Oil Pool Injection Order is the entire SMU Kuparuk Oil Pool including the following land are: Umiat Meridian TION, R7E Sections 1, 2,3,4,9,10,11, 12 all T31N, R7E Sections 24, 25, 26, 34, 35, 36 all Pool Definition Injection of fluids for enhance recovery is proposed for the correlative interval shown in Figure F-2, the North Tarn 1A well, known as the Southern Miluveach Unit (SMU), Kuparuk Oil Pool. Within the requested areal extent, the SMU Kuparuk Pool is defined as the accumulation of hydrocarbons common to and correlating with the interval between the depth of -6006 ft. TVDss and-6090ft. TVDss as defined in the North Tam 1A Well. Within the proposed Area Injection Order, the primary Kuparuk reservoirs are the Kuparuk "C" and the Kuparuk "A" intervals. Lower Confining Interval Below the Kuparuk Oil Pool is the Miluveach Shale. The Miluveach is a thick regional shale deposit in the proposed area of development. The Kuparuk Pool in the area of the SMU The primary reservoirs in the proposed Area Injection Order consist of the shallow marine sandstones of the Kuparuk "A" reservoir and the unconformably overlying transgressive sandstones of the Kuparuk "C' reservoir. The underlying "A" is generally less permeable reservoir than found in the more permeable Kuparuk "C" reservoir. Upper Confining Interval The Kuparuk "C" reservoir is overlain by the Kalubik Shale interval. The Kalubik Shale is a regionally extensive and thick shale unit which provides acts a top seal for the reservoir and provides the upper confining layer to waterfiood. 7 A -A'\ Section G — Formation Geology wwwnm wrrpyu..� w"°"""'""a qy I G -t: West to East Schematic Stratigraphic Cross Section Across Area of Interest StratleraphY Figure G3 shows the depositional model for Kuparuk Formation, which consists of the underlying Kuparuk "A" shallow marine sands which are thought to be truncated in the Western portion of the SMU. The Kuparuk "A" sand is overlain by the Kuparuk "C" which is a transgressive sand deposited on the regional Lower Cretaceous Unconformity. The Kuparuk "C" and underlying Kuparuk "A" members of the Cretaceous age Kuparuk formation consist of very fine to coarse grained sandstones and siltstones. Within the proposed development area, the combined thickness of the two members ranges from 0 to over 80 feet. Figure G2 shows the expected isochore of the Kuparuk "C", which is the primary reservoir in the area ranging from 0 to as much as 35 feet thick. Thickness is estimated from well data and seismic signature. Figure G-3 shows the expected isochore of the Kuparuk "A" reservoir, ranging from 0 to as much as 80 feet thick. The Kuparuk A" reservoir thins to the west as it is truncated by the Lower Cretaceous Unconformity. Sedimentoloev The Kuparuk "C" sandstones are fine to coarse-grained, composed of quartz and up to 40% structural glauconite, and are commonly cemented with secondary siderite (the ubiquitous precipitate in North Slope reservoir sandstones). Porosity averages 22% and permeabilities range from 50 to hundreds of mD in the Kuparuk "C' averaging 70 mD in the Mustang area. The Kuparuk "A" sandstone are very fine to fined grained sandstone interbedded with siltstone and mudstones. Porosity averages 22%, but the permeability is lower than the Kuparuk "C" member ranging from less than 10 mD to 300mD, averaging 30 mD. Structure and Trap 7 e Kuparu Poo within the SMU ranges in depth from-5800to -6400' TVDSS. Oil is trapped within the regional structural trap formed by the Colville Anticline. There is no oil -water contact in the proposed Area Injection Order. The Kuparuk reservoirs in the SMU are well above the known oil -water contact of the Kuparuk Oil Pool, which Range in depth from 6530' TVDss to 6650' TVDss in the KRU and are deeper than this to the Northeast in the Milne Point Unit. Definin¢ Net Pa Net pay is general defined by Gamma Ray, Resistivity and Porosity logs. Water saturation in the Kuparuk "C" can be as low as 20%, while water saturations in the Kuparuk "A" are as high as 40%. Net Pay cutoffs of about 15% porosity and 35% water saturation are assumed for purposes of volumetric calculations and are consistent with petrophysical evaluations which suggest these cutoffs are good indicators of net pay in the Kuparuk "C" sand. Section G — Formation Geology G•2: Kuparuk"C" Reservoirisochore Stratigraphy Figure G1 shows the depositional model for Kuparuk Formation, which consists of the underlying Kuparuk "A" shallow marine sands which are thought to be truncated in the Western portion of the SMU. The Kuparuk "A" sand is overlain by the Kuparuk "C" which is a transgressive sand deposited on the regional Lower Cretaceous Unconformity. The Kuparuk "C" and underlying Kuparuk "A" members of the Cretaceous age Kuparuk formation consist of very fine to coarse grained sandstones and siltstones. Within the proposed development area, the combined thickness of the two members ranges from 0 to over 80 feet. Figure G2 shows the expected isochore of the Kuparuk "C", which is the primary reservoir in the area ranging from 0 to as much as 35 feet thick. Thickness is estimated from well data and seismic signature. Figure G-3 shows the expected isochore of the Kuparuk "A" reservoir, ranging from 0 to as much as 80 feet thick. The Kuparuk A" reservoir thins to the west as it is truncated by the Lower Cretaceous Unconformity. Sedimentolo The Kuparuk "C" sandstones are fine to coarse-grained, composed of quartz and up to 40% structural glauconite, and are commonly cemented with secondary siderite (the ubiquitous precipitate in North Slope reservoir sandstones). Porosity averages 22% and permeabilities range from 50 to hundreds of mD in the Kuparuk "C" averaging 70 mD in the Mustang area. The Kuparuk "A" sandstone are very fine to fined grained sandstone interbedded with siltstone and mudstones. Porosity averages 22%, but the permeability is lower than the Kuparuk "C" member ranging from less than 10 mD to 100mD, averaging 30 mD. Structure and Trap T e Kuparu Poo within the SMU ranges in depth from -5800 to -6400' TVDSS. Oil is trapped within the regional structural trap formed by the Colville Anticline. There is no oil -water contact in the proposed Area Injection Order. The Kuparuk reservoirs in the SMU are well above the known oil -water contact of the Kuparuk Oil Pool, which Range in depth from 6530' TVDss to 6650' TVDss in the KRU and are deeper than this to the Northeast in the Milne Point Unit. Defining Net Pa Net pay is general defined by Gamma Ray, Resistivity and Porosity logs. Water saturation in the Kuparuk "C" can be as low as 20%, while water saturations in the Kuparuk "A" are as high as 40%. Net Pay cutoffs of about 15% porosity and 35% water saturation are assumed for purposes of volumetric calculations and are consistent with petrophysical evaluations which suggest these cutoffs are good indicators of net pay in the Kuparuk "C" sand. A'\ Section G — Formation Geology ✓i G-3: Kuparuk "A3" Reservoir Isochore / Stratigraphy Figure G1 shows the depositional model for Kuparuk Formation, which consists of the underlying Kuparuk "A" shallow marine sands which are thought to be truncated in the Western portion of the SMU. The Kuparuk "A" sand is overlain by the Kuparuk "C" which is a transgressive sand deposited on the regional Lower Cretaceous Unconformity. The Kuparuk "C' and underlying Kuparuk "A" members of the Cretaceous age Kuparuk formation consist of very fine to coarse grained sandstones and siltstones. Within the proposed development area, the combined thickness of the two members ranges from 0 to over 80 feet. Figure G2 shows the expected isochore of the Kuparuk "C', which is the primary reservoir in the area ranging from 0 to as much as 35 feet thick. Thickness is estimated from well data and seismic signature. Figure G-3 shows the expected isochore of the Kuparuk "A" reservoir, ranging from 0 to as much as 80 feet thick. The Kuparuk A" reservoir thins to the west as it is truncated by the Lower Cretaceous Unconformity. Sedimentolo The Kuparuk "C" sandstones are fine to coarse-grained, composed of quartz and up to 40% structural glauconite, and are commonly cemented with secondary siderite (the ubiquitous precipitate in North Slope reservoir sandstones), Porosity averages 22% and permeabilities range from 50 to hundreds of mD in the Kuparuk "C" averaging 70 mD in the Mustang area. The Kuparuk "A" sandstone are very fine to fined grained sandstone interbedded with siltstone and mudstones. Porosity averages 22%, but the permeability is lower than the Kuparuk "C" member ranging from less than 30 mD to 100mD, averaging 30 mD. Strutture and Trap Te Kuparu Poo within the SMU ranges in depth from -5800 to -6400' TVDSS. Oil is trapped within the regional structural trap formed by the Colville Anticline. There is no oil -water contact in the proposed Area Injection Order. The Kuparuk reservoirs in the SMU are well above the known oil -water contact of the Kuparuk oil Pool, which Range in depth from 6530' TVDss to 6650' TVDss in the KRU and are deeper than this to the Northeast in the Milne Point Unit. Defining Net Pay Net pay is general defined by Gamma Ray, Resistivity and Porosity logs. Water saturation in the Kuparuk "C" can be as low as 20%, while water saturations in the Kuparok "A" areas high as 40%. Net Pay cutoffs of about 15% porosity and 35% water saturation are assumed for purposes of volumetric calculations and are consistent with petrophysical evaluations which suggest these cutoffs are good indicators of net pay in the Kuparuk "C" sand. "-N1 Section G — Formation Geology G-4: Kuparuk "AY' Reservoir Isochore Stratigraphy Figure GS shows the depositional model for Kuparuk Formation, which consists of the underlying Kuparuk "A" shallow marine sands which are thought to be truncated in the Western portion of the SMU. The Kuparuk "A" sand is overlain by the Kuparuk "C" which is a transgressive sand deposited on the regional Lower Cretaceous Unconformity. The Kuparuk "C" and underlying Kuparuk "A" members of the Cretaceous age Kuparuk formation consist of very fine to coarse grained sandstones and siltstones. Within the proposed development area, the combined thickness of the two members ranges from 0 to over 80 feet. Figure G2 shows the expected isochore of the Kuparuk "C', which is the primary reservoir in the area ranging from 0 to as much as 35 feet thick. Thickness is estimated from well data and seismic signature. Figure G-3 shows the expected isochore of the Kuparuk "A" reservoir, ranging from 0 to as much as 80 feet thick. The Kuparuk A" reservoir thins to the west as it is truncated by the Lower Cretaceous Unconformity. Sedimentolo The Kuparuk "C'sandstones are fine to coarse-grained, composed of quartz and up to 40%structuraI glauconite, and are commonly cemented with secondary siderite (the ubiquitous precipitate in North Slope reservoir sandstones). Porosity averages 22% and permeabilities range from 50 to hundreds of mD in the Kuparuk "C' averaging 70 mD in the Mustang area. The Kuparuk "A" sandstone are very fine to fined grained sandstone interbedded with siltstone and mudstones. Porosity averages 22%, but the permeability is lower than the Kuparuk "C" member ranging from less than 10 mD to 100mD, averaging 30 mD. Structure and_Tra T e Kuph aruk Pool within the SMU ranges in depth from-5800to -6400' TVDSS. Oil is trapped within the regional structural trap formed by the Colville Anticline. There is no oil -water contact in the proposed Area Injection Order. The Kuparuk reservoirs in the SMU are well above the known oil -water contact of the Kuparuk Oil Pool, which Range in depth from 6534 TVDss to 6650' TVDss in the KRU and are deeper than this to the Northeast in the Milne Point Unit. Defining Net Pa Net pay is general defined by Gamma Ray, Resistivity and Porosity logs. Water saturation in the Kuparuk "C" can be as low as 20%, while water saturations in the Kuparuk "A" are as high as 40%. Net Pay cutoffs of about 15% porosity and 35% water saturation are assumed for purposes of volumetric calculations and are consistent with petrophysical evaluations which suggest these cutoffs are good indicators of net pay in the Kuparuk "C" sand. 11 Section G — Formation Geology O-5: Cross Section, Flattened on the LCU, across the AIO area (Outlined in red on map). Log Curves include gamma my and deep resistivity in TVDss and measured depth Stratlgraphy Figure G3 shows the depositional model for Kuparuk Formation, which consists of the underlying Kuparuk "A" shallow marine sands which are thought to be truncated in the Western portion of the SMU. The Kuparuk "A" sand is overlain by the Kuparuk "C" which is a transgressive sand deposited on the regional Lower Cretaceous Unconformity. The Kuparuk "C" and underlying Kuparuk "A" members of the Cretaceous age Kuparuk formation consist of very fine to Coarse grained sandstones and siltstones. Within the proposed development area, the Combined thickness of the two members ranges from 0 to over 80 feet. Figure G2 shows the expected isochore of the Kuparuk "C", which Is the primary reservoir in the area ranging from 0 to as much as 35 feet thick. Thickness is estimated from well data and seismic signature, Figure G-3 shows the expected isochore of the Kuparuk "A" reservoir, ranging from 0 to as much as 80 feet thick. The Kuparuk A" reservoir thins to the west as it is truncated by the Lower Cretaceous Unconformity. Sedimentologv The Kuparuk "C" sandstones are fine to coarse-grained, composed of quartz and up to 40% structural glauconite, and are commonly cemented with secondary siderite (the ubiquitous precipitate in North Slope reservoir sandstones). Porosity averages 22% and permeabilities range from 50 to hundreds of mD in the Kuparuk "C" averaging 70 mD in the Mustang area. The Kuparuk "A" sandstone are very fine to fined grained sandstone interbedded with siltstone and mudstones. Porosity averages 22%, but the permeability is lower than the Kuparuk "C' member ranging from less than SO mD to 100mD, averaging 30 MD. Structure and Tra 7 e Kuparu Poo within the SMU ranges in depth from-5800to -6400' TVDSS. Oil is trapped within the regional structural trap formed by the Colville Anticline. There is no oil -water contact in the proposed Area Injection Order. The Kuparuk reservoirs in the SMU are well above the known oil -water contact of the Kuparuk Oil Pool, which Range in depth from 6530' TVDss to 6650' TVDss in the KRU and are deeper than this to the Northeast in the Milne Point Unit. Defining Net Pa Net pay is general defined by Gamma Ray, Resistivity and Porosity logs. Water saturation in the Kuparuk "C" can be as low as 20%, while water saturations in the Kuparuk "A" are as high as 40%. Net Pay cutoffs of about 15% porosity and 35% water saturation are assumed for purposes of volumetric calculations and are consistent with petrophysical evaluations which suggest these cutoffs are good indicators of net pay in the Kuparuk "C" sand. 12 Section G — Formation Geology ,s Q G-6: Lower Cretaceous Unconformity (LCU)/Kuparuk "C" Structure Grid Stratieraohv Figure G3 shows the depositional model for Kuparuk Formation, which consists of the underlying Kuparuk "A" shallow marine sands which are thought to be truncated in the Western portion of the SMU. The Kuparuk "A" sand is overlain by the Kuparuk "C" which is a transgressive sand deposited on the regional Lower Cretaceous Unconformity. The Kuparuk "C" and underlying Kuparuk "A" members of the Cretaceous age Kuparuk formation consist of very fine to coarse grained sandstones and siltstones. Within the proposed development area, the combined thickness of the two members ranges from 0 to over 80 feet. Figure G2 shows the expected isochore of the Kuparuk "C", which is the primary reservoir in the area ranging from 0 to as much as 35 feet thick. Thickness is estimated from well data and seismic signature. Figure G-3 shows the expected isochore of the Kuparuk "A" reservoir, ranging from 0 to as much as 80 feet thick. The Kuparuk A" reservoir thins to the west as it is truncated by the Lower Cretaceous Unconformity. Sedimentolo The Kuparuk "C" sandstones are fine to coarse-grained, composed of quartz and up to 40% structural glauconite, and are commonly cemented with secondary siderite (the ubiquitous precipitate in North Slope reservoir sandstones). Porosity averages 22% and permeabilities range from 50 to hundreds of mD in the Kuparuk "C" averaging 70 mD in the Mustang area. The Kuparuk "A" sandstone are very fine to fined grained sandstone interbedded with siltstone and mudstones. Porosity averages 22%, but the permeability is lower than the Kuparuk "C" member ranging from less than 10 mD to 100mD, averaging 30 mD. Structure�and Trap T e Kuph aruk Pool within the SMU ranges in depth from -5800 to -6400' TVDSS. Oil is trapped within the regional structural trap formed by the Colville Anticline. There is no oil -water contact in the proposed Area Injection Order. The Kuparuk reservoirs in the SMU are well above the known oil -water contact of the Kuparuk Oil Pool, which Range in depth from 653U TVDss to 6650' TVDss in the KRU and are deeper than this to the Northeast in the Milne Point Unit. Definine Net Pa Net pay is general defined by Gamma Ray, Resistivity and Porosity logs. Water saturation in the Kuparuk "C" can be as low as 20.0/, while water saturations in the Kuparuk "A" are as high as 40%. Net Pay cutoffs of about 15% porosity and 35% water saturation are assumed for purposes of volumetric calculations and are consistent with petrophysical evaluations which suggest these cutoffs are good indicators of net pay in the Kuparuk "C" sand. 13 /v'SV Section H — Logs of Injection Wells To date, two wells within the SMU have been drilled and are Intended to be utilized for injection. The well logs and well histories for these wells, North Tam #1A and SMU M. 02, have been submitted and are on file with the AOGCC 14 Section I — Design and Mechanical Integrity of Injection Wells 1-1: Generic SMU Kuparuk Pool Injector 4 String Casing Well Design The well design for the SMU Kuparuk Oil Pool well (Figurel-1) are like the other Kuparuk Oil Pools drilled within the adjacent Kuparuk River Unit 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 approximately 1250' TVDss. Intermediate casing strings will be set and cemented to isolate problematic shales zones and to optimize drilling through these zones. Any significant hydrocarbon bearing zones found in the borehole above the Kuparuk 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 SMU Kuparuk Oil Pool will likely be developed in one of two methods. The first type will be comprised of solid liners including pre -perforated pup joints and/or sliding sleeves. This completion will be utilized where hydraulic fracturing is needed to enhance productions. The other type of completion will utilize uncemented slotted liners where fracture stimulation is not needed. Tubing sizes will be determined to optimize expected production and injection rates. In lieu of the packer depth requirement under 20 AAC 25.412(b) specifying packer depth within 200ft measured depth from above the top of the perforations, BRPC request 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 shale have outer casing cement volume sufficient to place cement a minimum of 300' measured depth above the planned packer depth. Since the Kuparuk Oil Pool injectors are planned as horizontal wells, stimulation optimization efforts and well work feasibility may be impeded if the packer/isolation 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 operation will be performed in accordance with 20 ACC 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 SMU Kuparuk 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 15 A),N'Ila Section J —Injection Fluids rrrw�4 'a�Yw errwusrr •rOYxrr faYsv4 WYNSTswnMntlq cur ru � tsr agenes�rw ..a.u.w u w 'reNtl ZdL6x usn .m WNN �vs or ua r -x .w alb J-1: Kuparuk Seawater Treatment Plant Water Composition Waterflooding will he Implemented as the Initial enhanced recovery mechanism for the proposed SMU Kuparuk 011 Pool with the use of both produced water and treated seawater. Seawater will be delivered through a pipellne spur off the nearby Alpine water pipeline. Additionally, waterflooding maybe followed later with either lean gas or m6 ble gas Injection to further Improve recovery. Other fluids may also be Injected for reservoir stimulation, reservoir performance, evaluation, freeze protection, or Nemlml Inhibition; however, these fluids are not planned for continuous Injectlon as a means for enhanced recovery. The volumes of these other fluids are expected to be less than D.1% of the total volume Injected and are not expected to hinder the recovery, efgclency of the proposed SMU Kuparuk Oil Pool. Types and sources of fluids requested for Injection are (compositions Included for fluids that may be dedicated Intention fluids): 011 pool. Fluld Compatibility Dispersed day in the sandstone layers Is not prone to swelling when in contact with typical Injection water salinities expected to be used in the SMU Kuparuk Oil Pool. Analyses of formation water samples collected from the Kuparuk producers within the KRU Indicate the potential for moderate scaling during production and when the formation water tubes with seawater. The ipeCglc sale risks are listed below. Produced Water Injection BaSO4 and CaCO3 Scale risks are minimized as the injection water going deeper Into formation Seawaterlojection BaSO4 risk Is high from wellbore througghout the mixing zone CaCO3 risk s minor In reservoir beyanE the near wellbore area Scaling mitigation measures Include placement of aqueous and solid phase scale inhibitors In facture treatments, conventional squeeze treatments, and chemical Injection In the wells and at the surface. The analyses of the fo Mlon water samples listed above Indicate that the sale risk Is expected to be controlled utilizing these measures. Fleltl injectivity data from analogous reservoirs (The Kuparuk River Field, Kuparuk Pact and Nanuq/Kupamk In the Colville River Field) suggest limited permeability degradation will occur with property treated Injection flultls. No co=vIbility Issues between Injection gas and Kuparuk Reservoir fluids have been Idents led. 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 conductivltywithin the fracture through the life of the well. Hydraulic stimulation operations will be performed N accordance with 20AAC 25.283. Hydraullcstlmulatlon formulations may be adjusted as new technologies emerge and as the reservoir charachedzation 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 het of gas perday; however, Injection rates will be confined by Injection pressures as to not exceed the overburden pressure gradient and muse ffxctures to penetrate through the confinement layer 16 /\�/Section J — Injection Fluids L�gYXN�W:S:0Sa0.Wa sX,EYwmeme..Xmnms o�mXa. m, mfW"NW —a all SemlYebK21p9M Lne. dR Y,M. 3w. MNMNk vvm... ae, Mr za_.cY uma.. oetm.'auase .111pee2ta to a_ 6EY saw fe AepEmNl Yf Wi ,O CEAs �'� mluC en M, enmuru„n� ! • mnl„mT y, AWvllmn uua mwu.E OP rp, owmrt emm n/ev sevPrary'm ertweouvm •eon fanaY.m'fw ra, J-2; Kuparuk Gas Injectant Composition Waterflooding will be Implemented as the Initial enhanced recovery mechanism for the proposed SMU Kuparuk 011 Pool with the use of both produced water and treated seawater. Seawater wig be delivered through a pipeline spur off the nearby Alpine water pipeline. Additionally, waterflooding maybe followed later with either loan gas or miscible gas Injectlon to further Improve recovery. Other fluids may also be Injected for reservoir stimulation, reservoir performance, mivatlon, freeze protection, or chemloal 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 SMU Kuparuk Oil Pool. Types and sources of fluids requested for Injection are hchni, sltlem Included for fluids that may be dedicated Injection fluids): Kuparuk Oil Pool. tre 131 Fluid Compatibility Okpersed day In the sandstone layers is not prone to swelling when In contact with typical Injection water salinities expected to be wed In the SMU Kuparuk 011 Pool. Analyses of formation watersamples collected from the Kuparuk producers within the KRU Indicate the potential for moderate scaling during Production and when the formation water mixes with seawater. The specific wale risks are listed below. Produced Water Injedlon Basin and C 003 Scale risks are minimized as the Injection water going deeper Into formation Seawater Injection 1:SOC risk is high from well throughout the mixing zone CaCO3 risk Is minor In reservoir beyontl the near wellbore area "Ing nn tlgation measures Include placement of aqueous and solid phase wale Inhibitors In fracture tm hnnm m.. No compatibility Issues 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 ronMed by injection pressures as to not exceed the overburden pressure gradient and cause fractures to Penetrate through the confinement layer 17 Section J — Injection Fluids rµu mm mu�ry ammo ru. o.Fc..�v vgawvrti140imYv 9Ytlekyal wa�Y v' .avNY ovuw unrv. .., s.n W na W. fuy.vnn Uanvwrun muu a,. rtn. n:Lnn arv......w run .•• •Y• vWidal WWVVtlwa M14CMA'Ei0 J-3: Kuparuk Pool Produced Water Composition Waterflooding will be implemented as the Initial enhanced recovery mechanism for the proyused SMU Kuparuk 011 Pool with the use of both produced water and treated seawater. seawater will be delivered through a plpeline spur of the nearby Alpine water plpellne. Additionally, waterBonding may be followed later with either lean gas or miscible gas Injection to further Improve recovery. Other fluids may also be Injected far reservoir stimulation, reservoir performance, evaluation, freeze protection, or chemical Inhibition; however, these fluids are not panned 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 SMU Kupamk 011 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 reatment plain (composition listed In Figure 1-1) Produced water from all present and yet-to.be defined oil pools within the SMU Kupamk River Field, Including without (Imitation the Kupaiuk Oil Pool. Enriched hydrocarbon las (MI): Blend of KRU lean gas with Indigenous and/or Imported natural gas liquids (composition listed In Figure 1-3) Lean gas (composition las In Figure 1-3) Fluids wed during hydraulic stimulation Tracer survey fluids to monitor reservoir performance (chemical, radioactive, etc.) Fluids used to improve rear wellboreInlettivky (We use of acid or similar treatment) Fluids used to seal wellbore Intervals Ich negatively Impact recovery efficiency (cement resin, etc.) Fluids associated with freeze protection (diesel, glycol, methanol, etc.) Standard oigleld chemicals (comosion inhibitor, scale Inhibitor, eri Fluid Camaat AITv Dispersed day In the sandstone layers IS not prone to swelling when In contact with typical Injection water salinities expected to be used In the SMU Kuparuk Oil Pool. Analyses of formation water samples collected from the Kuparuk producers within the KRU Indicate the Potential for moderate waling during production and when the formation water mixes with seawater. The specific scale risks are Ikted below. Produced Water Injection BaS06 and CaCO3 Sale risks are minimized as the Injection water going deeper Into formation Seawa[erinjectlon B.SO4 risk is high from wellbore throughout the mixing zone Ca003 risk Is minor in reservoir beyond the near wellbore area saling mitigation measures Include placement of aqueous and solid phase sale 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 Injectivlty data from analogous reservoirs (The Ku)amk River Field, Kupamk Pool and Nanuq/Kuparuk in she Colville River Field) suggest limited permeability degradation will occurwith properly treated Injection flulds. No compatibility Issues between Injection gas and KuParuk Reservoir fluids have been Identified, Fluids used far hydraulic stimulation are planned to include a mixture or weer IsrxAwaror eaa.�m. • ....-..- munwannor may ox aoiumea as new recnnolpgles emerge arm 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 conflned by Injection pressures as to nor exceed the overburden pressure gradient and cause fractures to penetrate through the confinement layer i] v\, Section K—SMU Kuparuk Oil Pool Injection Pressure Summary Figure K-1: SMU Kuparuk Oil Pool Injection Pressure Summary Injealon Type Estimated Wellhead Estimated Bottom -hole Pressure(PSIA) Pressure Malmum' Average* Maxlmum'• Avera e• Water Injection 1400 I 2000 I4000 9623 *Basad on current operations at a true vertical depth of 6100 feet *' Maximums vary acrording to actual depth Assumptions: Datum (TVDss) 6100 Average Injection Gradient 0.62 Maximum injection Gradient 0.67 overburden Pressure Gradient 0.72 CPF-3 Fluid Gradient (Water) 0.442 Gas Gradient (Fall 0.15 Calculations: Bottom Hole Pressure (BHP)=Datum (TVDss)'Injecden Gradient (Water or MI) Hydrostatic Pressure= Datum ITVDss) • Fluid Gradient Well Head Pressure (WHP)=BHP-Hydrostatic Pressure BRPC proposes to develop the SMU Kuparuk Oil Pool using a waterflood and 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 nearby core data, is 0.72 psi/ft. To ensure containment of injected fluids within the SMU Kuparuk Oil Pool, injection pressures will be managed as to not exceed the maximum injection gradient of 0.67 psi/ft. 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. 19 ^YNN Section L— Fracture Containment Modeling SUMMARY e Modeling the growth of hydraulic fractures induced by water injection into the Kuparuk C zone was conducted using the threedimensional numerical simulator GOHFER. Results suggest that hydraulic fractures can be created and extended within the Kuparuk A4 and C formations if water injection is conducted at surface pressures above 1700-2000 psi. This modeling also indicated that created fractures would be contained within the Kuparuk interval unless the surface injection pressure rises to more than 2700-3000 psi. • Modeling is based on worst case scenario for fracture containment which is a single point of injection rather than multiple injection points within the Kup C interval. An Internal containment assurance analysis, conducted through BRPC, Indicates that the estimated maximum injection pressures for the Kuparuk wells (listed in Section K) in WAG 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 fracture model built based on the nearby KRU 2S-13pbl well log data and calibrated by using data from nearby geo-mechanical tests and pressure history matched data from the North Tarn Ill fracture stimulation 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 Kuparuk Oil Pool without risk of breaking through overburden or under -burden containment zones. The frac modelling software used was version was the Grid Oriented Hydraulic Fracture Extension Replicator (GOHFER), due to its reliability and common use by North Slope operators 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. Modeling the growth of hydraulic fractures induced by water injection into the Kuparuk C zone was conducted using the three-dimensional numerical simulator. Results suggest that hydraulic fractures can be created and extended within the Kuparuk A and C formations if water Injection Is conducted at surface pressures above 1700-2000 psi. This modeling also indicated that created fractures would be contained within the Kuparuk Interval unless the surface injection pressure rises to more than 2700.3000 psl. Based on the computed and calibrated stress profile, and the model results presented here, it is possible to Initiate and propagate fractures with water Injection in the Kuparuk formation at surface pressures up to 2000 psi, with all created fractures contained within the sands by the In-situ stress contrast between the sands and bounding slit/shale layers. An increase in fracture treating pressure of more than 10DO psi above the stable fracture extensionpressure Indicated by the model is required before excessive fracture height growth develops. The calibrated stress and fracture model predict height containment within each reservolr Interval. It Is not able to accurately predict the lateral extent of the created fractures. Rate of fracture extension (laterally) depends primarily on the balance between Injection rate and leakoff rate to the surrounding formation. This can be affected by spatlaI changes in pore pressure and reservoir quality, and by progressive plugging or damage to the formation sand -face caused by Infected suspended solids and contaminants. To study how fractures are Initiated during injection In the Kuparuk Resennor and whether they can be effectively contained within the target Interval, the following cases were simulated for a horizontal well penetrating and Injecting Into a single point within the Kuparuk "C". Single point Injection models the worst-case scenario for the Induced pressure on the confining layers. In practice, Injecting along the length of the lateral will result in less fracture height growth at each point. Injection at a single point would lead to the most fracture growth in the zone. Increasing the number of Injection points in the well will decrease the possibility of fracturing out of zone. 1) Water Injection without propped fracture at 3,000 bpd (Figure L-1,2,3,4,) 2) Water Injection without propped fracture at 6,000 bpd (Figure L-5,6) The above simulations indicate that injection Induced fractures will be contained within the Kuparuk Reservoir, no breakthrough of the overburden or under -burden containment zones will occur. 20 Section L— Fracture Containment Modeling MECHANICAL -- MODEL-2S-13PB1 -'o - - _ • Best and closest analog for 3 injection wells was 2S- 13PB1 Poisson's ratio derived from shear compressional ratio Young's modulus derived from shear compressional ratio and density log Conversion to static Young modulus using Eiza transform Pore pressure set to normally pressured - — - ---, _ -- Figure L-1: Well log from 2S-13PB1 used in GOHFER fracture analysis An Internal containment assurance analysis, conducted through BRPC, Indicates that the estimated maximum Injection pressures for the Kuparuk wells (listed in Section K) in WAG 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 fracture model built based on the nearby KRU 2S-13pb1 well log data and calibrated by using data from nearby geo-mechanical tests and pressure history matched data from the North Tarn #1 fracture stimulation 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 Kuparuk Oil Pool without risk of breaking through overburden or under -burden containment zones. The frac modelling software used was version was the Grid Oriented Hydraulic Fracture Extension Repllcator (GOHFER), due to its reliability and common use by North Slope operators as well as in the fracturing Industry. GOWER Is a planar 3-D geometry fracture simulator developed by Barree & Associates In association with Stlm-lab and Is commercially available throughout the industry for performing hydraulic fracture simulation work. Modeling the growth of hydraulic fractures induced by water Injection Into the Kuparuk C zone was conducted using the three-dimensional numerical simulator. Results suggest that hydraulic fractures can be created and extended within the Kuparuk A and C formations if water Injection Is conducted at surface pressures above 1700.2000 psi. This modeling also Indicated that created fractures would be contained within the Kuparuk Interval unless the surface injection pressure rises to more than 2700-3000 psi. Based on the computed and calibrated stress profile, and the model results presented here, It Is possible to initiate and propagate fractures with water Injection in the Kuparuk formation at surface pressures up W 2000 psi, with all created fractures contained within the sands by the In-situ stress contrast between the sands and bounding silt/shale layers. An increase in fracture treating pressure of more than 1000 psi above the stable fracture extension pressure Indicated by the model Is required before excessive fracture height growth develops. The calibrated stress and fracture model predict height containment within each reservoir interval. It Is not able to accurately predict the lateral extent of the created fractures. Rate of fracture extension (laterally) depends primarily on the balance between injection rate and leakoff rate to the surrounding formation. This can be affected by spatial changes In pore pressure and reservoir quality, and by progressive plugging or damage to the formation sand -face "used by Injected suspended solids and contaminants. To study how fractures are Initiated during injection In the Kuparuk Reservoir and whether they can be effectively contained within the target Interval, the following cases were simulated for a horizontal well penetrating and Injecting Into a single point within the Kuparuk "C". Single point Injection models the worst-case scenario for the induced pressure on the confining layers. In practice, Injecting along the length of the lateral will result in less fracture height growth at each point. Injection at a single point would lead to the most fracture growth in the zone. Increasing the number of Injection points In the well will decrease the possibility of fracturing out of zone. 1) Water Injection without propped fracture at 3,000 bpd (Figure L-1,2,3,4,) 2) Water Injection without propped fracture at 6,000 bpd (Figure L -S,6) The above simulations Indicate that injection Induced fractures will be contained within the Kuparuk Reservoir; no breakthrough of the overburden or under -burden containment zones will occur. 21 Section L — Fracture Containment Modeling PHANTOM - FF - INJECTION INTO KUPARUK C F- ure L-2• Madog f in I oint esti n int tit K aruk 1�gure L-?: TVlodepoi�slf�gl�poln� jecilon Inoto tie Hparuk C" An Internal containment assurance analysis, conducted through BRPC, Indicates that the estimated maximum Injection pressures for the Kuparuk 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 fracture model built based on the nearby KRU 2S-13pb1 well log data and calibrated by using data from nearby geo-mechanical tests and pressure history matched data from the North Tarn #1 fracture stimulation 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 Kuparuk Oil Pool without risk of breaking through overburden or under -burden containment zones. The frac modelling software used was version was the Grid Oriented Hydraulic Fracture Extension Replicator (GOHFER), due to its rel lability and common use by North Slope operators as well as in the fracturing industry. GOWER Is a planar 3-D geometry fracture simulator developed by Barnes, & Associates in association with Stim-lab and Is commercially available throughout the Industry for performing hydraulic fracture slmulation work. Modeling the growth of hydraulic fractures Induced by water injection Into the Kuparuk C zone was conducted using the three-dimensional numerical simulator. Results suggest that hydraulic fractures can be created and extended within the Kuparuk A and C formations if water Injection Is conducted at surface pressures above 1700-2000 psi. This modeling also Indicated that created fractures would be contained within the Kuparuk Interval unless the surface Injection pressure rises to more than 2700.3000 psi. Based on the computed and calibrated stress profile, and the model results presented here, it Is possible to initiate and propagate fractures with water Injection In the Kuparuk formation at surface pressures up to 2000 psi, with all created fractures contained within the sands by the in-sau stress contrast between the sands and bounding slit/shale layers. An increase in fracture treating pressure of more than 1000 psi above the stable fracture extension pressure Indicated by the model is required before excessive fracture height growth develops, The calibrated stress and fracture model predict height containment within each reservoir Interval. It is not able to accurately predict the lateral extent of the created fractures. Rate of fracture extension (laterally) depends primarily on the balance between Injection rate and leakoff rate to the surrounding formation. This can be affected by spatial changes in pore pressure and reservoir quality, and by progressive plugging or damage to the formation sand -face caused by Injected suspended solids and contaminants. To study how fractures are initiated during Injection in the Kuparuk Reservoir and whether they can be effectively contained within the target Interval, the following cases were simulated for a horizontal well penetrating and injecting Into a single point within the Kuparuk "C". Single point injection models the worst-case scenario for the Induced pressure on the confining ayers. In practice, Injecting along the length of the lateral will result In less fracture height growth at each point. Injection at a single point would lead to the most fracture growth in the zone. Increasing the number of injection points in the well will decrease the possibility of fracturing out of zone. 1) Water Injection without propped fracture at 3,000 bpd (Figure L -1,2,3A) 2) Water Injection without propped fracture at 6,000 bpd (Figure L-5,6) The above simulations indicate that injection Induced fractures will be contained within the Kuparuk Reservoir, no breakthrough of the overburden or under -burden containment zones will occur. 22 n-/� Section L—Fracture Containment Modeling PHANTOM FF — INJECTION PRESSURE AT 3000 BPD rm.. ras = a� Figure L-3: Injection pressure modeled at 3000 BOPD An internal containment assurance analysis, conducted through BRPC, indicates that the estimated maximum injection pressures for the Kuparuk 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 fracture model bulk based on the nearby KRU 2S-13pb1 well log data and calibrated by using data from nearby geo-mechanical tests and pressure history matched data from the North Tarn #1 fracture stimulation 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 Kuparuk Oil Pool without risk of breaking through overburden or under -burden containment zones. The frac modelling software used was version was the Grid Oriented Hydraulic Fracture Extension Replicator (GOHFER), due to its reliability and common use by North Slope operators as well as In the fracturing Industry. GOWER is a planar 3-D geometry fracture simulator developed by Berms &Associates in association with Stim-lab and is commercially available throughout the Industry for performing hydraulic fracture simulation work. Modeling the growth of hydraulic fractures induced by water Injection into the Kuparuk Czone was conducted using the three-dimensional numerical simulator. Results suggest that hydraulic fractures can be created and extended within the Kuparuk A and C formations if water Injection Is conducted at surface pressures above 1700-2000 psi. This modeling also Indicated that created fractures would be contained within the Kuparuk interval unless the surface Injection pressure rises to more than 2700-3000 psi. Based on the computed and call brated stress profile, and the model results presented here, it is possible to Initiate and propagate fractures with water injection in the Kuparuk formation at surface pressures up to 2000 psi, with all created fractures contained within the sands by the in-situ stress contrast between the sands and bounding slit/shale layers. An Increase In fracture treating pressure of more than 1000 psi above the stable fracture extension pressure Indicated by the model is required before excessive fracture height growth develops. The calibrated stress and fracture model predict height containment within each reservoir Interval. It Is notable to accurately predict the lateral extent of the created fractures. Rate of fracture extension (laterally) depends primarily on the balance between Injection rate and leakoff rate to the surrounding formation, This can be affected by spatial changes In pore pressure and reservoir quality, and by progressive plugging or damage to the formation sand -face caused by Injected suspended solids and contaminants. To study how fractures are Initlated during injection in the Kuparuk Reservoir and whether they can be effectively contained within the target Interval, the following cases were simulated for a horizontal well penetrating and Injecting Into a single point within the Kuparuk "C. Single point Injection models the worst-case scenario for the Induced pressure on the confining layers. In practice, injecting along the length of the lateral will result in less fracture height growth at each point. Injectlon at a single point would lead to the most fracture growth in the zone. Increasing the number of injection points In the well will decrease the possibility of fracturing out of zone, 1) Water Injection without propped fracture at 3,000 bpd (Figure L-1,2,3,4,) 2) Water Injection without propped fracture at 6,000 bpd (Figure L-5,6) The above simulations indicate that Injection Induced fractures will be contained within the Kuparuk Reservoir; no breakthrough of the overburden or under -burden containment zones will occur. 23 Section L — Fracture Containment Modeling 3000 BPD INJECTION RATE - FRACTURE GEOMETRY Figure L-4: Fracture geometry, exhibiting containment within the Kuparuk formation at 3000 BOPD An Internal containment assurance analysis, conducted through BRPC, Indicates that the estimated maximum Injection pressures for the Kuparuk 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 fracture model bulli based on the nearby KRU 2S-13pb1 well log data and calibrated by using data from nearby geo-mechanical tests and pressure history matched data from the North Tarn Ri fracture stimulation 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 Kuparuk Oil Pool without risk of breaking through overburden or under -burden containment zones. The frac modelling software used was version was the Grid Oriented Hydraulic Fracture Extension Replicator (GOHFER), due to Its reliability and common use by North Slope operators as well as in the fracturing Industry. GOWER 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. Modeling the growth of hydraulic fractures Induced by water Injection Into the Kuparuk C zone was conducted using the three-dimensional numerical simulator, Results suggest that hydraulic fractures can be created and extended within the Kuparuk A and C formations if water Injection Is conducted at surface pressures above 1700-2000 psi. This modeling also indicated that created fractures would be contained within the Kuparuk Interval unless the surface injection pressure rises to more than 2700-3000 psi. Based on the computed and calibrated stress profile, and the model results presented here, It is possible to Initiate and propagate fractures with water Injection in the Kuparuk formation at surface pressures up to 2000 psi, with all created fractures contained within the sands by the in-situ stress contrast between the sands and bounding silt/shale layers. An Increase in fracture treating pressure of more than 1000 psi above the amble fracture extension pressure indicated by the model Is required before excessive fracture height growth develops. The calibrated stress and fracture model predict height containment within each reservoir Interval. It Is not able to accurately predict the lateral extent of the created fractures. Rate of fracture extension (laterally) depends primarily on the balance between Injection rate and leakoff rate to the surrounding formation. This can be affected by spatial changes in pore pressure and reservoir quality, and by progressive plugging or damage to the formation sand -face caused by Injected suspended solids and contaminants. To study how fractures are Initiated during Injectlon In the Kuparuk Reservoir and whether they can be effectively contained within the target Interval, the following cases were simulated for a horizontal well penetrating and injecting Into a single point within the Kuparuk "C". Single point Injection models the worst-case scenario for the Induced pressure on the confining layers. In practice, Injecting along the length of the lateral will result In less fracture height growth at each point. Injection at a single point would lead W the most fracture growth in the zone. Increasing the number of Injection points in the well will decrease the possibility of fracturing out of zone. 1) Water Injection without propped fracture at 3,000 bpd (Figure L-1,2,3,4,) 2) Water Injection without propped fracture at 6,000 bpd (Figure L-5,6) The above simulations Indicate that Injection induced fractures will be contained within the Kuparuk Reservoir; no breakthrough of the overburden or under -burden containment zones will occur. 24 Section L— Fracture Containment Modeling PHANTOM FF - INJECTION PRESSURE AT 6000 BPD 2 E I' ewW �Imnurt Figure L-5: Injection pressure modeled at 6000 BOPD An internal containment assurance analysis, conducted through BRPC, indicates that the estimated maximum injection pressures for the Kuparuk wells (listed in Section K) In WAG 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 fracture model built based on the nearby KRU 2S-13pb1 well log data and calibrated by using data from nearby geo-mechanical tests and pressure history matched data from the North Tarn #1 fracture stimulation 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 Kuparuk Oil Pool without risk of breaking through overburden or under -burden containment zones. The frac modelling software used was version was the Grid Oriented Hydraulic Fracture Extension Replicator (GOHFER), due to its reliability and common use by North Slope operators as well as in the fracturing Industry. GOHFER is a planar 3-D geometry fracture simulator developed by Barree & Associates in association with Stlm-lab and is commercially available throughout the Industry for performing hydraulic fracture simulation work. Modeling the growth of hydraulic fractures Induced by water injection Into the Kuparuk C zone was conducted using the three-dimensional numerical simulator. Results suggest that hydraulic fractures can be created and extended within the Kuparuk A and C formations H water Injection Is conducted at surface pressures above 1700-2000 psi. This modeling also Indicated that created fractures would be contained within the Kuparuk Interval unless the surface injection pressure rises to more than 2700-3000 psi. and calibrated stress profile, and the model results presented here, it is possible to Initiate and propagate fractures with Iparuk formation at surface pressures up to 2000 psi, with all created fractures contained within the sands by the Insltu the sands and bounding silt/shale layers. An increase in fracture treating pressure of more than 1000 psi above the stable ure indicated by the model is required before excessive fracture height growth develops. The calibrated stress and fracture ttainment within each reservoir Interval. It is not able to accurately predict the lateral extent of the created fractures. m (laterally) depends primarily on the balance between injection rate and leakoff rate to the surrounding formation. This it changes in pore pressure and reservoir quality, and by progressive plugging or damage to the formation sand -face caused )lids and rnMamlmMe To study how fractures are initiated during in'ectlon In the Kuparuk Reservoir and whether they can be effectIvely contained within the target Interval, the following cases were simulated �or a horizontal well penetrating and in acting Into a single point within the Kuparuk "C". Single point Injection models the worst-case scenario for the Induced pressure on the confining layers. In practice, Injecting along the length of the lateral will result in less fracture height growth at each point. Injection at a single point would lead to the most fracture growth in the zone. Increasing the number of Injection points In the well will decrease the possibility of fracturing out of zone. 1) Water Injection without propped fracture at 3,000 bpd (Figure L-1,2,3,4,) 2) Water Injection without propped fracture at 6,000 bpd (Figure L-5,6) The above simulations indicate that Injection Induced fractures will be contained within the Kuparuk Reservoir, no breakthrough of the overburden or under -burden containment zones will occur. *1 /1 \ Section L — Fracture Containment Modeling 6000 BPD - INJECTION RATE - FRACTURE GEOMETRY Figure L-6: Water Injection Without Propped Fracture At 6,000 BPD An Internal containment assurance analysis, conducted through BRPC, indicates that the estimated maximum Injection pressures for the Kuparuk 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 fracture model bulk based on the nearby KRU 25-13pb1 well log data and calibrated by using data from nearby geo-mechanical tests and pressure history matched data from the North Tarn al fracture stimulation 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 Kuparuk Oil Pool without risk of breaking through overburden or under -burden containment zones. The frac modelling software used was version was the Grid Oriented Hydraulic Fracture Extension Replicator (GOHFER), due to Its reliability and common use by North Slope operators as well as in the fracturing Industry. GOHFER Is a planar 3-0 geometry fracture simulator developed by Barree &Associates In association with Stim-lah and Is commercially available throughout the Industry for performing hydraulic fracture simulation work. Modeling the growth of hydraulic fractures Induced by water Injection Into the Kuparuk C zone was conducted using the three-dimensional numerical simulator. Results suggest that hydraulic fractures can be created and extended within the Kuparuk A and C formations If water injection Is conducted at surface pressures above 1700-2000 psi. This modeling also Indicated that created fractures would be contained within the Kuparuk Interval unless the surface Injection pressure rises to more than 2700.3000 psi. Based on the computed and calibrated stress profile, and the model results presented here, it is possible to Initiate and propagate fractures with water injection in the Kuparuk formation at surface pressures up to 2000 psi, with all created fractures contained within the sands by the In-situ stress contrast between the sands and bounding silt/shale layers. An increase In fracture treating pressure of more than lOGO psi above the stable fracture extension pressure indicated by the model is required before excessive fracture height growth develops. The calibrated stress and fracture model predict height containment within each reservoir Interval. It Is not able to accurately predict the lateral extent of the created fractures. Rate of fracture extension (laterally) depends primarily on the balance between injection rate and leakoff rate to the surrounding formation. This can be affected by spatial changes In pore pressure and reservoir quality, and by progressive plugging or damage to the formation sand -face caused by Injected suspended solids and contaminants. Tom o study how fractures are Initiated during In action In the Kuparuk Reservoir and whether they can be effectively contained within the target Interval, the following cases were simulated or a horizontal well penetrating and injecting Into a single point within the Kuparuk "C'. Single point Injection models the worst-case scenario for the Induced pressure on the confining layers. In practice, injecting along the length of the lateral will result in less fracture height growth at each point. Injection at a single point would lead to the most fracture growth in the zone. Increasing the number of Injection points in the well will decrease the possibility of fracturing out of zone. 1) Water Injection without propped fracture at 3,000 bpd (Figure L-1,2,3,4,) 2) Water Injection without propped fracture at 6,000 bpd (Figure L-5,6) The above simulations Indicate that Injection Induced fractures will be contained within the Kuparuk Reservoir; no breakthrough of the overburden or under -burden containment zones will occur. 26 A'+Av,,, Section L — Fracture Containment Modeling CONCLUSIONS e Based on the computed and calibrated stress profile, and the model results presented here, it is possible to initiate and propagate fractures with water injection in the Kuparuk formation at surface pressures up to 2000 psi, with all created fractures contained within the sands by the in-situ stress contrast between the sands and bounding slit/shale layers. An Increase in fracture treating pressure of more than 1000 psi above the stable fracture extension pressure Indicated by the model is required before excessive fracture height growth develops. e The calibrated stress and fracture model predicts height containment within each reservoir Interval, but Is not able to accurately predict the lateral extent of the created fractures. Rate of fracture extension (laterallyj depends primarily on the balance between injection rate and leakoff rate to the surrounding formation. This can be affected by spatial changes In pore pressure and reservoir quality, and by progressive plugging or damage to the formation sand -face caused by injected suspended solids and contaminants. • Based on experience with other water injection and disposal projects, continuous monitoring of Injection pressures is recommended. If this is Impractical, then dally surface shut-in pressures should be obtained to track any long-term variations In observed Injection pressure. An Internal containment assurance analysis, conducted through BRPC, Indicates that the estimated maximum Injection pressures for the Kuparuk wells (listed In Seaton 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 fracture model bulk based on the nearby KRU 2S.13pb1 well log data and calibrated by using data from nearby geo-mechanical tests and pressure history matched data from the North Tarn #1 fracture stimulation 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 Kuparuk 011 Pool without risk of breaking through overburden or under -burden containment zones. The fret modelling software used was version was the Gdd Oriented Hydraulic Fracture Extension Replicator (GOHFER), due to its reliability and common use by North Slope operators as well as In the fracturing industry. GOWER is a planar 3-D geometry fracture simulator developed by Barree & Associates in association with Stlm-lab and Is commercially available throughout the Industry for performing hydraulic fracture simulation work. Modeling the growth of hydraulic fractures Induced by water injection Into the Kuparuk C zone was conducted using the three-dimensional numerical simulator. Results suggest that hydraulic fractures can be created and extended within the Kuparuk A and C formations If water Injection Is conducted at surface pressures above 1700-2000 psi. This modeling also indicated that created fractures would be contained within the Kuparuk interval unless the surface injection pressure rises to more than 2700-3000 psi. Based on the computed and calibrated stress profile, and the model results presented here, It is possible to initiate and propagate fractures with water Injection in the Kuparuk formation at surface pressures up to 2000 psi, with all created fractures contained within the sands by the In-situ stress contrast between the sands and bounding silt/shale layers. An increase in fracture treating pressure of more than 1000 psi above the stable fracture extension pressure Indicated by the model is required before excessive fracture height growth develops. The calibrated stress and fracture model predid height containment within each reservoir Interval. It Is not able to accurately predict the lateral extent of the created fractures. Rate of fracture extension (laterally) depends primarily on the balance between Injection rate and leakoff rate to the surrounding formation. This can be affected by spatial changes In pore pressure and reservoir quality, and by progressive plugging or damage to the formation sand -face caused by Injected suspended solids and contaminants. To study how fractures are Initiated during Injection in the Kuparuk Reservoir and whether they can be effectively contained within the target Interval, the following cases were simulated for a horizontal well penetrating and injecting Into a single point within the Kuparuk "C", Single point Injection models the worst-case scenario for the Induced pressure on the confining layers. In practice, Injecting along the length of the lateral will result in less fracture height growth at each point. Injection at a single point would lead to the most fracture growth in the zone. Increasing the number of injection points in the well will decrease the possibility of fracturing out of zone. 1) Water Injection without propped fracture at 3,000 bpd (Figure L-1,2,3,4,) 2) Water Injection without propped fracture at 6,000 bpd (Figure L-5,6) The above simulations indicate that injection Induced fractures will be contained within the Kuparuk Reservoir, no breakthrough of the overburden or under -burden containment zones will occur. 27 Section M — Formation Water Quality Ma: OIMMr 9tmple M.j,,, Netlh Tern 1A Md:Op etmplt Mtlpek, NMh T. Laboratory analysis of the Kuparuk Reservoir water sample collected from the North Tarn #1A well test is above the 10,000 mg/I cut off for freshwater. Based on the calculation of the weight percent of the chloride ions (chlorine molecules in the analysis) and sodium ions in the analysis from Kuparuk Lab, the total weight percent would be 1.66 weight percent which translates to 16,600 parts per million. This is consistent with the 15,000 to 20,000 ppm readings that are measured from the Kuparuk Reservoir. In fresh water - official salt concentration limits in drinking water US: 1000 ppm. Salinity of the Kuparuk Reservoir water in nearby Kuparuk River Unit producers found a salinity range from approximately 16,000 to 20,000 mg/I NaCl. Based on this information, the Kuparuk Reservoir is not a source of drinking water. Composition of the North Tarn #1A water, gas and crude oil composition is listed in Figures M-1, 2 and 3. Gni A^Section N —Aquifer Exemption Yn: N19 Nerbw N: nax 4rilnY Y�:O evuxPowml4W� .vW�FnxA WM'vr"35YI I6. MwnwmuYmRYn!pW :Y I.Anuugyxpw Me.!i4 pt511N0 M1 M!W xn!w'rttl:FnWxnYNtlhvw.rtr.Ynm RNvi:>'Lp4yq[aM.P..aW 64nTOWiWanM WY.rnnMl'e bmvm.mmlRnlwa¢Imx:r P.x nW>exRa�hAr,v Y.+eryxkmx] M lmAermv bmm xn WYW�wWme:n fuem'r[Mraynuvex..m b 'New re.v.Y.wpinn:MW i .n R: rt.n Rwlxrr¢IWx PMNweYw[W'9:INMMiprp Wx !. Ymtne RSonatt4 2 14mnn yypRmpe: ny 1 <m,ruW#rlNOanWmn £wlt'wWry� DI_536rP iB9-556 CP.00WL O'D-03 .an PwAxMmw:yryn.y.[cRWTx WOryi1RWM%u'v6 Y..wquw rtmsexxrVrmm W Iyrl3�nusl Wn9. b. tMA.r �IX'g...rrtm uo!e�xW Nx�NnerMeNm w. STlWrTrFW um6nx �. vu4m->6Y6.¢Warz%•!^, vuw!.o..Yu6w.. �nnxW .Wn Mrr[..mT•Ix w.,W� R.xcm+.:w x5YMv 4{VStM'YtlMOgpU Wgx¢+detrtF 6:!+s e'Mwx.m avz Wn'tl M:JnwnW W pnm+4 Wp)wtenl mW rt'u::mx:pR.rJz Mynaryeµy RUK mWbmloawexxRnPu1n18W r [w.pupizmcmipinam zaµa n u'glry Wxrt�n W inmvmYpxnY. X/'y'mrnkN:v an Yslmv6l:aq)yp5nµr.z PYevd I61! YyNi!5t ryagxs 'M xrtleelwe N!0 4gwz S W R W'I .x: n Yx'A N pnuha uMe 5 pgry y+y MiAWhwuq Schlumberger Salinity Evaluation Minimum values of formation water salinity in the Southern Miluveach Unit Area, west of the Kuparuk River Unit and continuing into the NPRA through the Colville River Unit determined using standard open hole wellbore geophysical methods which have been calibrated from drill stem and production testing, range from over 3,000 to 18,000 milligrams per liter ("mg/I") total dissolved solids ("TDS"). This evaluation was conducted by qualified petrophysicists contracted from Schlumberger Oil Field Services by Brooks Range Petroleum. Permafrost extends from the surface to approximately 1300' TVDss in the SMU, although partially frozen zones locally exist to a depth of 1800' TVDss. As such, no fresh water aquifers exist within the planned development from the surface to this depth. Any potential aquifer sands that could be located below this interval would be considered uneconomic sources of drinking water in this area. No significant permeable zones have been identified in any nearby wells that penetrate the stratigraphy below permafrost and above the first potential hydrocarbon bearing reservoir intervals. The first potential hydrocarbon zone in the SMU could be found at a depth of about 4000' TVDss, which is stratigraphically equivalent to the shallowest producing horizon in the nearby Tarn oil pool. This zone, stratigraphically equivalent to the Tarn Pool has not yet been proven to be a productive oil pool within the SMU. A petrophysical evaluation of the zone from the base of permafrost to 4000' TVDss was conducted on the nearby West Sak 25590 15 well which has a complete logging suite suitable for estimating the Total Dissolved Solids content (TOS) and salinity. From this analysis, the TDS/Salinity content of the fluids in these sands is calculated to be more than 3000 ppm. Hence, by definition, there are no drinking water aquifers identified in the vicinity by this analysis. 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 field." 40 CFR147.102(b)(3). The Commission has adopted that exemption by reference 20 AAC 25.440(c). All of the proposed SMU Kuparuk Oil Pool and the area to which the proposed AIO applies is within the ORIGINAL Kuparuk River Unit as approved in 1984 when the Environmental Protection Agency adopted the original aquifer exemption, and in 1986, when the Commission incorporated the KRU aquifer exemption. As such, the original aquifer exemption still applies to the proposed SMU AID. An aquifer exception should be granted for the SMU based on these factors and analysis. No fresh water aquifers are found within the development area of the SMU. 29 Section N—Aquifer Exemption F -M. Schlumberger salinity Evaluation (Provided to AOGCC) Minimum values of formation water salinity in the Southern Miluveach Unit Area, west of the Kuparuk River Unit and continuing into the NPRA through the Colville River Unit determined using standard open hole wellbore geophysical methods which have been calibrated from drill stem and production testing, range from over 3,000 to 18,000 milligrams per liter ("mg/1") total dissolved solids ("TDS"). This evaluation was conducted by qualified petrophysicists contracted from Schlumberger Oil Field Services by Brooks Range Petroleum. Permafrost extends from the surface to approximately 1300' TVDss in the SMU, although partially frozen zones locally exist to a depth of 1800' TVDss. As such, no fresh water aquifers exist within the planned development from the surface to this depth. Any potential aquifer sands that could be located below this interval would be considered uneconomic sources of drinking water in this area. No significant permeable zones have been identified in any nearby wells that penetrate the stratigraphy below permafrost and above the first potential hydrocarbon bearing reservoir intervals. The first Potential hydrocarbon zone in the SMU could be found at a depth of about 4000' TVDss, which is stratigraphically equivalent to the shallowest producing horizon in the nearby Tarn oil pool. This zone, stratigraphically equivalent to the Tarn Pool has not yet been proven to be a productive oil pool within the SMU. A petrophysical evaluation of the zone from the base of permafrost to 4000' TVDss was conducted on the nearby West Sak 2559015 well which has a complete logging suite suitable for estimating the Total Dissolved Solids content (TDS) and salinity. From this analysis, the TDS/Salinity content of the fluids in these sands is calculated to be more than 3000 ppm. Hence, by definition, there are no drinking water aquifers identified in the vicinity by this analysis. 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 field." 40 CFR147.102(b)(3). The Commission has adopted that exemption by reference 20 AAC 25.440(c). All of the proposed SMU Kuparuk Oil Pool and the area to which the proposed AIO applies is within the ORIGINAL Kuparuk River Unit as approved in 1984 when the Environmental Protection Agency adopted the original aquifer exemption, and in 1986, when the Commission incorporated the KRU aquifer exemption. As such, the original aquifer exemption still applies to the proposed SMU AIO. An aquifer exception should be granted for the SMU based on these factors and analysis. No fresh water aquifers are found within the development area of the SMU. 30 Section 0 — Hydrocarbon Recovery 0-1: ap OT Proposed SMU Kuparuk Development Wells 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 SMU Kuparuk Oil Pool. This waterflood technique has been widely used on North Slope with consistent success. The SMU Kuparuk 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. Some wells will likely be hydraulically fracture stimulated to enhance productivity and improve vertical injection sweep. Most wells will trend north to south, sub parallel the maximum principal stress direction to improve waterflood performance, andrange in length up to 6,000 feet within the reservoir (Figure 0-1). Wells will be arranged end-to-end to form alternating rows of producers and injectors in a line -drive flood pattern. After taking into account structural constraints, a nominal 1,500 ft. inter - well spacing delivers adequate secondary response. Initial wells will provide critical performance and injection data for the SMU Kuparuk 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 remaining SMU Kuparuk Pool development. The primary uncertainties in the development of the SMU Kuparuk Oil Pool are the lateral continuity of relatively thin sandstone bed and the effective displaceable pore volumes. The seismic signature of the SMU Kuparuk Pool reservoir is consistent with and supports laterally continuous productive sandstones over development with some compartmentalization possible, but hydraulic fracture stimulation will aid connecting the more poorly developed sandstone beds. Reservoir modeling estimates that primary recovery will recover approximately 10 t015% of the original oil -in-place ("OOIP") and that waterflood recovery will range from 1096 to 25% incremental recovery OOIP, yielding a total recovery after waterflood of up to 35%. Gas injection whether miscible or immiscible, would be expected to yield significant incremental recovery in the SMU Kuparuk Oil Pool. Historical IWAG incremental recovery has been in the range between 1-S%of DOW, while MWAG incremental recovery has been demonstrated to range from 3-15% of OOIP. 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 Kuparuk 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. Resource recovery for floods is heavily dependent on injection throughput, waterflood recovery efficiency, and gas injection recovery efficiency. 31 Section O — Hydrocarbon Recovery Table Summarizing Audited Kuparuk Reservoir Reserves 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 SMU Kuparuk Oil Pool. This waterflood technique has been widely used on North Slope with consistent success. The SMU Kuparuk 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. Some wells will likely be hydraulically fracture stimulated to enhance Productivity and improve vertical injection sweep. Most wells will trend north to south, sub parallel the maximum principal stress direction to Improve waterflood pertormance, and range in length up to 6,000 feet within the reservoir (Figure 0-1). Wells will be arranged end-to-end to form alternating rows of producers and injectors in a line -drive flood pattern. After taking into attount structural constraints, a nominal 1,500 ft. inter - well spacing delivers adequate secondary response. Initial wells will provide critical pertormance and injection data for the SMU Kuparuk Pool which may, in combination with additional geologic anengneering studies, change the number of wells, well spacing, well design, and well placement for the remaining SMU Kuparuk Pool development. The primary uncertainties in the development of the SMU Kuparuk Oil Pool are the lateral continuity of relatively thin sandstone bed and the effective displaceable pore volumes. The seismic signature of the SMU Kuparuk Pool reservoir is consistent with and supports laterally continuous productive sandstones over development with some compartmentalization possible, but hydraulic fracture stimulation will aid connecting the more poorly developed sandstone beds. Reservoir modeling estimates that primary recovery will recover approximately 10 to15%of the original oil -in-place ("OOIP") and that waterflood recovery will range from 10% to 25% incremental recovery OOIP, yielding a total recovery after waterflood of up to 35%. Gas injection whether miscible or immiscible, would be expected to yield significant incremental recovery in the SMU Kuparuk Oil Pool. Historical IWAG incremental recovery has been in the range between 1-5% Of OOIP, while MWAG incremental recovery has been demonstrated to range from 3-15% of oOIP. 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 Kuparuk Interval. Therefore, itis 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. Resource recovery for floods is heavily dependent on injection throughput, waterflood recovery efficiency, and gas injection recovery efficiency. 32 Application for Area Injection Order Kuparuk Oil Pool Southern Miluveach Unit (Kuparuk "C" and "A" Sand Reservoirs) L. Vendl, L. Smith, D. Gleason , AAN Section A -Introduction 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 pressure maintenance and enhanced recovery of hydrocarbons in the Southern Miluveach Unit, Kuparuk Oil Pool pursuant to 20 ACC 25.402. Brooks Range Petroleum Corporation ("BRPC"), in its capacity as Operator of the Southern Miluveach Unit (SMU), 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). BRPC is operating the SMU Kuparuk Reservoir under the Current Kuparuk Pool Rules that govern the development of the Kuparuk Pool. Ay� Introduction The Kuparuk Oil Pool within the SMU is a continuation of the deposit of Kuparuk "C" and Kuparuk "A" Sands adjacent to the southwest portion of the Kuparuk River Unit. It is comprised of sandstones, siltstones, and shale that lies between -5800 ft. true vertical depth sub -sea ("TVDSS") and -6400 ft. TVDSS within the SMU. Development of the Kuparuk Oil Pool in the SMU will be completed in discrete phases to mitigate risk and improve recovery. The reservoir targets will be accessed from the SMU "Mustang" drill site. Current plans are to initially develop the field with up to 11 horizontal producers and up to 10 horizontal injectors. Some of the producers may be hydraulically fractured to enhance production and ultimate recovery. /N/,Section B — Project Area Figure B-1 shows all existing injection wells, production wells, abandoned wells, dry holes and any other wells within the requested Southern Miluveach Unit, Kuparuk Oil Pool. Specific approvals for any new injection wells or existing wells to be converted to injection service will be obtained pursuant to 20 AAC 25.0057 25.280, and 25.507, or any applicable successor regulation. Mika FJ za n xe n m SMJT )] V ]5 )5 1M y)t rax xwaz - f • r t e ,Md3 Mus4n Fl / 9YI�xJ i NT -1A � 2544 TNAI-- SS1L S9 -t SAP SL -W Figure B-1 shows all existing injection wells, production wells, abandoned wells, dry holes and any other wells within the requested Southern Miluveach Unit, Kuparuk Oil Pool. Specific approvals for any new injection wells or existing wells to be converted to injection service will be obtained pursuant to 20 AAC 25.0057 25.280, and 25.507, or any applicable successor regulation. A,, �/N . Section C & D — Operator & Adjacent Surface Owners BRPC is the designated operator of the SMU, which included the Mustang drill site from which the Kuparuk development 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: James Beckham, Director 550 West Seventh Avenue, Suite 1100 Anchorage, AK 99501-355 Operators ConocoPhillips 700 G Street Anchorage, Alaska 99501 Repsol 3800 Centerpoint Dr, Anchorage, Alaska, 99503 Section E - Description of Proposed Operation • Up to 10 horizontal producers & 11 horizontal Injectors • Drilled in north/south Orientation, parallel geologic structure • Production from both "C" and "A" Kuparuk reservoir sands • Alternating rows of producers and Injectors • "Line drive" flood pattern • Approximately 1500' inter -well spacing • 3D model guides well placement • Plans for both waterflood and eventual lean or miscible gas flood • Produced water and seawater injection (CPAI seawater pipeline) • Gas sourced from SMU processing facilities Section F — Pool Location and Description Defining Well, North Tarn 1A, highlighting Pool interval with respect to the upper and lower confining intervals /N' r \ Section G — Formation Geology Nanuk-Kuparuk Colville#1 (Alpine Field) (Sand Absent( Western -Mustang Kuparuk Field o- West East G-1: West to East Schematic Stratigraphic Cross Section Across Area of Interest j LCU Kuparuk"C"Sand .�... -,.,..+N..-�-�..- LCU Jurauk Sands �� furessic Shale Brppk:en Erppklan MP3 HRI Brppkian Brmkipn Ka1ub1 Ke1UDt Hla HU k,F_ Kup Wluvearh Kalubik KaNb& Ka ub k lurassk sk Ipmss KuP'V KUP-C- Kup'U MIWme h Kup-A- Kup"A- Ke Regional DC 1 9 work llimsv Thin Miilrveerh Mlluveath - Flattened on the LCU enedonthe LCU mmssir mmssk G-1: West to East Schematic Stratigraphic Cross Section Across Area of Interest �AvNN Section G — Formation Geology G-2: Kuparuk "C" Reservoir Isocho�- Q4"" N Section G — Formation Geology u -j: Kuparuk "AW Reservoir Isochore /,' Section G — Formation Geology 17 16 15 14 3 1 \ 20 21 22 / 23 19 0 ®� V Ii 1 26 27 26 21%4-3621%4-36tp / 2M-37 45 43 M 1 1 f 36 M 33 31 33 34 3 / 36 W-02 2M-3831 2M-31-- -- 29 26 f / / ✓ 2 M 24 / M 21 tv ° ` Mustang-1PB1 I i 17 16 14 12 / NT -1A' 2M-33 -- 25-14 to i i 6 7 5 //l '>4 / 2M-34 --- �28-13A 2S-73AL1 3 22L-03 Z o � / n 25-11 Scale = 1:48000 �._ 7 0 3000 6000 9000fl 1 G-4: Kuparuk "AT' Reservoir Isochore �A''\ Section G — Formation Geology G-5: Cross Section, Flattened on the LCU, across the AIO area (Outlined in red on map). Log Curves include gamma ray and deep resistivity in TVDss and measured depth Section G — Formation Geology G-6: Lower Cretaceous Unconformity (LCU)/Kuparuk "C" Structure Grid ANN Section H — Logs of Injection Wells To date, two wells within the SMU have been drilled and are intended to be utilized for injection. The well logs and well histories for these wells, North Tarn #1A and SMU M- 02, have been submitted and are on file with the AOGCC AYNN Section I — Design and Mechanical Integrity of Injection Wells L h..Aff [lffLY9'32lktJ41 - J �II:T EptYP.M'Nf4i ' ... PI ntai • :IOII NOr�� !YS ' 41 t?pi/UI. t"IN,YR.'!Ac'nY/r111(+I .' .hi Lib ilYb.LS!"14'7... _ ..._ .. !:'VC:': r 1-1: Generic SMU Kuparuk Pool Injector 4 String Casing Well Design i/`**� Section J — Injection Fluids U..PEI NMnber: SI5]3Yifltia'i SaAlpk lbNlE STPSMWdg'Glaot UstllNge lobtlln: Mex CHARM UWE57P SamPle Pan;: STP SPD SFn]Pktl Xa[e: llWX16 3 . am. Marta it WATER -SEA ItHolmat BY ExrWAe, GaniNe Wle: Ql/»1 316 WrIlIeNu dboos-Imslom /{mksk Reaps: SOHO N0lnEC STP SMNEWKitt D50hXlge IMA tLwEg1: ArMKI/VA0.UI un't STP SampleftOESTIlM .,@I. PT4 AL=uE FFen klL SaTPpkd Oats 7/7/3716 35HOPM Pnxal a'AttTATc ma1Nb Id: WATER - SEA AaTut a.e IIKn aoxFX¢•anTwrF NMMMIRT CnFH0anlde I1atE07J3f/X16 $IIYAAFF SSC 'q(1 vexal N' cxmXINE Matatls NeNhs MLOtOF EienB +ryll OONEM IT @kIMTE FOPb'AlF 490 CJI T� NiyN r •. P4Xfh Ic'!PClIONATE 55 MPON1IUM) a.8 V, lPavXipAT! .iX „yl IV AElIFS'ZY j9XCj OAXp IC'9VVATE ZNI2N0 O. n} xeJl saN PNtAAiFI noolo Xryl SdTENAl1:AtNNT • TOTAL YJ A4T4! • AL(4VMNLYAI IL(A..AOA.P 0.00 w((1 NCW6'JAAILIII(O SI MIS IIW, 19 Ae:TIL, MION) wwl,ATEP3i n0 el aaOPvej ass nyll 1.2510•CObNVRMM1 19 MRAL9 • w(v.AULg ENX01q'Mn 53¢61 us/XX wlGmuMt pEs .yl s.as}PSAun+M1 •SI CPAv IP METHS • G (GUIVkh G(GIDVM) (y EY mdl SlEtlKCaR4M1Y EOIH 19 '.CTNS'lT'nINOMYpC 345110 fN(9)•IH G !x ]ll Im MT45'iF \MUNI s4iBi53lf:'>VWPEaITk I6 P+Oxl am W. I"GE IB mtfl 19 AVItt• P (MT'SAW I IF nTAAIVMI ]S].It nyll l9 t(TAIi' urymnLN.t! LI(NIN'.4'MI C.IE IN/I 19 xFILS' MO jMWNKNMy MN(1N0XM1`J N) ...sm nyn I9 AEiYu^'MNIMi11NAY[!F) Mn(W."ANEE) 0.0% rq(! M NFTN9' NA 0 V WIMI MRlSpC111M) 33AA rZ'I 19 x4TIu"' I In105iXO01S) !(P4.Y,o,181 ON SII Iv xerAu • sgalucax; slaNmnl so �1 19 NFrrat • to Pmonnunu J-1: Kuparuk Seawater Treatment Plant Water Composition / IYAN Section J — Injection Fluids Sample Number:5-26OW3 M0R SampkNanW SIPSeawater Plant Disdlarge Location: Area KUPARUK Un,t: ST'P samplepoint: STP SPD Sampled Date: 21212916 35DOOPNI Ntatda lit WAIER, - SEA ReWtwed By. Ca w l`e Anieie Date G71Zj1:1716 Analysis Readts Tr9 P&MMftr pewit UOM SR pRONTIURT) 8.29 nWI IP M. A73'ZN (aNC} ZN(ZWQ 0.07 mall S2310ALRALyl ITY•TOTAL a1CARn©NATE(HCO3) 791a m:fi CARRONATE(CO3l 0.0 mmd//k 5-2536' CONDUCTIVITY CONOLICTk r MOO Aj= 5-3510 SALINf1Y - 5P 0 RAY S REGHCGRANtt 10363 5-0578 PH N{)' PH PH T l7 5 -455057 -IF) - 5ULFIC E EY TRO SULFIDE is Mel J-2: Kuparuk Gas Injectant Composition /^� Section J — Injection Fluids 504PIPIE BtIxNtM:'Y1QY_Y33DaT$ 301fIp1e Wrtic GPF-3 Prod W'~Tank Outlet L.U.: A,,m KUPARUK Wt CPF3 clmPled mt. MI M16 215:DOPM PgISIN 1k WATER -PA UCSD kevhPme,Jny. DOMHIy Cdfigrme Date 04MM16 9ndesh R'NAtS r -a 93aas] O1lxBt IC' gfFTRTF ACGTATE giCx9(IG'BJTiRAT4 auTmarz BnxEAlr wlgRla oa9nmE UgryIX C. (ORhNTf PGARVUTE Gm XIX IC' PPGPIJ\IATE PAOPICXFT[ NpNIXIt•SUIFATE Sg91¢VIFATEI IV NFTA33'A!(4LVRTXVM) Al (AWMINUPTy IR M1FTUS'A(WnGNI A BOflCN4 I. RETAIS' LN (]XMUAB NP I&•PIVM) 10 METAIY' G(fJLLCUXQ U PAWFUM) 16 XFTAIS' CP IUiAOMUxO OI(WAOMVM} +R MF]A4S' FE ORPNJ e;In9rv1 10 XETAIS' 11 (PGTARMMI R (g9]'Afi5111A0 IO TAETCI9 ` V hIM�UNa V (UTMUM) ID NFTA15' MU (MAGNESV Mj MO(NMOXESMPA) 10 ThTA15' MN (1MXGARBF) Mn INMM1G4X.3 E) ICI IUFry4' MA $ 9GFIM) NA (iCCCJV) IU MET A{8 `P (PMOSMCPViJ f pxPSnNnxls) 10 PAV AIS•SI(6NIC0V1 3�$•tKl]M1I IR A£fAl3'SR jSTRGRT:UMI SA fl POM111M) le ANTA{S • zx aaG) Sarn1AP Pu nt. [PF3 PWT W l Sample Nwba S-160233006ie Sample Mahle CPF-3Prod WatwTNNk Outld w.rw ypp] La Uw. Arm KUPARUK UnIC CPF3 Sample Pant CPF3 PWt Olaf m3T ,„an Sampled Oatr. 217!2616 215:C". Rubix ld: WATER- PRODUCED <9R mNel RetdLAved B{. DalnNry Cd�]rwe Da0C O1JDILl3Tib ]9.99 n 1 X5.9 nIN/I 143 eNl SaxS mA/• 9.06 ngll ]TL nRl1 31 03 mA/1 ]A9 m0/1 0.90 rzA[�t 09.A rtgN 3.Y xgl 30)91 myl 9935 mN(1 90 A.31 nyl 190 ny/i 96.L9 refill 0.39 �xa(1 Analvs&REgd1s ZN (L Q 8-1330AIkILVtrT • NTAI OM MfATE(Nm3) GOMWE(O03) &5630 • WNNOCSNIIV CONDI)a T S.lslsswxmr•SPNWV 6PEDACOPA7m S4300 PN (0) • PN Pfi si:P9Sz-IPl'suwoF m nTn SVwOE @ Sfau O.M mnN l SSSS3 mNll 0.0 A;II 06P0 d(9n 3 P193 7.53 J-3: Kuparuk Pool Produced Water Composition Section K — SMU Kuparuk Oil Pool Injection Pressure Summary Figure K-1: SMU Kuparuk Oil Pool Iniection Pressure Summary Datum (TVDss) 6100 Average Injection Gradient Injection Type Estimated Wellhead Estimated Bottom -hole Overburden Pressure Gradient Pressure (PSIA) Pressure 0.442 Gas Gradient (MI) Maximum* Average* Maximum** Average* * Water Injection 1400 2000 4000 4623 *Based on current operations at a true vertical depth of 6100 feet ** Maximums vary according to actual depth Datum (TVDss) 6100 Average Injection Gradient 0.62 Maximum Injection Gradient 0.67 Overburden Pressure Gradient 0.72 CPF-3 Fluid Gradient (Water) 0.442 Gas Gradient (MI) 0.15 Calculations: Bottom Hole Pressure (BHP)=Datum (TVDss)*Injection Gradient (Water or MI) Hydrostatic Pressure = Datum (TVDss) * Fluid Gradient Well Head Pressure (WHP)=BHP-Hydrostatic Pressure /0� Section L — Fracture Containment Modeling SUMMARY • Modeling the growth of hydraulic fractures induced by water injection into the Kuparuk C zone was conducted using the threedimensional numerical simulator GOWER. Results suggest that hydraulic fractures can be created and extended within the Kuparuk A4 and C formations if water injection is conducted at surface pressures above 1700-2000 psi. This modeling also indicated that created fractures would be contained within the Kuparuk interval unless the surface injection pressure rises to more than 2700-3000 psi. • Modeling is based on worst case scenario for fracture containment which is a single point of injection rather than multiple injection points within the Kup C interval. /N,Y� Section L — Fracture Containment Modeling MECHANICAL MODEL - �2S-13PBI COMM • Best and closest analog for 3 injection wells was 2S- 71- 13PB1 4. Poisson's ratio derived from shear compressional ratio • Young's modulus derived from shear compressional ratio and density log Conversion to static Young modulus using Eiza transform Pore pressure set to normally pressured rigure L-1: well log from 2S-13PB1 used in GOWER fracture analysis Section L— Fracture Containment Modeling PHANTOM - FF - INJECTION INTO KUPARUK C F' ure L-2• dei f in I oint eLcti n in th K Baruk "�" Agure L- :1Nodeio?sii gel�poin riiiiec ion info t ie paruk C" AAN Section L — Fracture Containment Modeling PHANTOM FF - INJECTION PRESSURE AT 3000 BPD Figure L-3: Injection pressure modeled at 3000 BOPD /*� Section L — Fracture Containment Modeling 3000 BPD INJECTION RATE - FRACTURE GEOMETRY Figure L-4: Fracture geometry, exhibiting containment within the Kuparuk formation at 30011 0 BOPD /N''Y� Section L — Fracture Containment Modeling PHANTOM FF - INJECTION PRESSURE AT 6000 BPD ER 0 Figure L-5: Injection pressure modeled at 6000 BOPD Section L — Fracture Containment Modeling 6000 BPD - INJECTION RATE - FRACTURE GEOMETRY Figure L-6: Water Injection Without Propped Fracture At 61000 BPD Section L — Fracture Containment Modeling CONCLUSIONS • Based on the computed and calibrated stress profile, and the model results presented here, it is possible to initiate and propagate fractures with water injection in the Kuparuk formation at surface pressures up to 2000 psi, with all created fractures contained within the sands by the in-situ stress contrast between the sands and bounding silt/shale layers. An increase in fracture treating pressure of more than 1000 psi above the stable fracture extension pressure indicated by the model is required before excessive fracture height growth develops. • The calibrated stress and fracture model predicts height containment within each reservoir interval, but is not able to accurately predict the lateral extent of the created fractures. Rate of fracture extension (laterally) depends primarily on the balance between injection rate and leakoff rate to the surrounding formation. This can be affected by spatial changes in pore pressure and reservoir quality, and by progressive plugging or damage to the formation sand -face caused by injected suspended solids and contaminants. • Based on experience with other water injection and disposal projects, continuous monitoring of injection pressures is recommended. If this is impractical, then daily surface shut-in pressures should be obtained to track any long-term variations in observed injection pressure. ^'**� Section M — Formation Water Quality 916:LNS. Minn N.[ Y. k V Ih SI S1mpk NvaheF: 120 t ft 1' FnnPk X.ml� AI±Mn Smpk Snne: LR1'LUN-S Ar hli[ce1MMu UMk Mlm lkrvxlm $uwpk Ya{nt Mu: iv0lnrvinv Ample. S.mpW knte: 1.?[:31112 ]6R;Ip/,%1 1.•semkn JnerfUllon Addilkmal Nmm�k I 11 LwMXdveHlvbn UnN'Aa Nmx Nurh!'um lA IRII Ikk.m:.n n' mnk Anulr,l, R.lalk 1m1 Lltlen M.INRnWaN II V26 kRl.. • N s 11�v1i UM WIIG]IL49 W-LL'lI N'ai-mn•L Wavvu. 01.0 Vc14 WWl&SAW'-tiul:da V:Ji:nay I:Jmr 5,234 M[Y6M %RFXRF UJMS•Nr(hn PFl L1116 Melq nl lALninnonp nav Mry.` MesbM%RP%RF Calt'Lek:nl nM WY1 Met,IaM NNF-SXF CIE I(hWila) ILW µrY MeskM %N}:NRF Cr YCkumie:ul =LLQ' wl n LheJ.Ip xxF.NRf (%'ICalrvel 0 qw"Lh11aM %RF•%RF Ie (hon) Q71 WI!i N# lsq%NF•%RF NI%unwxnl 11V. Nl5 %k4d+M XRF.xRF nIF IMrym.mnl 110] Wfv HRakh%R]iw If. l.Nn vl .O,W MRIi \IertkM %R}.%NI' 1!a lMnllktv¢ml •OM µYY \IevLrM 1RF•\NI' Ne 15ndNM1l M113 uk!. fkvleM%RF%NF N1 (NrtkU eOA± µ1q ] .kM%RF•%RF V(Iv.rvMnml 11,05 Wt^. .SLzh XRF.%RF Ilrllln•eirel -4O, w" Mnuk M'x"-w sl5mma a3a w:Y \klak yXRF-XRF lit\11kw1 101 Wit M1bnh lry XNl •XNi' I:Il Wnvnn 41,4 W.% hkuk!p xRn%XF Znaiw) I.u. Yxnu1e sq. .\MakM %RF•XRF Ikfl4"d:-I 40] µYt Meek Sy XRF•XRi A19mel:lal v0! W't•i iba1s 95% .X" vM.alulnl .W •ylse I,w. bS'XII XNF AXltikasl =Y.05 w1% hMek bs'%RF.XRF fnlCn[u1:f µY4 916:LNS. Minn N.[ Mi.So AliiS_D M-1: Oil/Water Sample Analysis, North Tarn 1A M-2: Gas Sample Analysis, North Tarn K Dan WIWI k N rlh Sloge Pr AuxM , S1mpk NvaheF: 7w;,xN 5XmPk NnnR: kXYLIHt-\ AXeA: Misullmm�wa I:vR: MiaxlluWn4c RYmpk PNnl Dme: FcfAirelMn BanNe Ampkd Unlc 125,1011 7.0InAM A4A/1(,4R lym kR.0.'-il _ 1.•semkn JnerfUllon Onnks Ran%e WolhTxl IN Ca:S Sa M A hs R ik IRII Ikk.m:.n n' R,ft Mill 0.1n1S•Ny(ias M.INRnWaN II V26 kRl.. 0.11YSNnHis t'Mvn 1%mrdv d6]n NMI.. 1}IYi3•FRlix hlnMw W, ;'N Molt IFInIYNitia I:Jmr 5,234 wI% UJMS•Nr(hn PFl L1116 Melq 0.1'MYNm(In iNnnme 0214 MMb 0.191YNm(im rvUnnae ViMf Mia. 0.1Y1NNtl(iq FpenOa 0114 NN.. I}IMS•NWia ml'euvx &MI M.n ni Ie 14:5•Nz1(iz= I:RII I:T min MU:Y I11na5•FWfiu. T.1". 0x" Mnl+a IY IvvS•N� C4A llglin 0!7M1 Mol•. I}InIS•NaNin CBA R:win OIYI o-1Y13•NW4m A•n eMnk nkr Wl .95 win.l R-IW5•Ngim nrlm*u'(T(I)q, 11115 gytq'F RIWSM.Hu!. MR 1J 1 C 6ai IM IRw5!'F 1}fm3•Ndl,xa kr11Mf11 fl'1Re41 I:III,V RYYS(k 0.1 nL•V.l(ivy R:LL1<:d CRLfI LM13 IHui('P f}IWS•Ny(ina Cumpm bfl Frac 4v0i0 0.1415.31 S Nm flealof(lwfiupian I+MNI Illrvµ RIn14NM(iy, -v'•nh I:revin hkpl tW.v P.InuyYGia cpnl"n-Ilrnn: Ned ::MH (MIiw.l:rvP�i•rn• I.u. Yxnu1e sq. 1rti tFlimlv'rl:.=n:.` I.mPeldurc 111. Dept Mi.So AliiS_D M-1: Oil/Water Sample Analysis, North Tarn 1A M-2: Gas Sample Analysis, North Tarn Section N — Aquifer Exemption Introduction Sr ,tt rnvra-neJlq R,:Rbi.rr:ilL.-!TIf m R. - RJJ.r: bIT.-I'S'C Brooks Range Petroleum has asked Sct•Jumberyer to evaluate :,he salinity of the fermaticn v.ater cn wtll VVea Sak 255M 15• whit" wastl rged in March 1960. The inteNa+ analysed seas °rom 1 YJD 6325't'MD ft The data xvailablefor this esaluai`anincluded Resistivrd. Gamma Ray and snric providing compressional transnttme. \, Sulhmry Determination The salhnity Of the famwjm water {Rel was determined try Rwa imerpretatmn for a poro is calculated with the rompr ss oval tiansn time. This technique assumes the fluty n trf formation wase, wtI, ro hydrocarbon. The charts used in this work are inctudesint'n moon... Rwa lmerpretaton Rao imerInn tatim cats<sa of the following ,steps. 1. Determine Rt' rom the DIL tog a 2- DeTermine Atl g from some log 0 3. Calcufatepao;;ty(filfrom t+esame log R DT -556 SbnicPorosity= xCP e. ruare 189-556 - of CP = 0.0001' TiD-0.3 punt 4. Calculate Baia Oliva -Vx Rtt 0.61) of 5_ Convert RWA at formation temperature to RWA at 60 degf (RWA60) using the equation from Schlumberger Chart Book (2013 edition) Gen -6. a. @bYA�=:{arr�ttvfiFnl/rfi.'^ n h atl 6. Convert RWA60 W Salinity using the equation derived from the Schlumberger ELAN Parameter calculations ITER Gen 91 a; na a. SA11A77Y-7.3966x&1Na50� "cr)SALINITY=7.3466xRWA6 r„ 1001 The sortie measufemem ir, this well is a Wee of urtertainry in the Rwe imerpretanon sectUN-ue. sonic to messurenfris at shallow daOr can be affected by poor corroac:wn of the rocit iF this is the case the sonic pWosiry calculated from me equator In step 3 labrove3 may rerun in an optimistic Ihephl interpreted porosity. Thus. Ve sone porosity was calculated usi y a compaction mnettion m !CPI order comphrte an Rwa stat is ca:'ibrated io one ca'culated ra wr•Jt c*Mmr porosity in The intermediate section. t e \, sit n Im u! In m m mlriro 'Ire Salm;t) calcslacion was determined using a temperature gratem of 1571 degree: t i7 � , a: a t Fe =3 w n z n w m im IN IAT WE= surfatc temperature of 1D degree,^ FIVIeIt>:ii Inti' tIe base of the pennafro,r where a grad est ,.:.. __ degFAODftwas used. Schlumberger Salinity Evaluation urn tn�isi tU C O 0- E E O x w L N Q c 0 4� Wo w Ln L a 4A L 4J E t U N ^O�AN Section O — Hydrocarbon RecnvPry 20 21 22 23 24 19 P RaiMv HPP-Silree R Pl�arMew K ReR4, HP-K.Trj n 29-. xP.a.oiaem 28 27 6 25 30 :143] C Ringo Z S rOY51 MP W bpo 32 33 34 EF P 35 NPLCFURY 31 HPi %" 1a wu 5 4 3 1 6 —xv.xxwz - wowR1 8 9 HPA uonmv 10 n 12 7 G Wi-1ieyM V fr tL.W Vl Vl MBinpo l� /(/ JJ ypsyyil¢ xP-EE{Iwx HP.F.Fakon NPR-S�Knrtt4 Scale = 1.43584 17 16 15 tl� 0 200® 0 O-1: map or Proposed SMU Kuparuk Development Wells Section O — Hydrocarbon Recovery �ete a1 maas:25 Mach 8119 IJ.fIC (tl F'CT ]JS Ifp61l: 3 Gt]eJcr 2014 Summary Pf Dir and Gas Reserves and Resources Southam MfueaGchrox AUd=hko /P M to Licence He: A]tributablemisww' MAIi 0bands Eh.MF frvm CAW" CMMWVP MMbbl Predouv update Rpmmkv R emevu Dil Remries IP 212 2P 326 3P 303 N:rtuml Gax Rmervez IP 2P 39 NAV.1 Gas Lioulds Resenes IP 2P 3P ContlnAent Resnurcn Dd IC 2C 3C Hduml Gas IC 2C 3C Normal Gas Ciouids IC 2C 3C Prospective Reseurpss I'd Law•Csomne - AestCsoinate I,gh Estimate - HalurslGas CcaCn.mate - Aest Cg: m4 .I.,p Cslimata IP: P,Pved P: Prwed •Probah:e 3P: Pr.d • Probable-PceaiMu 152. 561a APProximately 3D} rcmverr 23.7 OCN APPraxim t'N 35k recasmy 27.6 04% Appr4Yimnely AO$ reaasery Table Summarizing Audited Kuparuk Reservoir Reserves Roby, David S (CED) From: Larry Vendl <Ivendl@brpcak.com> Sent: Friday, May 31, 2019 3:19 PM To: Roby, David S (CED) Subject: BRPC GOHFER final presentation materials. Attachments: Brooks Range Resources Mustang Injection Kuparuk C.pdf Dave, I don't think the report from the GOHFER frac modeling folk got to you. I did include some of the Illustrations in the application. You will probably want this for the files. We only received the .ppt presentation material, not a complete report. Attached, above. Cheers, UV KUPARUK C -MUSTANG INJECTION MODELLING JGC SUMMARY • Modeling the growth of hydraulic fractures induced by water injection into the Kuparuk C zone was conducted using the three- dimensional numerical simulator GOHFER. Results suggest that hydraulic fractures can be created and extended within the Kuparuk A4 and C formations if water injection is conducted at surface pressures above 1700-2000 psi. This modeling also indicated that created fractures would be contained within the Kuparuk interval unless the surface injection pressure rises to more than 2700-3000 psi. • Modeling is based on worst case scenario for fracture containment which is a single point of injection rather than multiple injection points within the Kup C interval. JGC,. DDEL-1S-'13P8 STRUCTURAL TOP OF KUPARUK C • Direction of maximum stress 330 deg • 3 horizontal injection wells JG.-,. • •]►III►'IlKID nxum nnnnmm�nnnuannlul mlxlw mmIIm nmwmmmnmm in; mnn 3R'.L*S Will �� nn Iwuaunlm nmmor, w umnuuni mi ,.;nwmm�mm�ummm�r nnnnnm annum :unwr: nuuntw nuunnnlllnwmn Innnnuu nunlnuunm � nunllwnn III nunnllIII lINH nnRUN lnn' m n xou it n1 x::... :m nl uln 11 ,m, .,•:. . Iwxounnnnmmn xnnm111'p yy�� NUNNx ".... IwWI I hl uxmm�u. nnu1101 9111"9109"�1unii nlnumno -n uu:un mnnx wnHIM mmll;nnn, PHANTOM FF - INJECTION PRESSURE AT 3000 BPD Engine Results m ti BWbm Nda hagln o N _wail wewv � -Nlaeaon Noe Belle. "o NopOeM Can< SURea Proppent Can< OO ? N rye F -Be115palM r N O a � S _ E w Q v$ In v �a 0 w T y C O 0 o a a 0 0 c 0 0 0 o epp py Bp'V.w 11Mw I6gIW N0.VN tBL]w ]AMw MON awW.w o Elapsed Elapsed Tlme (minules) JGC 3000 BPD INJECTION RATE - FRACTURE GEOMETRY PHANTOM FF - INJECTION PRESSURE AT 6000 BPD I Enaine Results RWom Nok Fe��e Well Presu N)e[tlon Rele suds ft Roo con CaM Surfea Prvppent Canc Rpe FngO BellseatPo 400000 8000.00 120W.00 1600000 2000.00 24000.W 28UW.UU MUUW dbUW.UU 4U UU Elapsed Time (minutes) P 6000 BPD - INJECTION RATE - FRACTURE GEOMETRY 1G 'Pill I9:0lPlelLlNl=(0111W X11► Its 1111111111110 1wry JIIIIIIIIIllnll p.,.:e_... .,. mnmtlm111Y ,.nlm(Ilnnl Ilu uI'fiuinl i1l1�w�11111m1xOUIIn111u1:IIllIl'' 111 u 1I xnllnIIf w.�•n:1l.oil. n1 1n11n1t1n11'n1l111 nllI �1l`,lx1l1ll1iti• 1l1lInllllollllml1 lll�IlluIluIiwnwx1il luxinunYnInIili. iunNnml n w III I M111111x1lli unnnmlulxfl 1 IIOl IwII IIIIII1:1:1:1IOr..1m111u11u111: 1 nnnnunnunn 1111111npbulill. mummnu nm I f 10 I iII111�1�1111111111 I11 illi llli1llli11111�'I Will 1111111 11111111111 I Iillpnl'°noon I Ix 111t1101xI1i11111011110tl1'II�iI1111"llm1Nm11111111111H111 tlllin mOmn 1 nnuul I nn ulii uuuullnlllllnunl1011m uumioimuli mannan 1111111111111 11111111111 Illllllllll IIIIIIIIIIIIIIIIU nlllilll IIIIIIII 111111111111111111111111mllllllxlln111111 unuuu luulm nulun '11'.111 JC•:Ill:.f' IIIIIIII!tllllll -luno numuunuuunuuounuumwol al MESQUITE JJ - INJECTION PRESSURE AT 3000 BPD Engine Results :J -aonom we vnmiw w.n rr.m m m nne 6Mom Mole Roppem core sw.� wopp.m coat npe rnmon eauseai vo IV g MESQUITE JJ - 3000 BPD - FRACTURE GEOMETRY JP; MESQUITE JJ - INJECTION RATE PRESSURE 3000 BPD Engine Results C B[Qpn NOk ReSWe Wetl Fem Rete 8,MM BWom we Poppenl Care Sufete AeDpnm Cont P¢ Wal 400000 W 4000.00 800000 1200000 16000.00 2000000 2400000 2WW.00 32000.00 36000.00 40000.00 Elapsed Time (minutes) 3 TGC e MESQUITE JJ - 6000 BPD - FRACTURE GEOMETRY 1.G1C„ V101c ONZ:M1 412"11610110116 :.11111 it110 IIIIIIIIillllllll ,+I!LL...n 111111 IIIIIIIIIIIIIIII I t,', "45UNrix glllll IIIIIIIIIIIIIIIIII I X01 IIIlllllnl�• li x nununnun 11 1 nonan .�lallmw uunn nom 1 •.•. Homo uunuucuu 1 _ I mom 1 Inunnuunu v.: i .•,.,,,:u„ �' •:.illi ,�.I 1111111 IIIIIIIIIIItlillllnuf. :..:.. '. v::.umnu :I��11���� 111' !- NII '.Illllllllilllilllplll 1 _. ulll ' �G�1111111{IIII'N�II�IIIIII-;: V{111111111{{IIl1�111111111Y, 1111111111111111 !(1f1'11��i: BINI 11`11111111111111111111111 111111111 ilamd�i Iln{{Or{{Idl {0{Im111 11111111111111111 1 1 '!xl liliiii�{ili�lii{nxH little, t 1 N�� {{I lin 1111111x11111 111 nunnnnnnmulilt iiinnu nIxI11l. 1I111111111111 Hill - 1 nnunnnnuuunuulnnnm HIP Hill I it It nnu nolmumnunuu > unm nu nun11111 1mm�unuu anon nnHl unnnlnn m �..,il mm•1 y� mmmm�m {lmm�unm � : moon unnu It 111111111111111116111 0 1 � nnnnnuux nnunnnunn 11111111111111 11111111111111111111 mn1nnl{nu uunmm�m 11 nnmml�m nnnnnnnnunnnlnu 1 lnumniiiumuw 1113111111..-I V: mmm�niininmm�mnnlluun mnnnnnn unnm unnninunuumununnnnu mmuux unnr unuuuuuuunni. nmanrl uum umumunuu unnll:muum 11111"10 luumoouu nun nmiiiinminnnnmin .nor alminnr. nunll:minu __ uunnl ur.�lluwr:l. n1;w — uuw ii BINGO FF - 3000 BPD INJECTION PRESURE Engine Results 0 'o 0 400000 800000 12000.00 1600000 2000000 2400000 2800000 3200000 3600000 4000000 0 Elapsed Time (minutes) TGC" eonom xde Hamra well vrem Nfectwn rate Bcttwn Hok Hoppem COM Surface RCppmI COM Rpe Fn�n -Ba115eatPo 0 'o 0 400000 800000 12000.00 1600000 2000000 2400000 2800000 3200000 3600000 4000000 0 Elapsed Time (minutes) TGC" BINGO FF - 3000 BPD - FRACTURE GEOMETRY JG�. BINGO FF - 6000 BPD INJECTION PRESURE Engine Results We Ibk vr<sur< well R<m Bortom Wk Roppdnl Con[ Surtett haOYdM Cor[ Rp<fr1(rq BdIIXdI Po 400000 BOW.W 12000.00 16000.00 20000.00 24000.00 20000.00 3200000 36000.00 4000000 0 Elapsed Time (minutes) S S 9v JG.. BINGO FF - 6000 BPD - FRACTURE GEOMETRY CONCLUSIONS • Based on the computed and calibrated stress profile, and the model results presented here, it is possible to initiate and propagate fractures with water injection in the Kuparuk formation at surface pressures up to 2000 psi, with all created fractures contained within the sands by the in-situ stress contrast between the sands and bounding silt/shale layers. An increase in fracture treating pressure of more than 1000 psi above the stable fracture extension pressure indicated by the model is required before excessive fracture height growth develops. • The calibrated stress and fracture model predicts height containment within each reservoir interval, but is not able to accurately predict the lateral extent of the created fractures. Rate of fracture extension (laterally) depends primarily on the balance between injection rate and leakoff rate to the surrounding formation. This can be affected by spatial changes in pore pressure and reservoir quality, and by progressive plugging or damage to the formation sand -face caused by injected suspended solids and contaminants. JGC, CONCLUSIONS • Based on experience with other water injection and disposal projects, continuous monitoring of injection pressures is recommended. If this is impractical, then daily surface shut-in pressures should be obtained to track any long-term variations in observed injection pressure. John Gilbert Consulting LLC Littleton CO 80128 Ph 303 4835160 ]GC. JGC Roby, David S (CED) From: Larry Vendl <Ivendl@brpcak.com> Sent: Thursday, May 30, 2019 9:17 AM To: Roby, David S (CED) Cc: Larry J. Smith Subject: FW: confidentiality of AID Application for SMU development... general answers to Dave's questions... Dave, with regard to the reference to the Kuparuk River Formation salinity range, I searched through the original KRU AID application (AIO-2) from back in '86. In that application, they include a lab report on the water chemistry (Attached Below). I was unable to locate the reference I included in the application. I will keep looking and provide that when I locate it, or we can replace that reference with the water analysis from the original application, if needed. Figure M-1 PRODUCTION PROFITS omenr a town JI111Axn0AMl imG Perrole n Stroke LAbonsray mAl& r 9 aw+ Mph VJ aGLV Levee _uad Ne._ Seung of - - am cwacem by REPORT OF WATER ANALYSIS LN&NumobN r_x_anr Sheaft CgMR7 --4-41.Z7 yd LAB r road IdneNM Se We 2Aaat R*Sbtmt7 (Ohn"nOWe M "* f.) ' a Hydm#W fuJNse nnee:ur Qd1QLU InN[Rei U ALM MnW 10 13 20 (Number Mar W Sym" dndketex n+9/Smb UAN) C&Jmm Cwmenea Sabdp Index at 77• e CAIUom aiaa Steadily at 95'F COnwntreoon - I mem/1. 9erlum SUNea Sabft K 93e F CMmntnodan - 1"I"IL REMARKS SODIUM BY AA: 9589 From: Larry Vendl NCO. eN/1 5S S4 63 8.71 3.46 29 --r—.2-2 1_74 5.45 36.73 saftm $Ufrla (9w".) (Q-A) ---%-z5 Sceling rendener e:cr. cafe. SoNowt, eA- AGee//. Cele. Sexiewy MJi9/1. PW ft S~Sban Fwr aareUon _17 100 Sent: Wednesday, May 29, 2019 12:37 PM To: Roby, David S (DOA) <dave.roby@alaska.gov>; Larry J. Smith <Ismith@brpcak.com>; Harry Bockmeulen (hbockmeulen@brpcak.com) <hbockmeulen@brpcak.com>; Dan Gleason <DGleason@brpcak.com> Subject: FW: confidentiality of AIO Application for SMU development...general answers to Dave's questions... Dave, I will see what I can do to round up answers to your questions by our meeting next week. My general comments are in green font, below. Did you receive any public comments that need to be addressed in the meeting next week, or are all of your questions internal to the AOGCC? I wanted to make sure we come prepared. me/1 h.RTI T401 Seo* (Cok.) ^ASA-: r9W UadNeeMed 30kh $60um (Caw) AR90 [AA r OU (SDNent Sofum o) Incn mfts q n n Ae(d SoNba 7 ewdum AA Inch _,.Oxide: ar nate: Caktumdnq z-4 Cekam Meaneelum mans 7MM^bAnh—ar nate: CArbNe 1 1 Ann _=7 -FA Suds" q P�_s Unidenti? eT: eARrmeira .7.oe &ga k (ISndlen Less) suNeM l I Acid lnswum" Sand a Car C&Jmm Cwmenea Sabdp Index at 77• e CAIUom aiaa Steadily at 95'F COnwntreoon - I mem/1. 9erlum SUNea Sabft K 93e F CMmntnodan - 1"I"IL REMARKS SODIUM BY AA: 9589 From: Larry Vendl NCO. eN/1 5S S4 63 8.71 3.46 29 --r—.2-2 1_74 5.45 36.73 saftm $Ufrla (9w".) (Q-A) ---%-z5 Sceling rendener e:cr. cafe. SoNowt, eA- AGee//. Cele. Sexiewy MJi9/1. PW ft S~Sban Fwr aareUon _17 100 Sent: Wednesday, May 29, 2019 12:37 PM To: Roby, David S (DOA) <dave.roby@alaska.gov>; Larry J. Smith <Ismith@brpcak.com>; Harry Bockmeulen (hbockmeulen@brpcak.com) <hbockmeulen@brpcak.com>; Dan Gleason <DGleason@brpcak.com> Subject: FW: confidentiality of AIO Application for SMU development...general answers to Dave's questions... Dave, I will see what I can do to round up answers to your questions by our meeting next week. My general comments are in green font, below. Did you receive any public comments that need to be addressed in the meeting next week, or are all of your questions internal to the AOGCC? I wanted to make sure we come prepared. UV From: Roby, David 5 (CED) <dave.roby@alaska.aov> Sent: Wednesday, May 29, 2019 10:57 AM To: Larry Vend[ <Ivendl@brpcak.com> Cc: Colombie, Jody J (CED) <lody.colombie@alaska.Rov>; Larry J. Smith <Ismith@brpcak.com> Subject: RE: confidentiality of AID Application for SMU development Hi Larry, We have some questions on the AIO application that we'd like you to address. They are: Please provide a copy of Schlumbergers evaluation of formation water salinity for the SMU so that the AOGCC can verify Schlumbergers results, the methods used, and any assumptions made. Please provide information concerning how the well logging information from West Sak 25590-15 was calibrated using drill stem and production testing (e.g., discuss resulting porosity values, how they were determined, and why they are applicable to the SMU). I will provide SLB's evaluation and data used for the analysis. I don't think we included the report, which is only a couple of pages, in the application. I will need to check on the question of calibration used by SLB for the log analysis. 2. During past discussions, you indicated Brooks Range would supply one or more cross-sections to support Brooks Range's contention that no freshwater aquifers exist within the SMU. Please demonstrate the relationship of the shallow geologic section encountered in West Sak 25590-15 to similar strata within the SMU and confirm that salinity calculations for West Sak 25590-15 are relevant to aquifers within the SMU. I have constructed a general cross section which I can provide for you showing the wells currently in the SMU correlated to the shallow section of the West Sak 25590-15 and other nearby 2M pad and 2S pad wells. On Map 0-1, which depicts the proposed SMU development wells, the injection well labeled "K Rebel" crosses through a small portion of Section 27, a section that appears to be unleased. For oil -related wells AOGCC requires a 500 -foot setback from property lines where ownership or landownership changes. Does Brooks Range own and/or operate Section 27? If not, will Brooks Range change the location of this well to honor a 500 - foot property line setback? You are correct, BRPC no longer owns/operates section 27 or the other leases outside and north/northwest of the SMU. As such any of the wells eventually drilled near those leases would need to have modified directional plans to abide by legal standoffs to the SMU boundary. If you need an updated map for that purpose, we can modify the current directional plans to accommodate that need. 4. AOGCC senior staff briefly reviewed the well history files for each of the wells drilled within the SMU. We did not find any indications that sidewall or conventional cores were taken. Brooks Range's AIO application provides specific range and average values for the porosity and permeability for the Mustang area. How were these values derived? Note that Regulation 20 AAC 25.071(b)(8) requires conventional and sidewall core analysis determinations including porosity, permeability, and fluid saturation, as well as all geochemical and formation fluid analyses. We did not find any such analyses in AOGCC's well history files. Please provide them if such analyses were conducted. We did not take any whole core or sidewall samples in the wells that have been drilled to -date in the SMU. If required under the Reg you state above, we can work that core sampling into our next phase of drilling. Fluid sampling is limited to those samples taken during the NTg1A well test. I can provide that data if it is not already in the AOGCC records. For general purposes I have been using average ranges of rock properties and fluid data which has been published as part of the KRU Unit reports to support volumetric calculations. Please provide references that support the statement: "Salinity of the Kuparuk Reservoir water in nearby Kuparuk River Unit producers found a salinity range from approximately 16,000 to 20,000 mg/I NaCl." I will refer to the original KRU Area Injection Order, or subsequent amendments, to find this quoted range of salinity. I am pretty sure I quoted that range from a previous application. 6. While reviewing AOGCC's well history file for the North Tarn 1A well we noticed that the Report of Sundry Well Operations (Form 10-404) for the fracture stimulation of the well received by AOGCC on Jan 17, 2018 did not contain the required Representative Daily Average Production Data subsequent to the fracturing operations. To complete AOGCC's record for this well, please submit Representative Daily Average Production values for oil, gas, water, casing pressure, and tubing pressure for the periods prior to and subsequent to the fracturing operation. If the well test from NT#1A is not already in the AOGCC database, we can provide that information. Other than that well test, there is no extended production data subsequent (Following) the wells test since the field is not yet on production. Thank you, Dave Roby 907-793-1232 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Dave Roby at 907- 793-1232 or dave.roby@alaska.zov. From: Roby, David S (DOA) Sent: Wednesday, May 1, 2019 10:23 AM To: Larry Vendl <Ivendl@brpcak.com> Cc: Colombie, Jody J (DOA) <iody.colombie@alaska.gov>; Larry J. Smith <Ismith@brpcak.com> Subject: RE: confidentiality of AID Application for SMU development Hi Larry, Thanks for bringing the revised application over. Regards, Dave Roby 907-793-1232 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Dave Roby at 907- 793-1232 or dave.robvrdalaska.¢ov. From: Larry Vendl <Ivendl@brpcak.com> Sent: Tuesday, April 30, 2019 5:53 PM To: Roby, David S (DOA) <dave.robv@alaska.gov> Cc: Colombie, Jody J (DOA) <jody.colombie@alaska.gov>; Larry J. Smith <Ismith@brpcak.com> Subject: Re: confidentiality of AID Application for SMU development No problem, Dave. I should have removed the confidential footers in the original submission. I think about 99% of the stuff in there is not sensitive. Maybe a net pay map and structure map, which are interpretive. Most everything else is out in the public, already. I will make new copies and drop those and a data disk off on Wednesday. 1119 Sent from my iPad On Apr 30, 2019, at 3:48 PM, Roby, David S (DOA) <dave.roby@alaska.gov> wrote: Larry, Here's our regulations on confidentiality of information: 20 AAC 25.537. Public and confidential information (a) The commission will routinely make available to the public, by means of records or reports, in its offices or elsewhere, or by means of regular publication, the following information: (1) surface and proposed bottom -hole locations of each well after approval of the Permit to Drill (Form 10-401); (2) total depth, bottom -hole location and well status after the Well Completion or Recompletion Report and Log (Form 10-407) is filed; (3) all reports and information required by this chapter for development and service wells; (4) regular production data and regular production reports, as required to be filed by the operator each month; (5) injection data and injection reports, as required to be filed by the operator each month; and (6) all data filed on a well as required by this chapter upon expiration of the confidential period described in (d) of this section. (b) Engineering, geologic, geophysical, and other commercial information not required by this chapter, but voluntarily filed with the commission will be kept confidential if the person filing the information so requests. This subsection does not apply to information submitted in a public hearing under 20 AAC 25.540. (c) In this section, "well status" means the classification of a well as oil, gas, service, suspended, shut-in, or abandoned. (d) Except as provided by (a) of this section, the reports and information required by this chapter to be filed by the operator for exploratory and stratigraphic test wells will be kept confidential by the commission for 24 months following the 30 -day filing period after well completion, suspension, or abandonment unless the operator gives written and unrestricted permission to release all of the reports and information at an earlier date. Upon notification that the commissioner of the Department of Natural Resources has made a finding that the required reports and information from a well contain significant information relating to the valuation of unleased land in the same vicinity, the commission will hold the reports and information confidential beyond the 24 -month period and until notified by the commissioner of the Department of Natural Resources to release the reports and information. 5 (e) Notwithstanding (b) or (d) of this section, any information obtained or used by the commission in the administration of its program under 42 U.S.C. 300h-4 (Safe Drinking Water Act of 1974, as amended, 42 U.S.C. 300f - 300j) (1) will be made available to the public unless the material has been claimed confidential and has been determined by the commission to be entitled to confidential treatment; claims of confidentiality will be denied for the following: (A) the name and address of any applicant for underground injection of fluids, and (B) information that deals with the existence, absence, or level of contaminants in freshwater; (2) will be made available to the United States Environmental Protection Agency upon request; if the information has been submitted to the commission under claim of confidentiality, the commission will submit that claim to the United States Environmental Protection Agency when providing the information. Part (e) is the most pertinent part here since it deals with implementation of the UIC program, which we do on behalf of the EPA, and it basically requires everything to be public unless you can demonstrate why something should be held confidential. Generally speaking, we'll usually hold stuff that is interpretive (like a seismic cross section, net pay map, interpreted log section, etc) confidential. That said if you have something that's interpretive and would be entitled to confidentiality if you could provide a non -confidential version of that (for example a structure map the omits faulting and doesn't label the contour depths) that would be appreciated, but is not mandatory. Regards, Dave Roby 907-793-1232 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Dave Roby at 907-793-1232 or dave.robv@alaska.gov. From: Larry Vendl <Ivendl@brpcak.com> Sent: Tuesday, April 30, 2019 3:17 PM To: Roby, David S (DOA) <dave.robv@alaska.gov> Cc: Colombie, Jody J (DOA) <icdy.colombie alaska.eov>; Larry J. Smith <Ismith@brpcak.com> Subject: RE: confidentiality of AID Application for SMU development I can do that, Dave. I think somehow the application text portion got labeled confidential. I think only portions of the attachment section should have the confidential stamps. Will you need to circulate for public review any of the supporting attachments, like a base maps, logs or tables? We can easily remove the confidential stamp from anything you deem needs to make public. Regards, LJV From: Roby, David S (DOA) <dave.robv@alaska.gov> Sent: Tuesday, April 30, 2019 3:00 PM To: Larry Vendl <Ivendl@brpcak.com> Cc: Colombie, Jody J (DOA) <lody.colombie@alaska.gov> Subject: confidentiality of AID Application for SMU development Hi Larry, The application you submitted for an AID for the SMU development has every single page marked as confidential. We need as much information as possible in the public domain and there's a lot of information in the application that isn't entitled to be held as confidential under our statutes and regulations. We need you to resubmit the application with only the stuff that truly is confidential marked as confidential and the remainder of the application available for public release. We've already scheduled the hearing and provided public notice for the application, so as long as you get the revised application to us in a reasonable amount of time the process won't get slowed up. Thank you, David Roby Senior Reservoir Engineer Alaska Oil and Gas Conservation Commission 907-793-1232 CONFIDENTIALITYNOTIa., This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Dave Roby at 907-793-1232 or dave.robv@alaska.aov. Roby, David S (CED) From: Larry Vendl <Ivendl@brpcak.com> Sent: Thursday, May 30, 2019 10:08 AM To: Roby, David S (CED) Subject: FW: confidentiality of AIO Application for SMU development... general answers to Dave's questions... Attachments: Salinity -Report West Sak 25590 15.pdf; Brooks_Range_Petroleum_West_Sak05590_15 _Salinity.las; Brooks_Range_Petroleum_West_Sak05590_15_Salinity_US.las; BRP _West _Sak_25590_Sa I i nity_Determination.pdf Dave, I am sending this again, without the cross-section pdf. I will send it under separate cover since it exceeded your allowable size of 20 MB. UV From: Larry Vend] Sent: Thursday, May 30, 2019 8:58 AM To: Roby, David S (DOA) <dave.roby@a]aska.gov> Subject: FW: confidentiality of AID Application for SMU development... general answers to Dave's questions... Dave, I attached the SLB Salinity Determination report that we commissioned for the nearby West Sak 25590-15 well. was chosen because it had the needed and most complete set of logs for the analysis. I also included a reduced size .pdf showing the well along with the Mustang wells and 2S pad to help demonstrate the lack of shallow aquifer sands. UV From: Larry Vend[ Sent: Wednesday, May 29, 2019 12:37 PM To: Roby, David S (DOA) <dave robe@alaska.gov>; Larry J. Smith <Ismith@brpcak.com>; Harry Bockmeulen (hbockmeulen@brpcak.com) <hbockmeulen@brpcak.com>; Dan Gleason <DGleason@brpcak.com> Subject: FW: confidentiality of AID Application for SMU development... general answers to Dave's questions... Dave, I will see what I can do to round up answers to your questions by our meeting next week. My general comments are in green font, below. Did you receive any public comments that need to be addressed in the meeting next week, or are all of your questions internal to the AOGCC? I wanted to make sure we come prepared. UV From: Roby, David S (CED) <dave.robv@alaska.gov> Sent: Wednesday, May 29, 2019 10:57 AM To: Larry Vendl <Ivendl@brpcak.com> Cc: Colombie, Jody 1 (CED) <iody.colombie@alaska.Kov>; Larry J. Smith <Ismith@brpcak.com> Subject: RE: confidentiality of AIO Application for SMU development Hi Larry, We have some questions on the AIO application that we'd like you to address. They are: Please provide a copy of Schlumberger's evaluation of formation water salinity for the SMU so that the AOGCC can verify Schlumbergers results, the methods used, and any assumptions made. Please provide information concerning how the well logging information from West Sak 25590-15 was calibrated using drill stem and production testing (e.g., discuss resulting porosity values, how they were determined, and why they are applicable to the SMU). I will provide SLB's evaluation and data used for the analysis. I don't think we included the report, which is only a couple of pages, in the application. I will need to check on the question of calibration used by SLB for the log analysis. 2. During past discussions, you indicated Brooks Range would supply one or more cross-sections to support Brooks Range's contention that no freshwater aquifers exist within the SMU. Please demonstrate the relationship of the shallow geologic section encountered in West Sak 25590-15 to similar strata within the SMU and confirm that salinity calculations for West Sak 25590-15 are relevant to aquifers within the SMU. I have constructed a general cross section which I can provide for you showing the wells currently in the SMU correlated to the shallow section of the West Sak 25590-15 and other nearby 2M pad and 2S pad wells. On Map 0-1, which depicts the proposed SMU development wells, the injection well labeled "K Rebel" crosses through a small portion of Section 27, a section that appears to be unleased. For oil -related wells AOGCC requires a 500 -foot setback from property lines where ownership or landownership changes. Does Brooks Range own and/or operate Section 27? If not, will Brooks Range change the location of this well to honor a 500 - foot property line setback? You are correct, BRPC no longer owns/operates section 27 or the other leases outside and north/northwest of the SMU. As such any of the wells eventually drilled near those leases would need to have modified directional plans to abide by legal standoffs to the SMU boundary. If you need an updated map for that purpose, we can modify the current directional plans to accommodate that need. 4. AOGCC senior staff briefly reviewed the well history files for each of the wells drilled within the SMU. We did not find any indications that sidewall or conventional cores were taken. Brooks Range's AIO application provides specific range and average values for the porosity and permeability for the Mustang area. How were these values derived? Note that Regulation 20 AAC 25.071(b)(8) requires conventional and sidewall core analysis determinations including porosity, permeability, and fluid saturation, as well as all geochemical and formation fluid analyses. We did not find any such analyses in AOGCC's well history files. Please provide them if such analyses were conducted. We did not take any whole core or sidewall samples in the wells that have been drilled to -date in the SMU. If required under the Reg you state above, we can work that core sampling into our next phase of drilling. Fluid sampling is limited to those samples taken during the NT#1A well test. I can provide that data if it is not already in the AOGCC records. For general purposes I have been using average ranges of rock properties and fluid data which has been published as part of the KRU Unit reports to support volumetric calculations. Please provide references that support the statement: "Salinity of the Kuparuk Reservoir water in nearby Kuparuk River Unit producers found a salinity range from approximately 16,000 to 20,000 mg/I NaCl." I will refer to the original KRU Area Injection Order, or subsequent amendments, to find this quoted range of salinity. I am pretty sure I quoted that range from a previous application. 6. While reviewing AOGCC's well history file for the North Tarn 1A well we noticed that the Report of Sundry Well Operations (Form 10-404) for the fracture stimulation of the well received by AOGCC on Jan 17, 2018 did not contain the required Representative Daily Average Production Data subsequent to the fracturing operations. To complete AOGCC's record for this well, please submit Representative Daily Average Production values for oil, gas, water, casing pressure, and tubing pressure for the periods prior to and subsequent to the fracturing operation. If the well test from NT#1A is not already in the AOGCC database, we can provide that information. Other than that well test, there is no extended production data subsequent (Following) the wells test since the field is not yet on production. Thank you, Dave Roby 907-793-1232 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Dave Roby at 907- 793-1232 or dave.robv@alaska.aov. From: Roby, David S (DOA) Sent: Wednesday, May 1, 2019 10:23 AM To: Larry Vend] <Ivendl(@brpcak.com> Cc: Colombie, Jody J (DOA) <jody.colombie@alaska.gov>; Larry J. Smith <Ismith@brpcak.com> Subject: RE: confidentiality of AIO Application for SMU development Hi Larry, Thanks for bringing the revised application over. Regards, Dave Roby 907-793-1232 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Dave Roby at 907- 793-1232 or dave.roby@alaska.Rov. From: Larry Vendl <Ivendl@brpcak.com> Sent: Tuesday, April 30, 2019 5:53 PM To: Roby, David S (DOA) <dave.robv@alaska.aov> Cc: Colombie, Jody 1 (DOA) <lody.colombie@alaska.gov>; Larry J. Smith <Ismith@brpcak.com> Subject: Re: confidentiality of AID Application for SMU development No problem, Dave. I should have removed the confidential footers in the original submission. I think about 99% of the stuff in there is not sensitive. Maybe a net pay map and structure map, which are interpretive. Most everything else is out in the public, already. I will make new copies and drop those and a data disk off on Wednesday. Sent from my iPad On Apr 30, 2019, at 3:48 PM, Roby, David S (DOA) <dave.roby@alaska.eov> wrote: Larry, Here's our regulations on confidentiality of information: 20 AAS 25.537. Public and confidential information (a) The commission will routinely make available to the public, by means of records or reports, in its offices or elsewhere, or by means of regular publication, the following information: (1) surface and proposed bottom -hole locations of each well after approval of the Permit to Drill (Form 10-401); (2) total depth, bottom -hole location and well status after the Well Completion or Recompletion Report and Log (Form 10-407) is filed; (3) all reports and information required by this chapter for development and service wells; (4) regular production data and regular production reports, as required to be filed by the operator each month; (5) injection data and injection reports, as required to be filed by the operator each month; and (6) all data filed on a well as required by this chapter upon expiration of the confidential period described in (d) of this section. (b) Engineering, geologic, geophysical, and other commercial information not required by this chapter, but voluntarily filed with the commission will be kept confidential if the person filing the information so requests. This subsection does not apply to information submitted in a public hearing under 20 AAC 25.540. (c) In this section, "well status" means the classification of a well as oil, gas, service, suspended, shut-in, or abandoned. (d) Except as provided by (a) of this section, the reports and information required by this chapter to be filed by the operator for exploratory and stratigraphic test wells will be kept confidential by the commission for 24 months following the 30 -day filing period after well completion, suspension, or abandonment unless the operator gives written and unrestricted permission to release all of the reports and information at an earlier date. Upon notification that the commissioner of the Department of Natural Resources has made a finding that the required reports and information from a well contain significant information relating to the valuation of unleased land in the same vicinity, the commission will hold the reports and information confidential beyond the 24 -month period and until notified by the commissioner of the Department of Natural Resources to release the reports and information. (e) Notwithstanding (b) or (d) of this section, any information obtained or used by the commission in the administration of its program under 42 U.S.C. 300h-4 (Safe Drinking Water Act of 1974, as amended, 42 U.S.C. 300f - 300j) (1) will be made available to the public unless the material has been claimed confidential and has been determined by the commission to be entitled to confidential treatment; claims of confidentiality will be denied for the following: 4 (A) the name and address of any applicant for underground injection of Fluids, and (B) information that deals with the existence, absence, or level of contaminants in freshwater; (2) will be made available to the United States Environmental Protection Agency upon request; if the information has been submitted to the commission under claim of confidentiality, the commission will submit that claim to the United States Environmental Protection Agency when providing the information. Part (e) is the most pertinent part here since it deals with implementation of the UIC program, which we do on behalf of the EPA, and it basically requires everything to be public unless you can demonstrate why something should be held confidential. Generally speaking, we'll usually hold stuff that is interpretive (like a seismic cross section, net pay map, interpreted log section, etc) confidential. That said if you have something that's interpretive and would be entitled to confidentiality if you could provide a non -confidential version of that (for example a structure map the omits faulting and doesn't label the contour depths) that would be appreciated, but is not mandatory. Regards, Dave Roby 907-793-1232 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Dave Roby at 907-793-1232 or dave.robv@alaska.gov. From: Larry Vendl <Ivendl@brpcak.com> Sent: Tuesday, April 30, 2019 3:17 PM To: Roby, David S (DOA) <dave.roby@alaska.gov> Cc: Colombie, Jody J (DOA) <jody.colombie@alaska.eov>; Larry J. Smith <Ismith@brpcak.com> Subject: RE: confidentiality of AID Application for SMU development I can do that, Dave. I think somehow the application text portion got labeled confidential. I think only portions of the attachment section should have the confidential stamps. Will you need to circulate for public review any of the supporting attachments, like a base maps, logs or tables? We can easily remove the confidential stamp from anything you deem needs to make public. Regards, W From: Roby, David S (DOA) <dave.roby@alaska.gov> Sent: Tuesday, April 30, 2019 3:00 PM To: Larry Vendl <Ivendl@brpcak.com> Cc: Colombie, Jody J (DOA) <jody.colombie@alaska.l¢ov> Subject: confidentiality of AID Application for SMU development Hi Larry, The application you submitted for an AIO for the SMU development has every single page marked as confidential. We need as much information as possible in the public domain and there's a lot of information in the application that isn't entitled to be held as confidential under our statutes and regulations. We need you to resubmit the application with only the stuff that truly is confidential marked as confidential and the remainder of the application available for public release. We've already scheduled the hearing and provided public notice for the application, so as long as you get the revised application to us in a reasonable amount of time the process won't get slowed up. Thank you, David Roby Senior Reservoir Engineer Alaska Oil and Gas Conservation Commission 907-793-1232 CONFIDENTIALITYNOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Dave Roby at 907-793-1232 or dave.robv@alaska.¢ov. D 3 CCD m 0 N to CD Or O v o a:)n m Q- c) O-timm0 .... -nen D O C1 0 0 N rn C D CD a 3 o o O W Cn CoD Z p i co o (n D N N 77 m C O_ o N C U) (n X n O 1 UI r � ? O Q N Ot Cn ro O Cn FOLD HERE The well name, location and borehole reference data were i unshed by the customer. 0 Any interpretation, research, analysis, data, results, estimates, or recommendation furnished with the services or otherwise communicated by Schlumberger to the customer at any time in connection with the services are opinions based on inferences torn measurements, empirical relatonships, and/or assumptions; which, inferences, empirical relationships and/or assumptions are not infallible and with respect b which professionals in the industry may differ. Accordingly, Schlumberger cannot and does notwarrant the accuracy, correctness, or completeness of any such interpretation, research, analysis, data, results, estimatss, or recommendation. The customer acknowledges that it is accepting the services "as is," that Schlumberger makes no representation or warranty, express or implied, of any kind or description in respect thereto, and that such services are delivered with the explicit understanding and agreement that any action taken based on the services received shall be at its own risk and responsibility, and no daim shall be made againstSchlurrberger as a consequence thereof. InthrpretflonCenter: Analyst: ]Burt2@slb.com IProcessDale: 4/17/2019 Techlog Vers: 2017.1 Mud and Borehole Measurements: N O C1 N rn C D CD a 3 a 0 1 UI r � ? O Q FOLD HERE The well name, location and borehole reference data were i unshed by the customer. 0 Any interpretation, research, analysis, data, results, estimates, or recommendation furnished with the services or otherwise communicated by Schlumberger to the customer at any time in connection with the services are opinions based on inferences torn measurements, empirical relatonships, and/or assumptions; which, inferences, empirical relationships and/or assumptions are not infallible and with respect b which professionals in the industry may differ. Accordingly, Schlumberger cannot and does notwarrant the accuracy, correctness, or completeness of any such interpretation, research, analysis, data, results, estimatss, or recommendation. The customer acknowledges that it is accepting the services "as is," that Schlumberger makes no representation or warranty, express or implied, of any kind or description in respect thereto, and that such services are delivered with the explicit understanding and agreement that any action taken based on the services received shall be at its own risk and responsibility, and no daim shall be made againstSchlurrberger as a consequence thereof. InthrpretflonCenter: Analyst: ]Burt2@slb.com IProcessDale: 4/17/2019 Techlog Vers: 2017.1 Mud and Borehole Measurements: 0 cm L co C.� C� c O c� E Q� Q) Al N M O m E L - 0 O Schlumberger Formation Water Salinity Determination West Sak 2559015 Company Brooks Range Petroleum Field Kuparuk Well West Sak 2559015 Date Logged 21 -Nov -2012 Date Processed 11 -Dec -2012 API Number 50-103-20013-00-00 Log Analyst Jason Burt, Ph.D. Reviewed by Douglas Hupp II interpretations are opinions based on inferences from electrical or other measurements and we cannot, and do not guarantee the accuracy or correctness of any interpretations and e shall not, except in the case of gross or willful negligence on our part, be liable or responsible for any loss, cast, damages or expenses incurred or sustained by anyone resulting ram any interpretation made by any of aur officers, agents or employees. These interpretations are also subject to orause 4 of our general terms and conditions asset out in our current rice schedule, Schlumberger-lar iva t e Apache Log Date: 21—March-1980 Feld: Kuoaruk Well: West Sak 25590015 Introduction Brooks Range Petroleum has asked Schlumberger to evaluate the salinity of the formation water on well West Sak 2559015, which was drilled in March 1980. The interval analyzed was from 1000 — 6325 ft MD ft. The data available for this evaluation included Resistivity, Gamma Ray and Sonic providing compressional transit time. Salinity Determination The salinity of the formation water (Rw) was determined by Awa interpretation from a porosity calculated with the compressional transit time. This technique assumes the fluid in the formation is water with no hydrocarbon. The charts used in this work are included in this report. Rwa Interpretation Rwa interpretation consists of the following steps. 1. Determine Rt from the DIL log 2. Determine Atlog from sonic log 3. Calculate porosity (0) from the sonic log SonicPorosity = DT — 55.6 x CP 189-55.6 CP = 0.0001 * TVD + 0.3 4. Calculate Rwa (Rwa = 01 x Rt/0.81) 5. Convert RWA at formation temperature to RWA at 60 degF (RWA60) using the equation from Schlumberger Chart Book (2013 edition) Gen -6. a. RWA RWA FT&MP+S77 60 = FTBMP 6n+&77 6. Convert RWA60 to Salinity using the equation derived from the Schlumberger ELAN parameter calculations (Chart Gen -9). a. SALINI77 = 7.3966 x R WA60(—lloz) SALINITY=7.3966xRWA6 The sonic measurement in this well is a source of uncertainty in the Rwa interpretation technique. Sonic measurements at shallow depths can be affected by poor compaction of the rock. If this is the case, the sonic porosity calculated from the equation in step 3 (above) may result in an optimistic (high) interpreted porosity. Thus, the sonic porosity was calculated using a compaction correction (CP) in order compute an Rwa that is calibrated to one calculated with density porosity in the intermediate section. The Salinity calculation was determined using a temperature gradient of 1.571 degree/100 ft starting at a surface temperature of 10 degrees Fahrenheit until the base of the permafrost where a gradient of 2.783 degF/100 ft was used. The Salinity values are provided in the accompanying las file and within the log provided. If you have any questions regarding the formation water salinity calculations, please feel free to contact Jason Burt or Doug Hupp at (907) 273-1700. Schlumberger -Private Apache Log Date: 21--March-1980 Field: Kuoaruk Well: West Sak 255900 15 Resistivity of NaCl Water Solutions 5cmumherger Gem 6 1!oime1Gsa.3i Conversion appmnmated by R,= R, I)T, a 6.TIyIT,+ 6.77)PF or R, = R, IIT, + 21.51/(1, a 21.5)1'C 10 B 6 5 4 3 2 I 01 0.6 0.5 0.4 Resistivity 03 of solution [ohm -m) 01 0.1 0.06 0.06 0.05 0.04 002 0.01 °F 50 °c 10 ®R 7M )41 '!M t5n em 20 30 40 50 60 70 60 90 100 120 140 160 160 200 fm attire Schlumberger -Private grains/gal PPM at7FF fb0 10 'bo z 15 00 20 to 25 t0 30 1b to 40 COm 50 100 NaCl q0) ISO NaCl c®loom or 200 gainslgaq 400 250 000 300 $� 400 !0,(♦q! 500 lzR7o 14 0 A� 1000 �% 1.500 @?qIo 2,1100 4 % 2,500 SO0 3.000 )p 0 bZ 4,000 707q� 5.000 %O0 l70a0 d/0 10,000 15,000 20,000 Roby, David S (CED) From: Larry Vendl <lvendl@brpcak.com> Sent: Thursday, May 30, 2019 3:45 PM To: Roby, David S (CED) Cc: Dan Gleason; Larry J. Smith Subject: Questions from Dave Roby regarding reservoir conditions at Mustang.... Dave, I will send this to Dan Gleason and Larry Smith who can verify my answers, below. Guys, correct me if I got anything wrong .... my answers are in green font, below. Dan, you are in the Best position to answer Question #3 regarding the surface injection pressures. I think we constructed a table in the application for that, no? UV From: Roby, David S (CED) <dave.roby@alaska.gov> Sent: Thursday, May 30, 2019 3:11 PM To: Larry Vendl <Ivendl@brpcak.com> Cc: Larry J. Smith <Ismith@brpcak.com> Subject: RE: [ZendTo] Cross section transfer Hi Larry A few more questions for you: 1) What's the OOIP in the development area, and how's that split between the A and C sands? The official D&M 1P reserve estimate uses a DDT of -6104 TVDss and a 30% recovery efficiency, which calculates to approximately 70.6 MMBO OOIP a provides a 1P reserve basis of 21.2 MMBO. 2P and 3P reserves are calculated with the structure filled -to -spill and 35% and 40% respectively, which would be calculated from a larger OOIP. 2) What are the reservoir fluid properties in this area, and is there a difference between the properties in the A and C sands? a. API gravity? 23.9 (From fluid analysis from NT #1A test) b. Viscosity? 2.1 cP c. GOR? Estimated to be approximately 600, initially, but will rise rather quickly until injection support is available. d. Reservoir pressure? As high as 3850 PSI due to overpressure from nearby injection. Production along lease line has probably reduced this pressure to some degree. We are planning on pressures in the range of 10.8 ppg to 12.1 ppg and will be using MPD on the rig. e. Bubble point pressure? Estimated to be 1930 PSI f. Formation volume factor? 1.21 3) What are the corresponding surface injection pressures, for both water and gas injection phases, that correspond to the 0.67 psi/ft max allowable and 0.62 psi/ft average injection pressure gradients? I think there is a table showing this in the application. I will need to check. I will pass this on to Dan Gleason. I think he will have this information 4) Hasa LOT been conducted in the Kalubik in any of the wells in the area, and if so which well(s) and what were the results? There should be LOT at the intermediate casing points for North Tarn #1A, Mustang 1 and the KRU @L-03 wells. This information is probably on file in the well history files. You can either provide this information before Tuesday's hearing or at the hearing itself. Thanks, Dave Roby 907-793-1232 CONFIDENTIALITY NOTICE.• This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this a -mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Dave Roby at 907- 793-1232 or dave.robv@alaska.zov. From: Larry Vendl <Ivendl@brpcak.com> Sent: Thursday, May 30, 2019 12:54 PM To: Roby, David S (CED) <dave.roby@alaska.gov> Cc: Larry J. Smith <Ismith@brpcak.com> Subject: RE: [ZendTo] Cross section transfer Great! Do you think we can work through any further details next Tuesday at our meeting? If there are any loose ends that I can help with ahead of our 10am meeting, just let me know. UV From: Roby, David S (CED) <dave.roby@alaska.gov> Sent: Thursday, May 30, 2019 12:47 PM To: Larry Vendl <Ivendl@brpcak.com> Subject: RE: [ZendTo) Cross section transfer Got it Larry, thanks for sending it over. Yeah, I wasn't aware we had this capability until I asked our IT guy about ShareFile. I've always just used our FTP site for transfers, but don't think people outside the AOGCC can put stuff on our FTP site. Regards, Dave Roby 907-793-1232 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Dave Roby at 907- 793-1232 or dave.robv@alaska.zov. From: Larry Vendl <Ivendl@brpcak.com> Sent: Thursday, May 30, 2019 12:06 PM To: Roby, David S (CED) <dave.roby@alaska.gov> Subject: RE: [ZendTo) Cross section transfer It should be in your drop box, Dave. Good to know that exists, Thanks Lli From: ZendTo <noreply@state.ak.us> Sent: Thursday, May 30, 2019 11:51 AM To: Larry Vendl <Ivendl@brpcak.com> Subject: [ZendTo] Cross section transfer Larry Vendl, This is a request from David Roby of AOGCC. Please click on the link below and drop off the file or files I have requested. The link is only valid for 24 hours from the time of this email. More information is in the note below. https://drop.state.ak.us/drop/req.php?req=378904328 If you wish to contact David Roby, just reply to this email. — Note — Hi Larry, I've set this up so you can use the states preferred file transfer system without having to confirm your email address. Dave Roby David Roby dave.roby@alaska.gov AOGCC Copyright © 2018 ZendTo I About Alaska ZendTo This service is powered by a copy of ZendTo 3 Colombie, Jody J (CED) From: Roby, David S (CED) Sent: Wednesday, May 29, 2019 10:57 AM To: Larry Vendl Cc: Colombie, Jody 1 (CED); Larry J. Smith Subject: RE: confidentiality of AIO Application for SMU development Hi Larry We have some questions on the AID application that we'd like you to address. They are: 1. Please provide a copy of Schlumberger's evaluation of formation water salinity for the SMU so that the AOGCC can verify Schlumberger's results, the methods used, and any assumptions made. Please provide information concerning how the well logging information from West Sak 25590-15 was calibrated using drill stem and production testing (e.g., discuss resulting porosity values, how they were determined, and why they are applicable to the SMU). 2. During past discussions, you indicated Brooks Range would supply one or more cross-sections to support Brooks Range's contention that no freshwater aquifers exist within the SMU. Please demonstrate the relationship of the shallow geologic section encountered in West Sak 25590-15 to similar strata within the SMU and confirm that salinity calculations for West Sak 25590-15 are relevant to aquifers within the SMU. 3. On Map 0-1, which depicts the proposed SMU development wells, the injection well labeled "K Rebel" crosses through a small portion of Section 27, a section that appears to be unleased. For oil -related wells AOGCC requires a 500 -foot setback from property lines where ownership or landownership changes. Does Brooks Range own and/or operate Section 27? If not, will Brooks Range change the location of this well to honor a 500 - foot property line setback? 4. AOGCC senior staff briefly reviewed the well history files for each of the wells drilled within the SMU. We did not find any indications that sidewall or conventional cores were taken. Brooks Range's AID application provides specific range and average values for the porosity and permeability for the Mustang area. How were these values derived? Note that Regulation 20 AAC 25.071(b)(8) requires conventional and sidewall core analysis determinations including porosity, permeability, and fluid saturation, as well as all geochemical and formation fluid analyses. We did not find any such analyses in AOGCC's well history files. Please provide them if such analyses were conducted. 5. Please provide references that support the statement: "Salinity of the Kuparuk Reservoir water in nearby Kuparuk River Unit producers found a salinity range from approximately 16,000 to 20,000 mg/I NaCl." 6. While reviewing AOGCC's well history file for the North Tarn 1A well we noticed that the Report of Sundry Well Operations (Form 10-404) for the fracture stimulation of the well received by AOGCC on Jan 17, 2018 did not contain the required Representative Daily Average Production Data subsequent to the fracturing operations. To complete AOGCC's record for this well, please submit Representative Daily Average Production values for oil, gas, water, casing pressure, and tubing pressure for the periods prior to and subsequent to the fracturing operation. Thank you, Dave Roby 907-793-1232 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Dave Roby at 907- 793-1232 or dave.robv@alaska.aov. From: Roby, David S (DOA) Sent: Wednesday, May 1, 2019 10:23 AM To: Larry Vendl <Ivendl@brpcak.com> Cc: Colombie, Jody 1 (DOA) <jody.colombie@alaska.gov>; Larry J. Smith <Ismith@brpcak.com> Subject: RE: confidentiality of AID Application for SMU development Hi Larry, Thanks for bringing the revised application over. Regards, Dave Roby 907-793-1232 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state orfederal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Dave Roby at 907- 793-1232 or dave.robv@alaska.gov. From: Larry Vendl <Ivendl@brocak.com> Sent: Tuesday, April 30, 2019 5:53 PM To: Roby, David S (DOA) <dave.robv@alaska.gov> Cc: Colombie, Jody J (DOA) <iodv.colombie@alaska.gov>; Larry J. Smith <Ismith@brocak.com> Subject: Re: confidentiality of AID Application for SMU development No problem, Dave. I should have removed the confidential footers in the original submission. I think about 99% of the stuff in there is not sensitive. Maybe a net pay map and structure map, which are interpretive. Most everything else is out in the public, already. I will make new copies and drop those and a data disk off on Wednesday. UV Sent from my iPad On Apr 30, 2019, at 3:48 PM, Roby, David S (DOA) <dave.robv@alaska.gov> wrote: Larry, Here's our regulations on confidentiality of information: 20 AAC 25.537. Public and confidential information (a) The commission will routinely make available to the public, by means of records or reports, in its offices or elsewhere, or by means of regular publication, the following information: (1) surface and proposed bottom -hole locations of each well after approval of the Permit to Drill (Form 10-401); (2) total depth, bottom -hole location and well status after the Well Completion or Recompletion Report and Log (Form 10-407) is filed; (3) all reports and information required by this chapter for development and service wells; (4) regular production data and regular production reports, as required to be filed by the operator each month; (5) injection data and injection reports, as required to be filed by the operator each month; and (6) all data filed on a well as required by this chapter upon expiration of the confidential period described in (d) of this section. (b) Engineering, geologic, geophysical, and other commercial information not required by this chapter, but voluntarily filed with the commission will be kept confidential if the person filing the information so requests. This subsection does not apply to information submitted in a public hearing under 20 AAC 25.540. (c) In this section, "well status" means the classification of a well as oil, gas, service, suspended, shut-in, or abandoned. (d) Except as provided by (a) of this section, the reports and information required by this chapter to be filed by the operator for exploratory and stratigraphic test wells will be kept confidential by the commission for 24 months following the 30 -day filing period after well completion, suspension, or abandonment unless the operator gives written and unrestricted permission to release all of the reports and information at an earlier date. Upon notification that the commissioner of the Department of Natural Resources has made a finding that the required reports and information from a well contain significant information relating to the valuation of unleased land in the same vicinity, the commission will hold the reports and information confidential beyond the 24 -month period and until notified by the commissioner of the Department of Natural Resources to release the reports and information. (e) Notwithstanding (b) or (d) of this section, any information obtained or used by the commission in the administration of its program under 42 U.S.C. 300h-4 (Safe Drinking Water Act of 1974, as amended, 42 U.S.C. 300f - 300j) (1) will be made available to the public unless the material has been claimed confidential and has been determined by the commission to be entitled to confidential treatment; claims of confidentiality will be denied for the following: (A) the name and address of any applicant for underground injection of Fluids, and (B) information that deals with the existence, absence, or level of contaminants in freshwater; (2) will be made available to the United States Environmental Protection Agency upon request; if the information has been submitted to the commission under claim of 3 confidentiality, the commission will submit that claim to the United States Environmental Protection Agency when providing the information. Part (e) is the most pertinent part here since it deals with implementation of the UIC program, which we do on behalf of the EPA, and it basically requires everything to be public unless you can demonstrate why something should be held confidential. Generally speaking, we'll usually hold stuff that is interpretive (like a seismic cross section, net pay map, interpreted log section, etc) confidential. That said if you have something that's interpretive and would be entitled to confidentiality if you could provide a non -confidential version of that (for example a structure map the omits faulting and doesn't label the contour depths) that would be appreciated, but is not mandatory. Regards, Dave Roby 907-793-1232 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Dave Roby at 907-793-1232 or dave.robyPalaska.eov. From: Larry Vendl <Ivendl@brpcak.com> Sent: Tuesday, April 30, 2019 3:17 PM To: Roby, David S (DOA) <dave.robv@alaska.eov> Cc: Colombie, Jody J (DOA) <jody.colombie@alaska.Rov>; Larry J. Smith <Ismith@brpcak.com> Subject: RE: confidentiality of AIO Application for SMU development I can do that, Dave. I think somehow the application text portion got labeled confidential. I think only portions of the attachment section should have the confidential stamps. Will you need to circulate for public review any of the supporting attachments, like a base maps, logs or tables? We can easily remove the confidential stamp from anything you deem needs to make public. Regards, LJV From: Roby, David S (DOA) <dave.robv@alaska.aov> Sent: Tuesday, April 30, 2019 3:00 PM To: Larry Vendl <Ivendl@brpcak.com> Cc: Colombie, Jody J (DOA) <iodv.colombie@alaska.gov> Subject: confidentiality of AID Application for SMU development Hi Larry, The application you submitted for an AIO for the SMU development has every single page marked as confidential. We need as much information as possible in the public domain and there's a lot of information in the application that isn't entitled to be held as confidential under our statutes and regulations. We need you to resubmit the application with only the stuff that truly is confidential marked as confidential and the remainder of the application available for public release. We've already scheduled the hearing and provided public notice for the application, so as long as you get the revised application to us in a reasonable amount of time the process won't get slowed up. Thank you, David Roby Senior Reservoir Engineer Alaska Oil and Gas Conservation Commission 907-793-1232 CONFIDENTIALITY NOTICE., This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Dave Roby at 907-793-1232 or dave.robv@alaska.eov. Roby, David S (CED) From: Larry Vendl <Ivendl@brpcak.com> Sent: Wednesday, May 29, 2019 12:37 PM To: Roby, David S (CED); Larry J. Smith; Harry Bockmeulen; Dan Gleason Subject: FW: confidentiality of AIO Application for SMU development... general answers to Dave's questions... Dave, I will see what I can do to round up answers to your questions by our meeting next week. My general comments are in green font, below. Did you receive any public comments that need to be addressed in the meeting next week, or are all of your questions internal to the AOGCC? I wanted to make sure we come prepared. UV From: Roby, David S (CED) <dave.roby@alaska.gov> Sent: Wednesday, May 29, 2019 10:57 AM To: Larry Vendl <Ivendl@brpcak.com> Cc: Colombie, Jody J (CED) <jody.colombie@alaska.gov>; Larry J. Smith <Ismith@brpcak.com> Subject: RE: confidentiality of AID Application for SMU development Hi Larry, We have some questions on the AID application that we'd like you to address. They are: 1. Please provide a copy of Schlumberger's evaluation of formation water salinity for the SMU so that the AOGCC can verify Schlumberger's results, the methods used, and any assumptions made. Please provide information concerning how the well logging information from West Sak 25590-15 was calibrated using drill stem and production testing (e.g., discuss resulting porosity values, how they were determined, and why they are applicable to the SMU). I will provide SLB's evaluation and data used for the analysis. I don't think we included the report, which is only a couple of pages, in the application. I will need to check on the question of calibration used by SLB for the log analysis. 2. During past discussions, you indicated Brooks Range would supply one or more cross-sections to support Brooks Range's contention that no freshwater aquifers exist within the SMU. Please demonstrate the relationship of the shallow geologic section encountered in West Sak 25590-15 to similar strata within the SMU and confirm that salinity calculations for West Sak 25590-15 are relevant to aquifers within the SMU. I have constructed a general cross section which I can provide for you showing the wells currently in the SMU correlated to the shallow section of the West Sak 25590-15 and other nearby 2M pad and 2S pad wells. 3. On Map 0-1, which depicts the proposed SMU development wells, the injection well labeled "K Rebel" crosses through a small portion of Section 27, a section that appears to be unleased. For oil -related wells AOGCC requires a 500 -foot setback from property lines where ownership or landownership changes. Does Brooks Range own and/or operate Section 27? If not, will Brooks Range change the location of this well to honor a 500 - foot property line setback? You are correct, BRPC no longer owns/operates section 27 or the other leases outside and north/northwest of the SMU. As such any of the wells eventually drilled near those leases would need to have modified directional plans to abide by legal standoffs to the SMU boundary. If you need an updated map for that purpose, we can modify the current directional plans to accommodate that need. 4. AOGCC senior staff briefly reviewed the well history files for each of the wells drilled within the SMU. We did not find any indications that sidewall or conventional cores were taken. Brooks Range's AIO application provides specific range and average values for the porosity and permeability for the Mustang area. How were these values derived? Note that Regulation 20 AAC 25.071(b)(8) requires conventional and sidewall core analysis determinations including porosity, permeability, and fluid saturation, as well as all geochemical and formation fluid analyses. We did not find any such analyses in AOGCC's well history files. Please provide them if such analyses were conducted. We did not take any whole core or sidewall samples in the wells that have been drilled to -date in the SMU. If required under the Reg you state above, we can work that core sampling into our next phase of drilling. Fluid sampling is limited to those samples taken during the NT#1A well test. I can provide that data if it is not already in the AOGCC records. For general purposes I have been using average ranges of rock properties and fluid data which has been published as part of the KRU Unit reports to support volumetric calculations. Please provide references that support the statement: "Salinity of the Kuparuk Reservoir water in nearby Kuparuk River Unit producers found a salinity range from approximately 16,000 to 20,000 mg/I NaCl." I will refer to the original KRU Area Injection Order, or subsequent amendments, to find this quoted range of salinity. I am pretty sure I quoted that range from a previous application. 6. While reviewing AOGCC's well history file for the North Tarn 1A well we noticed that the Report of Sundry Well Operations (Form 10-404) for the fracture stimulation of the well received by AOGCC on Ian 17, 2018 did not contain the required Representative Daily Average Production Data subsequent to the fracturing operations. To complete AOGCC's record for this well, please submit Representative Daily Average Production values for oil, gas, water, casing pressure, and tubing pressure for the periods prior to and subsequent to the fracturing operation. If the well test from NT#1A is not already in the AOGCC database, we can provide that information. Other than that well test, there is no extended production data subsequent (Following) the wells test since the field is not yet on production. Thank you, Dave Roby 907-793-1232 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Dave Roby at 907- 793-1232 or dave.robv@alaska.eov. From: Roby, David S (DOA) Sent: Wednesday, May 1, 2019 10:23 AM To: Larry Vendl <]vendl@brpcak.com> Cc: Colombie, Jody 1 (DOA) <jody.colombie@alaska.aov>; Larry J. Smith <Ismith@brpcak.com> Subject: RE: confidentiality of AIO Application for SMU development Hi Larry, Thanks for bringing the revised application over. Regards, Dave Roby 907-793-1232 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Dave Roby at 907- 793-1232 or dave.robv@alaska.zov. From: Larry Vendl <Ivendl@brpcak.com> Sent: Tuesday, April 30, 2019 5:53 PM To: Roby, David S (DOA) <dave.robv@alaska.aov> Cc: Colombie, Jody J (DOA) <Lody.colombie@alaska.Pov>; Larry J. Smith <Ismith@brpcak.com> Subject: Re: confidentiality of AIO Application for SMU development No problem, Dave. I should have removed the confidential footers in the original submission. I think about 99% of the stuff in there is not sensitive. Maybe a net pay map and structure map, which are interpretive. Most everything else is out in the public, already. I will make new copies and drop those and a data disk off on Wednesday. IPI Sent from my iPad On Apr 30, 2019, at 3:48 PM, Roby, David S (DOA) <dave.robv@alaska.gov> wrote: Larry, Here's our regulations on confidentiality of information: 20 AAC 25.537. Public and confidential information (a) The commission will routinely make available to the public, by means of records or reports, in its offices or elsewhere, or by means of regular publication, the following information: (1) surface and proposed bottom -hole locations of each well after approval of the Permit to Drill (Form 10-401); (2) total depth, bottom -hole location and well status after the Well Completion or Recompletion Report and Log (Form 10-407) is filed; (3) all reports and information required by this chapter for development and service wells; (4) regular production data and regular production reports, as required to be filed by the operator each month; (5) injection data and injection reports, as required to be filed by the operator each month; and (6) all data filed on a well as required by this chapter upon expiration of the confidential period described in (d) of this section. (b) Engineering, geologic, geophysical, and other commercial information not required by this chapter, but voluntarily filed with the commission will be kept confidential if the person filing the information so requests. This subsection does not apply to information submitted in a public hearing under 20 AAC 25.540. 91 (c) In this section, "well status" means the classification of a well as oil, gas, service, suspended, shut-in, or abandoned. (d) Except as provided by (a) of this section, the reports and information required by this chapter to be filed by the operator for exploratory and stratigraphic test wells will be kept confidential by the commission for 24 months following the 30 -day filing period after well completion, suspension, or abandonment unless the operator gives written and unrestricted permission to release all of the reports and information at an earlier date. Upon notification that the commissioner of the Department of Natural Resources has made a finding that the required reports and information from a well contain significant information relating to the valuation of unleased land in the same vicinity, the commission will hold the reports and information confidential beyond the 24 -month period and until notified by the commissioner of the Department of Natural Resources to release the reports and information. (e) Notwithstanding (b) or (d) of this section, any information obtained or used by the commission in the administration of its program under 42 U.S.C. 300h-4 (Safe Drinking Water Act of 1974, as amended, 42 U.S.C. 300f - 300j) (1) will be made available to the public unless the material has been claimed confidential and has been determined by the commission to be entitled to confidential treatment; claims of confidentiality will be denied for the following: (A) the name and address of any applicant for underground injection of Fluids, and (B) information that deals with the existence, absence, or level of contaminants in freshwater; (2) will be made available to the United States Environmental Protection Agency upon request; if the information has been submitted to the commission under claim of confidentiality, the commission will submit that claim to the United States Environmental Protection Agency when providing the information. Part (e) is the most pertinent part here since it deals with implementation of the UIC program, which we do on behalf of the EPA, and it basically requires everything to be public unless you can demonstrate why something should be held confidential. Generally speaking, we'll usually hold stuff that is interpretive (like a seismic cross section, net pay map, interpreted log section, etc) confidential. That said if you have something that's interpretive and would be entitled to confidentiality if you could provide a non -confidential version of that (for example a structure map the omits faulting and doesn't label the contour depths) that would be appreciated, but is not mandatory. Regards, Dave Roby 907-793-1232 CONFIDENTIALITY NOTICE This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Dave Roby at 907-793-1232 or dave.roby@alaska.gov. 4 From: Larry Vendl <Ivendl@brpcak.com> Sent: Tuesday, April 30, 2019 3:17 PM To: Roby, David S (DOA) <dave.roby@alaska.aov> Cc: Colombie, Jody J (DOA) <iody.colombie@alaska.gov>; Larry J. Smith <Ismith@brpcak.com> Subject: RE: confidentiality of AIO Application for SMU development I can do that, Dave. I think somehow the application text portion got labeled confidential. I think only portions of the attachment section should have the confidential stamps. Will you need to circulate for public review any of the supporting attachments, like a base maps, logs or tables? We can easily remove the confidential stamp from anything you deem needs to make public. Regards, Uv From: Roby, David S (DOA) <dave.roby@alaska.aov> Sent: Tuesday, April 30, 2019 3:00 PM To: Larry Vendl <Ivendl(a@brpcak.com> Cc: Colombie, Jody 1 (DOA) <iody.colombie@alaska.gov> Subject: confidentiality of NO Application for SMU development Hi Larry, The application you submitted for an AIO for the SMU development has every single page marked as confidential. We need as much information as possible in the public domain and there's a lot of information in the application that isn't entitled to be held as confidential under our statutes and regulations. We need you to resubmit the application with only the stuff that truly is confidential marked as confidential and the remainder of the application available for public release. We've already scheduled the hearing and provided public notice for the application, so as long as you get the revised application to us in a reasonable amount of time the process won't get slowed up. Thank you, David Roby Senior Reservoir Engineer Alaska Oil and Gas Conservation Commission 907-793-1232 CONFIDENTIALITYNOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Dave Roby at 907-793-1232 or dave.robv(@alaska.zov. Roby, David S (CED) From: Larry Vencil <Ivendl@brpcak.com> Sent: Tuesday, April 30, 2019 5:53 PM To: Roby, David S (DOA) Cc: Colombie, Jody J (DOA); Larry J. Smith Subject: Re: confidentiality of AID Application for SMU development No problem, Dave. I should have removed the confidential footers in the original submission. I think about 99% of the stuff in there is not sensitive. Maybe a net pay map and structure map, which are interpretive. Most everything else is out in the public, already. I will make new copies and drop those and a data disk off on Wednesday. LIV Sent from my iPad On Apr 30, 2019, at 3:48 PM, Roby, David S (DOA) <dave.robv@alaska.eov> wrote: Larry, Here's our regulations on confidentiality of information: 20 AAC 25.537. Public and confidential information (a) The commission will routinely make available to the public, by means of records or reports, in its offices or elsewhere, or by means of regular publication, the following information: (1) surface and proposed bottom -hole locations of each well after approval of the Permit to Drill (Form 10-401); (2) total depth, bottom -hole location and well status after the Well Completion or Recompletion Report and Log (Form 10-407) is filed; (3) all reports and information required by this chapter for development and service wells; (4) regular production data and regular production reports, as required to be filed by the operator each month; (5) injection data and injection reports, as required to be filed by the operator each month; and (6) all data filed on a well as required by this chapter upon expiration of the confidential period described in (d) of this section. (b) Engineering, geologic, geophysical, and other commercial information not required by this chapter, but voluntarily filed with the commission will be kept confidential if the person filing the information so requests. This subsection does not apply to information submitted in a public hearing under 20 AAC 25.540. 1 (c) In this section, "well status" means the classification of a well as oil, gas, service, suspended, shut-in, or abandoned. (d) Except as provided by (a) of this section, the reports and information required by this chapter to be filed by the operator for exploratory and stratigraphic test wells will be kept confidential by the commission for 24 months following the 30 -day filing period after well completion, suspension, or abandonment unless the operator gives written and unrestricted permission to release all of the reports and information at an earlier date. Upon notification that the commissioner of the Department of Natural Resources has made a finding that the required reports and information from a well contain significant Information relating to the valuation of unleased land in the same vicinity, the commission will hold the reports and information confidential beyond the 24 -month period and until notified by the commissioner of the Department of Natural Resources to release the reports and information. (e) Notwithstanding (b) or (d) of this section, any information obtained or used by the commission in the administration of its program under 42 U.S.C. 30011-4 (Safe Drinking Water Act of 1974, as amended, 42 U.S.C. 300f - 300j) (1) will be made available to the public unless the material has been claimed confidential and has been determined by the commission to be entitled to confidential treatment; claims of confidentiality will be denied for the following: (A) the name and address of any applicant for underground injection of Fluids, and (B) information that deals with the existence, absence, or level of contaminants in freshwater; (2) will be made available to the United States Environmental Protection Agency upon request; if the information has been submitted to the commission under claim of confidentiality, the commission will submit that claim to the United States Environmental Protection Agency when providing the information. Part (e) is the most pertinent part here since it deals with implementation of the UIC program, which we do on behalf of the EPA, and it basically requires everything to be public unless you can demonstrate why something should be held confidential. Generally speaking, we'll usually hold stuff that is interpretive (like a seismic cross section, net pay map, interpreted log section, etc) confidential. That said if you have something that's interpretive and would be entitled to confidentiality if you could provide a non -confidential version of that (for example a structure map the omits faulting and doesn't label the contour depths) that would be appreciated, but is not mandatory. Regards, Dave Roby 907-793-1232 CONFIDENTIALITYNOTICE This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Dave Roby at 907-793-1232 or dave.robv@alaska.zov. FA From: Larry Vendl <Ivendl@brpcak.com> Sent: Tuesday, April 30, 2019 3:17 PM To: Roby, David S (DOA) <dave.roby@alaska.gov> Cc: Colombie, Jody J (DOA) <jody.colombie@alaska.gov>; Larry J. Smith <Ismith@brpcak.com> Subject: RE: confidentiality of AIO Application for SMU development I can do that, Dave. I think somehow the application text portion got labeled confidential. I think only portions of the attachment section should have the confidential stamps. Will you need to circulate for public review any of the supporting attachments, like a base maps, logs or tables? We can easily remove the confidential stamp from anything you deem needs to make public. Regards, NITA From: Roby, David S (DOA) <dave.roby @alaska.gov> Sent: Tuesday, April 30, 2019 3:00 PM To: Larry Vendl <]vendl@brpcak.com> Cc: Colombie, Jody 1 (DOA) <iody.colombie@alaska.gov> Subject: confidentiality of AIO Application for SMU development Hi Larry, The application you submitted for an AIO for the SMU development has every single page marked as confidential. We need as much information as possible in the public domain and there's a lot of information in the application that isn't entitled to be held as confidential under our statutes and regulations. We need you to resubmit the application with only the stuff that truly is confidential marked as confidential and the remainder of the application available for public release. We've already scheduled the hearing and provided public notice for the application, so as long as you get the revised application to us in a reasonable amount of time the process won't get slowed up. Thank you, David Roby Senior Reservoir Engineer Alaska Oil and Gas Conservation Commission 907-793-1232 CONFIDENTMITYNOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Dave Roby at 907-793-1232 or dave.robv@alaska.eov. Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Re: Docket Number: AIO-19-016 Southern Miluveach Unit, Kuparuk River Oil Pool The application of Brooks Range Petroleum Corporation (BRPC) for an Area Injection Order (AIO) to allow enhanced oil recovery injection operations on their portion of the Kuparuk River Oil Pool (KROP). BRPC, by letter dated April 25, 2019, requests the Alaska Oil and Gas Conservation Commission (AOGCC) issue an AIO to authorize injection for enhanced oil recovery purposes on the portion of the KROP, as defined by Conservation Order No. 432D, that they operate. The AOGCC has scheduled a public hearing on this application for June 4, 2019, at 10:00 a.m. at 333 West 7' Avenue, Anchorage, Alaska 99501. In addition, written comments regarding this application may be submitted to the AOGCC, at 333 West 7`" Avenue, Anchorage, Alaska 99501. Comments must be received no later than the conclusion of the June 4, 2019, 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 June 1, 2019. J ssie L. Chmielowski Commissioner Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Re: Docket Number: AIO-19-016 Southern Miluveach Unit, Kuparuk River Oil Pool The application of Brooks Range Petroleum Corporation (BRPC) for an Area Injection Order (AIO) to allow enhanced oil recovery injection operations on their portion of the Kuparuk River Oil Pool (KROP). BRPC, by letter dated April 25, 2019, requests the Alaska Oil and Gas Conservation Commission (AOGCC) issue an AIO to authorize injection for enhanced oil recovery purposes on the portion of the KROP, as defined by Conservation Order No. 432D, that they operate. The AOGCC has scheduled a public hearing on this application for June 4, 2019, at 10:00 a.m. at 333 West 7th Avenue, Anchorage, Alaska 99501. In addition, written comments regarding this application may be submitted to the AOGCC, at 333 West 7th Avenue, Anchorage, Alaska 99501. Comments must be received no later than the conclusion of the June 4, 2019, 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 June 1, 2019. //signature on file// Jessie L. Chmielowski Commissioner STATE OF ALASKA ADVERTISING ORDER NOTICE TO PUBLISHER SUBMR INVOICE SHOWMG ADVERTISING ORDER NO., CERTIFIED AFFIDAVIT OF PUBLICATION WITH ATTACHED COPY OF ADVERTISMENT. ADVERTISING ORDER NUMBER AO-19-02L FROM: AGENCY CONTACT: Jody Colombie/Samantba Carlisle Alaska Oil and Gas Conservation Commission DATE OF A.O.AGENCY PHONE: 333 West 7th Avenue 4/30/2019 (907) 279-1433 Anchors e, Alaska 99501 DATES ADVERTISEMENT REQUIRED: COMPANY CONTACT NAME: PHONE NUMBER: ASAP FAX NUMBER: 907 276-7542 TO PUBLISHER: Anchorage Daily News, LLC SPECIAL INSTRUCTIONS: PO Box 140147 Anchorage, Alaska 99514-0174 TYPE OF ADVERTISEMENT: i✓ LEGAL F- DISPLAY 9— CLASSIFIED OTHER (Specify below) DESCRIPTION PRICE AIO-19-016 Initials of who prepared AO: Alaska Non -Taxable 92-600185 ................................ soeMrclrrlNVOICHsxoW�c:anveans xG :':tfR66R;N6:sCER'PIFI}9i A7FFTDAVIT.,O,F:: :PUBLICATION WITHATTACHEDCO" OF aayERTISMENTTti:::_;: AOGCC 333 West 7th Avenue Anchorage, Alaska 99501 Pae 1 of 1 Total of All Pa es $ REF T e Number Amount Date Comments 1 PVN VCO21795 2 AO AO-19-021 3 4 IN AMOUNT SY Act. Template I PGM LGR Object FY DIST LIQ I 19 A14100 3046 19 } 4 5 PurchasingAutharity Na mei r Title: Purchasing Authority's Signature Telephone Number I A. N and receiving agency name must appear on all invoices and documents relating to this purchase. 2. The state Is registered for tax free transactions under Chapter 32, IRS code. Registration number 92-73-0006 K. Items are for the exclusive use of the state and not for resale. DISTRIBUUTION:. plvlslQaF7seaJ/Ongivai:40 poples ;Pa1ilisher(faxeil) INVARO fijmilkReceiving Form: 02-901 Revised: 4/30/2019 Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Penny Vadla 399 W. Riverview Ave. Soldotna, AK 99669-7714 George Vaught, Jr. Darwin Waldsmith Richard Wagner P.O. Box 13557 P.O. Box 39309 P.O. Box 60868 Denver, CO 80201-3557 Ninilchik, AK 99639 Fairbanks, AK 99706 ANCHORAGE DAILY NEWSRECEIVED AFFIDAVIT OF PUBLICATION MAY 0 6 2019 AOGCC Account #: 270227 ST OF AKIAK OILAND GAS Order# CONSERVATION COMMISSION Cost 333 WEST 7TH AVE STE 100 nninunonnp ev ooarw�szo STATE OF ALASKA THIRD JUDICIAL DISTRICT Joleesa Stepetin being first duly sworn on oath deposes and says that he/she is a representative of the Anchorage Daily News, a daily newspaper. That said newspaper has been approved by the Third Judicial Court, Anchorage, Alaska, and it now and has been published in the English language continually as a daily newspaper in Anchorage, Alaska, and it is now and during all said time was printed in an office maintained at the aforesaid place of publication of said newspaper. That the annexed is a copy of an advertisement as it was published in regular issues (and not in supplemental form) of said newspaper on May 01, 2019 and that such newspaper was regularly distributed to its subscribers during all of said period. That the full amount of the fee charged for the foregoing publication is not in excess of the rate charged private individuals. Signed J e sa Steoetin Subscribed and swom to before me this 1st d y of may, 2019 Notaryblit in and for The State of Alaska. 0001437635 Product ADN -Anchorage Daily News $18428 Placement 0300 Position 0301 S Notice Of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Re: Docket Number: AIO-19-016 Southern Miluveach Unit, Kuparuk River Oil Pool The application of Brooks Ran Petroleum Corporation (BRPC) for an Area Injection Order (At to allow enhanced oil recovery injection operations on their portion of the Kuparuk River Oil Pool WROP). BRPC, by letter dated April 25, 2019, requests the Alaska Oil and Gas Conservation Commission (AOGCC) Issue an AID to authorize injection for enhanced oil recovery purposes on the portion of the KROP, as defined by Conservation Order No. 4321), that they operate, The AOGCC has scheduled a public hearing on this application for June 4, 2019, at 10:00 a.m. at 333 West 7th Avenue, Anchorage, Alaska 99501. In addition, written comments regarding this application may be submitted to the AOGCC, at 333 West 7th Avenue, Anchors a, Alaska 99501. Comments must be received no later than the conclusion of the June 4, 2019, hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact the AOGCC's Special Assistant, Jody Colombia, at (907) 793-1221, no later than June 1, 2019. //signature on file// Jessie L. Chmielowski Commissioner - Published: May 1, 2019 Third Division Anchorage, Alaska ANGELA M SIMMONS NOTARY PUBLIC State of Alaska MY COMMISSION EXPIRES My Commission Explms Apr. 14, 2021 Lawrence J. Vendl Manager, Exploration and Subsurface Projects Brooks Range Petroleum Corporation 510 L Street, Suite 601 Anchorage, AK, 99501 Phone 907.865.5811 April 25th, 2019 Jessie Chmiewlowski, Chair Alaska Oil and Gas Conservation Commission 333 W. 7th Ave #100 Anchorage, Alaska, 99501-3539 RE: Application for Area Injection Order for the Kuparuk Oil Pool Southern Miluveach Unit, North Slope, Alaska Dear Commissioner Chmiewlowski: Ilk 0 1 2019 AOCCC In accordance with 20 ACC 25.402 (Enhanced Recovery Operations) and 20 AAC 25.460 (Area Injection Orders), Brooks Range Petroleum Corp. ("BRPC") as operator of the Southern Miluveach Unit ("SMU") and on behalf of the Working Interest Owners, requests that the Alaska Oil and Gas Conservation Commission ("Commission") approve BRPC's application for an Area Injection Order ("AIO") for the Kuparuk Oil Pool, as defined by the Commission and within the SMU as defined in the SMU Agreement by and between the Alaska Department of Natural Resources. First injection into the Kuparuk Oil Pool in the Southern Miluveach Unit is expected to occur as early as the 3rd quarter of 2019. BRPC 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 Lawrence Vendl (907-865-5811) if you have questions or require additional information. Regards, 4;17z1 ;ZWre'hcd J. VenOF Manager, BRPC Exploration and Subsurface Projects North Slope Operations and Development Cc: Bart Armfield, Brooks Range Petroleum Corporation BRPC Application for SMU Kuparuk Pool, Area Injection Order pg. 1 Brooks Range Petroleum Corporation Application for Area Injection Order in the Kuparuk Oil Pool Southern Miluveach Unit May, 2019 Section A- Introduction Section B- Plot of Project Area Section C- Operator & Surface Owners Section D- Affidavit Section E- Description of Proposed Operation Section F- Pool Description Section G- Formation Geology Section H- Logs of Injection Wells Section I- Mechanical Integrity of Injection Wells Section J- Injection Fluids Section K- Injection Pressures Section L- Fracture Information Section M- Formation Water Quality Section N- Aquifer Exemption Section O- Hydrocarbon Recovery Section P- Confinement in Offset Wells Section Q- Proposed Area Injection Order Rules 20 AAC 25.402(c)(1) 20 AAC 25.402(c)(2) 20 AAC 25.402(c)(3) 20 AAC 25.402(c)(4) 20 AAC 25.402(c)(5) 20 AAC 25.402(c)(6) 20 AAC 25.402(c)(7) 20 AAC 25.402(c)(8) 20 AAC 25.402(c)(9) 20 AAC 25.402(c)(10) 20 AAC 25.402(c)(11) 20 AAC 25.402(c)(12) 20 AAC 25.402(c)(13) 20 AAC 25.402(c)(14) 20 AAC 25.402(c)(15) 20 AAC 25.402(c)(16) BRPC Application for SMU Kuparuk Pool, Area Injection Order P9. 2 List of Figures/Exhibits B-1: Plot of the SMU Kuparuk Oil Pool Area and all Existing Wells D-1: Affidavit F-1: Outline of AIO and Pool Area highlighting leases outside of the SMU F-2: Defining Well, North Tarn 1A, highlighting Pool interval with respect to the upper and lower confining intervals G-1: West to East Schematic Stratigraphic Cross Section Across Area of Interest G-2: Kuparuk "C" Reservoir Isochore G-3: Kuparuk "A4" Reservoir Isochore G-4: Kuparuk "A3" Reservoir Isochore G-5: West to East Well Cross Section across the AIO Area G-6: Lower Cretaceous Unconformity (LCU)/Kuparuk "C Structure Grid 1-1: Generic Kuparuk Injector Well Design J-1: Kuparuk Seawater Treatment Plant Water Composition J-2: Kuparuk Gas Injectant Composition J-3: Kuparuk Pool Produced Water Composition K-1: Southern Miluveach Unit, Kuparuk Oil Pool Injection Pressure Summary L-1: Well log from 2S-13PB1 used in GOHFER fracture analysis L-2: Model of single point Injection into the Kuparuk "C" L-3: Injection pressure modeled at 3000 BOPD L-4: Fracture geometry, exhibiting containment within the Kuparuk formation at 3000 BOPD L-5: Injection pressure modeled at 6000 BOPD L-6: Water Injection Without Propped Fracture At 6,000 BPD M-1: SMU Kuparuk Pool Water Sample Analysis from North Tarn 1A Well Test M-2: SMU Kuparuk Pool Gas Sample Analysis from North Tarn 1A Well Test M-3: SMU Kuparuk Pool Crude Oil Sample Analysis from North Tarn 1A Well Test 0-1: Map of Proposed SMU Kuparuk Development Wells BRPC Application for SMU Kuparuk Pool, Area Injection Order pg. 3 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 pressure maintenance and enhanced recovery of hydrocarbons in the Southern Miluveach Unit, Kuparuk Oil Pool pursuant to 20 ACC 25.402. Brooks Range Petroleum Corporation ("BRPC"), in its capacity as Operator of the Southern Miluveach Unit (SMU), 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). BRPC is operating the SMU Kuparuk Reservoir under the Current Kuparuk Pool Rules that govern the development of the Kuparuk Pool. Introduction The Kuparuk Oil Pool within the SMU is a continuation of the deposit of Kuparuk "C" and Kuparuk "A" Sands adjacent to the southwest portion of the Kuparuk River Unit. It is comprised of sandstones, siltstones, and shale that lies between -5800 ft. true vertical depth sub -sea ("TVDSS") and -6400 ft. TVDSS within the SMU. Development of the Kuparuk Oil Pool in the SMU will be completed in discrete phases to mitigate risk and improve recovery. The reservoir targets will be accessed from the SMU "Mustang" drill site. Current plans are to initially develop the field with up to 11 horizontal producers and up to 10 horizontal injectors. Some of the producers may be hydraulically fractured to enhance production and ultimate recovery. BRPC Application for SMU Kuparuk Pool, Area Injection Order pg. 4 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 Southern Miluveach Unit, Kuparuk Oil Pool as of March, 2019. 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. BRPC Application for SMU Kuparuk Pool, Area Injection Order pg. 5 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. BRPC is the designated operator of the SMU, which included the Mustang drill site from which the Kuparuk development 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: James Beckham, Director 550 West Seventh Avenue, Suite 1100 Anchorage, AK 99501-355 Repsol 3800 Centerpoint Dr. Anchorage, Alaska, 99503 BRPC Application for SMU Kuparuk Pool, Area Injection Order Operators ConocoPhillips 700 G Street Anchorage, Alaska 99501 ME 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. BRPC Application for SMU Kuparuk Pool, Area Injection Order pg. 7 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 Kuparuk Oil Pool within the Southern Miluveach Unit will be developed from the existing SMU Mustang drillsite and produced through the SMU processing facilities. Current plans call for 10 horizontal producers and up to 11 horizontal injection wells. Depending on expected reservoir quality, some of the producers may be hydraulically fractured to stimulate production and enhance ultimate recovery. As needed, additional wells may be drilled to optimize reservoir performance Most of the development wells will trend North to South parallel to the direction of the major fault patterns that cut through the reservoir. The length of the horizontal sections of the wells are planned to range in length up to 6000' within the reservoir. Some of the wells will produce from both the Kuparuk "C" and the Kuparuk "A" reservoirs. In these wells it is expected that hydraulic fracture stimulation may be needed to enhance productivity and improve vertical injection sweep. The wells will be arranged end-to-end to form alternate rows of producers and injectors in a line -drive flood pattern. Initial studies, which include a computer-generated reservoir simulation study, suggest a nominal 1500' inter -well spacing will fit within and between the major faults which cut through the Kuparuk reservoir and will most likely cause some interference to a conformable waterflood. Based on well performance, some infill drilling may be needed to optimize reservoir performance and maximize recovery. To evaluate the performance of the Kuparuk Reservoir, a 3-D model, based on the available 3D seismic surveys, was constructed covering the entire development area to demonstrate reservoir performance using a waterflood for enhanced recovery. Additionally, waterflooding may 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 will most likely consist of either produced water or seawater injection. The seawater injection source water will come from the nearby CPAI operated Alpine seawater pipeline. Gas will be sourced from the SMU 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 may occur in the future on one or more injection patterns to enhance recovery from the reservoir. An economic evaluation of future IWAG and MWAG projects will determine the feasibility of utilizing these enhancement techniques within the SMU. BRPC Application for SMU Kuparuk Pool, Area Injection Order pg. 8 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 Southern Miluveach Unit, Kuparuk Oil Pool Area Injection Order is the entire Kuparuk Oil Pool, as proposed, which is within the following land: Location As shown on Figure F-1, the affected area proposed for the SMU Kuparuk Oil Pool Injection Order is the entire SMU Kuparuk Oil Pool including the following land are: Umiat Meridian T1 ON, R7E Sections 1, 2, 3, 4, 9, 10, 11, 12 all T11 N, R7E Sections 24, 25, 26, 34, 35, 36 all Pool Definition Injection of fluids for enhance recovery is proposed for the correlative interval shown in Figure F-2, the North Tarn 1A well, known as the Southern Miluveach Unit (SMU), Kuparuk Oil Pool. Within the requested areal extent, the SMU Kuparuk Pool is defined as the accumulation of hydrocarbons common to and correlating with the interval between the depth of -6006 ft. TVDss and -6090 ft. TVDss as defined in the North Tarn 1A Well. Within the proposed Area Injection Order, the primary Kuparuk reservoirs are the Kuparuk "C" and the Kuparuk "A" intervals. Lower Confininc Interval Below the Kuparuk Oil Pool is the Miluveach Shale, The Miluveach is a thick regional shale deposit in the proposed area of development. The Kuparuk Pool in the area of the SMU The primary reservoirs in the proposed Area Injection Order consist of the shallow marine sandstones of the Kuparuk "A" reservoir and the unconformably overlying transgressive sandstones of the Kuparuk "C" reservoir. The underlying "A" is generally less permeable reservoir than found in the more permeable Kuparuk "C" reservoir. Upper Confininc Interval The Kuparuk "C" reservoir is overlain by the Kalubik Shale interval. The Kalubik Shale is a regionally extensive and thick shale unit which provides acts a top seal for the reservoir and provides the upper confining layer to waterflood. BRPC Application for SMU Kuparuk Pool, Area Injection Order Section G- Formation Geology 20 AAC 25.402(c)(6) 20 AAC 26.402(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 Stratiaraphv Figure G1 shows the depositional model for Kuparuk Formation, which consists of the underlying Kuparuk "A" shallow marine sands which are thought to be truncated in the Western portion of the SMU. The Kuparuk "A" sand is overlain by the Kuparuk "C" which is a transgressive sand deposited on the regional Lower Cretaceous Unconformity. The Kuparuk "C" and underlying Kuparuk "A" members of the Cretaceous age Kuparuk formation consist of very fine to coarse grained sandstones and siltstones. Within the proposed development area, the combined thickness of the two members ranges from 0 to over 80 feet. Figure G2 shows the expected isochore of the Kuparuk "C", which is the primary reservoir in the area ranging from 0 to as much as 35 feet thick. Thickness is estimated from well data and seismic signature. Figure G-3 shows the expected isochore of the Kuparuk "A" reservoir, ranging from 0 to as much as 80 feet thick. The Kuparuk A" reservoir thins to the west as it is truncated by the Lower Cretaceous Unconformity. Sedimentolo The Kuparuk "C" sandstones are fine to coarse-grained, composed of quartz and up to 40% structural glauconite, and are commonly cemented with secondary siderite (the ubiquitous precipitate in North Slope reservoir sandstones). Porosity averages 22% and permeabilities range from 50 to hundreds of mD in the Kuparuk "C" averaging 70 mD in the Mustang area. The Kuparuk "A" sandstone are very fine to fined grained sandstone interbedded with siltstone and mudstones. Porosity averages 22%, but the permeability is lower than the Kuparuk "C" member ranging from less than 10 mD to 100mD, averaging 30 mD. Structure and Trap The Kuparuk Pool within the SMU ranges in depth from -5800 to -6400' TVDSS. Oil is trapped within the regional structural trap formed by the Colville Anticline. There is no oil -water contact in the proposed Area Injection Order. The Kuparuk reservoirs in the SMU are well above the known oil -water contact of the Kuparuk Oil Pool, which Range in depth from 6530' TVDss to 6650' TVDss in the KRU and are deeper than this to the Northeast in the Milne Point Unit. Definina Net Pa Net pay is general defined by Gamma Ray, Resistivity and Porosity logs. Water saturation in the Kuparuk "C" can be as low as 20%, while water saturations in the Kuparuk "A" are as high as 40%. Net Pay cutoffs of about 15% porosity and 35% water saturation are assumed for purposes of volumetric calculations and are consistent with petrophysical evaluations which suggest these cutoffs are good indicators of net pay in the Kuparuk "C" sand. BRPC Application for SMU Kuparuk Pool, Area Injection Order pg. 10 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 file with the commission. To date, two wells within the SMU have been drilled and are intended to be utilized for injection. The well logs and well histories for these wells, North Tarn #1 A and SMU M-02, have been submitted and are on file with the AOGCC. BRPC Application for SMU Kuparuk Pool, Area Injection Order pg. 11 Section I - Logs of Injection Wells 20 AAC 25.402(c)(8) 20 AAC 25.402(c)(B) -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 (8) the proposed casing program, if the injection wells are new. The well design for the SMU Kuparuk Oil Pool well (Figural -1) are like the other Kuparuk Oil Pools drilled within the adjacent Kuparuk River Unit 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 approximately 1250' TVDss. Intermediate casing strings will be set and cemented to isolate problematic shales zones and to optimize drilling through these zones. Any significant hydrocarbon bearing zones found in the borehole above the Kuparuk 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 SMU Kuparuk Oil Pool will likely be developed in one of two methods. The first type will be comprised of solid liners including pre -perforated pup joints and/or sliding sleeves. This completion will be utilized where hydraulic fracturing is needed to enhance productions. The other type of completion will utilize uncemented slotted liners where fracture stimulation is not needed. Tubing sizes will be determined to optimize expected production and injection rates. In lieu of the packer depth requirement under 20 AAC 25.412(b) specifying packer depth within 200ft measured depth from above the top of the perforations, BRPC request 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 shale have outer casing cement volume sufficient to place cement a minimum of 300' measured depth above the planned packer depth. Since the Kuparuk Oil Pool injectors are planned as horizontal wells, stimulation optimization efforts and well work feasibility may be impeded if the packer/isolation 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 operation will be performed in accordance with 20 ACC 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 SMU Kuparuk 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 BRPC Application for SMU Kuparuk Pool, Area Injection Order pg. 12 Section J - Logs of Injection Wells 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 SMU Kuparuk Oil Pool with the use of both produced water and treated seawater. Seawater will be delivered through a pipeline spur off the nearby Alpine water pipeline. 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 SMU Kuparuk 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 SMU Kuparuk River Field, including without limitation the Kuparuk Oil Pool. • 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 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 SMU Kuparuk Oil Pool. Analyses of formation water samples collected from the Kuparuk producers within the KRU indicate the potential for moderate scaling during production and when the formation water mixes with seawater. The specific scale risks are listed below. • Produced Water Injection o BaSO4 and CaCO3 o Scale risks are minimized as the injection water going deeper into formation • 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 reservoirs (The Kuparuk River Field, Kuparuk Pool and Nanuq/Kuparuk in the Colville River Field) suggest limited permeability degradation will occur with properly treated injection fluids. BRPC Application for SMU Kuparuk Pool, Area Injection Order pg. 13 No compatibility issues between injection gas and Kuparuk 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. BRPC Application for SMU Kuparuk Pool, Area Injection Order pg. 14 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. BRPC proposes to develop the SMU Kuparuk Oil Pool using a waterflood and ]WAG 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 nearby core data, is 0.72 psi/ft. To ensure containment of injected fluids within the SMU Kuparuk Oil Pool, injection pressures will be managed as to not exceed the maximum injection gradient of 0.67 psi/ft. 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. BRPC Application for SMU Kuparuk Pool, Area Injection Order pg. 15 Section L - Fracture Information 20 AAC 25.402(c)(11) 20 AAC 25.402(c)(11) -An application for injection must include evidence to support a commission finding of 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 through BRPC, indicates that the estimated maximum injection pressures for the Kuparuk 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 fracture model built based on the nearby KRU 2S-13pbl well log data and calibrated by using data from nearby geo-mechanical tests and pressure history matched data from the North Tarn #1 fracture stimulation 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 Kuparuk Oil Pool without risk of breaking through overburden or under -burden containment zones. The frac modelling software used was version was the Grid Oriented Hydraulic Fracture Extension Replicator (GOHFER), due to its reliability and common use by North Slope operators 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. Modeling the growth of hydraulic fractures induced by water injection into the Kuparuk C zone was conducted using the three-dimensional numerical simulator. Results suggest that hydraulic fractures can be created and extended within the Kuparuk A and C formations if water injection is conducted at surface pressures above 1700-2000 psi. This modeling also indicated that created fractures would be contained within the Kuparuk interval unless the surface injection pressure rises to more than 2700-3000 psi. Based on the computed and calibrated stress profile, and the model results presented here, it is possible to initiate and propagate fractures with water injection in the Kuparuk formation at surface pressures up to 2000 psi, with all created fractures contained within the sands by the in-situ stress contrast between the sands and bounding silt/shale layers. An increase in fracture treating pressure of more than 1000 psi above the stable fracture extension pressure indicated by the model is required before excessive fracture height growth develops. The calibrated stress and fracture model predict height containment within each reservoir interval. It is not able to accurately predict the lateral extent of the created fractures. Rate of fracture extension (laterally) depends primarily on the balance between injection rate and leakoff rate to the surrounding formation. This can be affected by spatial changes in pore pressure and reservoir quality, and by progressive plugging or damage to the formation sand -face caused by injected suspended solids and contaminants. To study how fractures are initiated during injection in the Kuparuk Reservoir and whether they can be effectively contained within the target interval, the following cases were simulated for a horizontal well penetrating and injecting into a single point within the Kuparuk "C'. Single point injection models the worst-case scenario for the induced pressure on the confining layers. In practice, injecting along the length of the lateral will result in less fracture height growth at each point. Injection at a single point would lead to the most fracture growth in the zone. Increasing the number of injection points in the well will decrease the possibility of fracturing out of zone. 1) Water Injection without propped fracture at 3,000 bpd (Figure L-1,2,3,4,) 2) Water Injection without propped fracture at 6,000 bpd (Figure L-5,6) The above simulations indicate that injection induced fractures will be contained within the Kuparuk Reservoir; no breakthrough of the overburden or under -burden containment zones will occur. BRPC Application for SMU Kuparuk Pool, Area Injection Order pg. 16 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 Kuparuk Reservoir water sample collected from the North Tarn #1 A well test is above the 10,000 mg/I cut off for freshwater. Based on the calculation of the weight percent of the chloride ions (chlorine molecules in the analysis) and sodium ions in the analysis from Kuparuk Lab, the total weight percent would be 1.66 weight percent which translates to 16,600 parts per million. This is consistent with the 15,000 to 20,000 ppm readings that are measured from the Kuparuk Reservoir. In fresh water - official salt concentration limits in drinking water US: 1000 ppm. Salinity of the Kuparuk Reservoir water in nearby Kuparuk River Unit producers found a salinity range from approximately 16,000 to 20,000 mg/I NaCl. Based on this information, the Kuparuk Reservoir is not a source of drinking water. Composition of the North Tarn #1A water, gas and crude oil composition is listed in Figures M-1, 2 and 3. BRPC Application for SMU Kuparuk Pool, Area Injection Order pg. 17 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. Minimum values of formation water salinity in the Southern Miluveach Unit Area, west of the Kuparuk River Unit and continuing into the NPRA through the Colville River Unit determined using standard open hole wellbore geophysical methods which have been calibrated from drill stem and production testing, range from over 3,000 to 18,000 milligrams per liter ("mg/I") total dissolved solids ("TDS"). This evaluation was conducted by qualified petrophysicists contracted from Schlumberger Oil Field Services by Brooks Range Petroleum. Permafrost extends from the surface to approximately 1300' TVDss in the SMU, although partially frozen zones locally exist to a depth of 1800' TVDss. As such, no fresh water aquifers exist within the planned development from the surface to this depth. Any potential aquifer sands that could be located below this interval would be considered uneconomic sources of drinking water in this area. No significant permeable zones have been identified in any nearby wells that penetrate the stratigraphy below permafrost and above the first potential hydrocarbon bearing reservoir intervals. The firstotA ential hydrocarbon zone in the SMU could be found at a depth of about 4000' TVDss, which is stratigraphicaliy equivalent to the shallowest producing horizon in the nearby Tarn oil pool. This zone, stratigraphically equivalent to the Tarn Pool has not yet been proven to be a productive oil pool within the SMU. A petrophysical evaluation of the zone from the base of permafrost to 4000' TVDss was conducted on the nearby West Sak 25590 15 well which has a complete logging suite suitable for estimating the Total Dissolved Solids content (TDS) and salinity. From this analysis, the TDS/Salinity content of the fluids in these sands is calculated to be more than 3000 ppm. Hence, by definition, there are no drinking water aquifers identified in the vicinity by this analysis. 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 field." 40 CFR147.102(b)(3). The Commission has adopted that exemption by reference 20 AAC 25.440(c). All of the proposed SMU Kuparuk Oil Pool and the area to which the proposed AIO applies is within the ORIGINAL Kuparuk River Unit as approved in 1984 when the Environmental Protection Agency adopted the original aquifer exemption, and in 1986, when the Commission incorporated the KRU aquifer exemption. As such, the original aquifer exemption still applies to the proposed SMU AIO. An aquifer exception should be granted for the SMU based on these factors and analysis. No fresh water aquifers are found within the development area of the SMU. BRPC Application for SMU Kuparuk Pool, Area Injection Order pg. 18 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 SMU Kuparuk Oil Pool. This waterflood technique has been widely used on North Slope with consistent success. The SMU Kuparuk 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. Some wells will likely be hydraulically fracture stimulated to enhance productivity and improve vertical injection sweep. Most wells will trend north to south, sub parallel the maximum principal stress direction to improve waterflood performance, and range in length up to 6,000 feet within the reservoir (Figure 0-1). Wells will be arranged end-to-end to form alternating rows of producers and injectors in a line -drive flood pattern. After taking into account structural constraints, a nominal 1,500 ft. inter -well spacing delivers adequate secondary response. Initial wells will provide critical performance and injection data for the SMU Kuparuk 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 remaining SMU Kuparuk Pool development. The primary uncertainties in the development of the SMU Kuparuk Oil Pool are the lateral continuity of relatively thin sandstone bed and the effective displaceable pore volumes. The seismic signature of the SMU Kuparuk Pool reservoir is consistent with and supports laterally continuous productive sandstones over development with some compartmentalization possible, but hydraulic fracture stimulation will aid connecting the more poorly developed sandstone beds. Reservoir modeling estimates that primary recovery will recover approximately 10 to15% of the original oil -in- place ("OOIP") and that waterflood recovery will range from 10% to 25% incremental recovery OOIP, yielding a total recovery after waterflood of up to 35%. Gas injection whether miscible or immiscible, would be expected to yield significant incremental recovery in the SMU Kuparuk Oil Pool. Historical IWAG incremental recovery has been in the range between 1-5% of OOIP, while MWAG incremental recovery has been demonstrated to range from 3-15% of OOIP. 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 Kuparuk 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. Resource recovery for floods is heavily dependent on injection throughput, waterflood recovery efficiency, and gas injection recovery efficiency. BRPC Application for SMU Kuparuk Pool, Area Injection Order pg. 19 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. At the time of this report, no wells have been drilled within a one-quarter mile radius of each other within the SMl1. However, the development will contain additional wells within this offset distance. 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. BRPC Application for SMU Kuparuk Pool, Area Injection Order pg. 20 Section Q - Proposed Area Injection Order Rules 20 AAC 25.402(c)(16) The rules set forth apply to the following area referred to in this order: Umiat Meridian T1 ON, R7E Sections 1,2,3,4,9,10,11,12 all T11 N, R7E Sections 24,25,34,35,36 all 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 SMU Kuparuk Oil Pool, which is defined as the accumulation of oil and gas common to and correlating with the interval within the North Tarn #1 well between the depths of -6006 ft. TVDSS and -6096 TVDSS respectively). Rule 2. Well Construction In lieu of the packer depth requirement under 20 AAC 25.412(b), the packerfisolation 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 SMU Kuparuk River Pool, including without limitation the Kuparuk 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 (by 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 SMU Kuparuk 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. BRPC Application for SMU Kuparuk Pool, Area Injection Order pg. 21 List of Figures/Exh!bits B-1: Plot of the SMU Kuparuk Oil Pool Area and all Existing Wells D-1: Affidavit F-1: Outline of AIO and Pool Area highlighting leases outside of the SMU F-2: Defining Well, North Tarn 1A, highlighting Pool interval with respect to the upper and lower confining intervals G-1: West to East Schematic Stratigraphic Cross Section Across Area of Interest G-2: Kuparuk "C Reservoir Isochore G-3: Kuparuk "A4" Reservoir Isochore G-4: Kuparuk "A3" Reservoir Isochore G-5: West to East Well Cross Section across the AIO Area G-6: Lower Cretaceous Unconformity (LCU)/Kuparuk "C Structure Grid I-1: Generic Kuparuk Injector Well Design J-1: Kuparuk Seawater Treatment Plant Water Composition J-2: Kuparuk Gas Injectant Composition J-3: Kuparuk Pool Produced Water Composition K-1: Southern Miluveach Unit, Kuparuk Oil Pool Injection Pressure Summary L-1: Well log from 2S-13PB1 used in GOHFER fracture analysis L-2: Model of single point Injection into the Kuparuk "C L-3: Injection pressure modeled at 3000 BOPD L-4: Fracture geometry, exhibiting containment within the Kuparuk formation at 3000 BOPD L-5: Injection pressure modeled at 6000 BOPD L-6: Water Injection Without Propped Fracture At 6,000 BPD M-1: SMU Kuparuk Pool Water Sample Analysis from North Tarn 1A Well Test M-2: SMU Kuparuk Pool Gas Sample Analysis from North Tarn 1A Well Test M-3: SMU Kuparuk Pool Crude Oil Sample Analysis from North Tarn 1A Well Test 0-1: Map of Proposed SMU Kuparuk Development Wells BRPC Application for Area Injection Order pg. 22 B-1: Plot of the SMU Kuparuk Oil Pool Area and all Existing Wells 17 16 15 14 21 22 23 1 24 1 19 Scale = 1:48000 17 0 3000 6000 9000 ft 14 1 BRPC Application for Area Injection Order pg. 23 2M-36 29 28 27 26 25 30 2M-37 32 33 34 35 36 2M-3831 .N1 -D2 2M-31 ---- 2 5 4 3 2 --M-03 1 6 Mustang -1 2M-33 NT -1A ' 2S-14 2M-34-._ 2S -13A 2S-13AL1 e 9 10 11 12 ' 7 zL-D3 zs-11 Scale = 1:48000 17 0 3000 6000 9000 ft 14 1 BRPC Application for Area Injection Order pg. 23 Exhibit D-1: Affidavit State of Alaska Third Judicial District I, Harry Bockmeulen, declare and affirm as follows: 1. 1 am the Chief Operating Officer of Brooks Range Petroleum, the designated operator of the Southern Miluveach Unit (SMU), and as such have responsibility for Unit operations. 2. On April 26, 2019 1 caused copies of the SMU Kuparuk Pool 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: State of Alaska Department of Natural Resources 550 West 7m Avenue, Suite 1100 Anchorage, AK 99501 ADL 391540 ADL 391552 ADL 391551 ADL 393564 ADL 391548 Operators: ConocoPhillips 700 G Street Anchorage, Alaska, 99501 Repsol 3800 Centerpoint Dr. Anchorage, AK, 99503 Dated April 26, 2019 Harry BockMeulen Declared and affirmed before me this April 26, 2018. Notary Public in and for Alaska My commission expires: BRPC Application for Area Injection Order pg. 24 F-2: Defining Well, North Tarn 1A, highlighting Pool interval with respect to the upper and lower confining intervals Kalubik Shale Upper Confining I ■ Miluveach Shale Lower Confining Layer BRPC Application for Area Injection Order pg. 25 G-1: West to East Schematic Stratigraphic Cross Section Across Area of Interest Nanuk-Ituparuk Colville#1 Kuparuk Fiaid Alpine Field Wartern—Mustang Field) (Sandyt'ytsjApybsprst) Wast 3W _ East _. .., . - z... I Kalubik Shale I LCU Kuparuk"C'Sand LCV Sand Miluveach Shale 'JurassIe Sands Jurassic Shale Bm.c.ri Brc.i, an HR2 R2 u, lublk Ka Wbik Kup "C' Milc,iii Jumsst Jurassic Regional Depositional Framework Milureach - Flattened on the'CU sci croakkan Brook:an Bruck iar. HR2 HR2 HR2 K.Iubik Kaluba Kalubik Kup'C Kup"C KupT' Milureach Kup'A' sci Jurassic Thin Milmai MIIWeach Jurassic Jurassic BRPC Application for Area Injection Order pg. 26 PAGES 27-29 HELD CONFIDENTIAL G-5: Cross Section, Flattened on the LCU, across the AIO area (Outlined in red on map). Log Curves include gamma ray and deep resistivity in TVDss and measured depth 5BT[I! P � Oflv[ 2A 55 BE 11. 13Ti e w a+a BRPC Application for Area Injection Order pg. 30 PAGE 31 HELD CONFIDENTIAL 1-1: Generic SMU Kuparuk Pool Injector 4 String Casing Well Design (ar�is IQl4LS�M .. .. io K? £^ •.. .... .. . .... .... ... . •° .- 116/1'. ll1n'LMM Mow 44m, MO/1M!'rV0 i6}.bflli0ir no iJ "- � ---'- •._r__ _..--- -•'7 we" so . }uf?ta C+.rr w�ew weu st . . . . . . . . . .III VV VLWI-05 363 ' ' ' all "NAW6Ii •61.161' 0012.616' NO 3 S, •',fJ 3f L IL'.i l W 6R0 12d14 Intrrmedlatr . NOIc ' 4111 Il 6r L kir •0IY ' . +. . . . Ypi6.. . 1:0 . . . . dDago ..................... .. .... .... .... .... .... .... .... BRPC Application for Area Injection Order pg. 32 IOC P •110.5m MO . . �. 91!I J- iw K~ 4-11,w 6tl. . im"&ditt-1 Iwo* =AICY •r 12;013' molsm66'rti0 1 -YM IM". Il Y✓YP/T-OM ,V�.' '- _- -, .. ]-.L ).-WIn{IntM1MIVU9 Ipm,uerATea is J"7Y, W,Mydf RL2l6tCM .•i .war ' 4111 Il 6r L kir •0IY ' . +. . . . Ypi6.. . 1:0 . . . . dDago ..................... .. .... .... .... .... .... .... .... BRPC Application for Area Injection Order pg. 32 J-1: Kuparuk Seawater Treatment Plant Water Composition Sample Kiumber: S-16026300063 Sample Mame: STP S ea"er Plant Discharge totatlon: Area: KUPARUK Unit STP Sample Pain STPSPD Sampled Date: ZW2016 350:00PM hUtrbt ld: WATER - SEA Reviewed 6q: CarvilleYDaniele Date02/24/2016 Aralwla ReS&S Tse p1amate Boa Mail MCIVIn. -A YP AMME 31657 RW DID NBC ICACETATE ACETATE X5.0 Nrgl O10 NEM IC • BUTYRATE BUTYRATE <5.0 Inel 010 NIX IC CHLORIDE CHLORIDE 384978 me) NEM IC • FORMATE :0 FORMATE <iD mWl OG NO( IC PROPIONATa PROPIDNATE <5.0 Mel DID NIX IC' SULFATE SO4iSULFATE{ 2500.0 AWi ICP METALS • AL (ALUM NUM) AL(AWMINUM) 0.00 mWl ICP METALS' IS (BORON) IS(SO RO N) 4,65 Mel ICP METHS' BA(BARIUM) RA(EARIUM) 0.15 mrfl ICP METALS • CA (CALCIUM) CA (CALCIUM) 428 59 ME/I ICP METALS • CII (CHROMUM) en (CHROMIUM) 0 at m{/I ICP METALS • FE QNOHI FE(IRON) 0.07 ffWI ICP METALS' 9(POTASSIUM) K (POTASSIUM) 392,42 fflel ITS METALS • U ILITXIUM) U(LITHIUM) 0.72 MWI IOF METALS • MO (MAGNESUMI MG(MAGNESIUM) 2130.38 Met ICP METALS • MN (MA iGANESEi MN(MANGANME) 0.0P3 "W1 ICA METALS' NA IS ODIUM) NACSDOIUM) e973.70 riW1 IO METALS` P(PHOSPHORUS) P (PHOSPHORUS) 0.03 nwi ICP METW -III (SILICON) III$ILICCNI 1.43 rtIel ICP METALS • SR OTRO NTIUM) BRPC Application for Area Injection Order pg. 33 J-1: Kuparuk Seawater Treatment Plant Water Composition (Continued) Sample Nwiiber:S-1W2034D0063 Sample Name: STP Seawater Plant Discharge Location: Area: KUPARLac Unit STP Sampled Date: 2/V20116 35Q00PM Mtrbcld WATER -SEA R evirwed Ry. Camille, Daniels Date 02/24/2016 Ana s Ne7ults ] Marten SR 07RONTIUM) 1OF METALS' ZN IBM C1 ZN (ZN 4 S-2330 AIAALN ITT - T OTA L BICMBO NATE (HO S) CARBONATE(CO3) 5-2510' CONOUCTMTY CO NOUCI PATY 9-2570 SALINITY - SP G AAV SPBOHCGRAMT SAM PH (G)PH PH S -450V 52-M SUTAOE BY TTTR SULFIDE Sample Point STP SPD !118111 zu 6.29 n1WI 0.02 .Wl 191.0 mWi 0.0 :Wl SMOG us/O 10260 7.17 Is a5rl BRPC Application for Area Injection Order pg. 34 J-2: Kuparuk Gas Injectant Composition Sample Nunbev: S-16D2D30 M Sample Name: STP Semler Plant Discharge Location: Area KUPARUK Unit STP Sampled Date: ZIV2016 3S0.00PM Matdx ld: WATER - SEA RerlewedBir Carville,Danlete DateOVX/$716 Anahral3 ResSdts its HnMemr sR firrRDNTIUM) I CP METALS • ZN C9NCj ZN (ZWQ S-2320 ALKALOI OT • T OTAL eICMaO NATE (HOD 3) CARBONATE (CO 3) 8-2510 • CONDUCNVITY CONOUCPMTT 945205AUNm" SP O AAV SPEOFIt GPAVnN SAWO PH 03)' PH PH 5.950032• IF)' SUUzOE aT TRP SUUdOE Sample POI Tit STP SPD 111111111 QUM 6.2s rwl 0.02 mall 191.6 "/l 0.0 "/1 53800 us/vn 10290 712 3.0 mail BRPC Application for Area Injection Order pg. 35 J-3: Kuparuk Pool Produced Water Composition Sample Number: S-1ti320300058 Sample Namz CPF-3 Prod WaterTank Outlet L.oTdow Area KUPARLAC Unit CPF3 Sample PrxnC CPF3 PWL CUT SaflVied Date: 2/2/3016 219:00PM Matrix id: WATER - PRODUCED Reviewed RT. Dorothy Colegrove Date: 02/08/2016 Analasis Realty Talc I>4 ma %l 81119A SSS DO NIX IC' ACETATE ACETATE 104.7 mg/1 DONE7f IC• WnRATE BUTYRATE <s0 rnwl OO NR IC • CHLORIDE CHLORIDE 143399 refill OO NIX IC' FORMATE FORMATE 45,0 MlL/1 DONO1 IC' PROPIONATE PROPIONATE 143 nW1 DOMIX tL•SULFATE S 041SULFATE) 745.5 ITWI ICA METALS' AL(ALUMINUM) AL(AWMINUFA 0.06 wsh ICP METALS• B(BORON) 9 RQ RON) 1).4R m511 ICP METALS • BA (BARIUM) OA(BARIUM) 31.03 mg(1 ICA METALS' CA (CALCIUM) CA(CALPAUM) 12978 m5(1 iCP METALS' CR(CNROMUM) CR (CHROMrim) 0.01 m5/l ICP METALS' M (IRON) FE(IRON) 0.29 mQl ICP METALS' R (POTASSIUM) A(POTASSIUMR) 89.77 Mel ICP METALSU (LITHIL)" Ll (LITHIUM) 1.11 mg/l ICP METALS • MO (MADNESATM) MG(MTADNESIUM) 18771 mV1 IQF METALS • MN (M ANDANESE) MN(MANOANe E) 00N Mg/1 10 METALS • NA PODIUM] NA(SODIUM) 9079.32 MWI ICP METALS • F(PHOSPHORUS) P (PHOSPH0 AM) 0.60 mg(I IW METALS •$1(SIUCON) $I CSILICON) 16.69 Mel ICF MALS • $R $TRO NTIUVA SR PTRONTIUM) 8.19 m5N IQ METALS' III $INC) BRPC Application for Area Injection Order pg. 36 J-3: Kuparuk Pool Produced Water Composition (Continued) Sample Nunber.S.IGO203WC58 Sample Name CPF3 Prod Water Tan k Qrtlet Location: Area KUPARUK Unit CPF3 Sampled Date: ZtV2016 P.15:00PM Matdxlh WATER -PRODUCED Reidered8{ Dorothy CdEgrove Date02p8/2016 Analysis Results gg POMMsr ZNMNQ S-2329 ALKALIN MY' TOTAL Sit"PORATECHMI) CARBONATE 00031 5.2510' CONDUCrM7Y CO NOUCTIVITY S-2520SALNRY' SP ORAV SPEOFICORANTY S-4560 PH (8)' PH PH 0-4500 S2 -CF) -SULFIDE EY TITR SULFIDE Sample Pant: CPF3 PWT OUT lm'UR UM 0.00 mall 15512 mall 0.9 MWI 43600 US/= 12290 7.91 18.3 mW[ BRPC Application for Area Injection Order pg. 37 Figure K-1: SMU Kuparuk Oil Pool Injection Pressure Summary Datum (TVDss) Estimated Wellhead Estimated Bottom -hole Injection Type Pressure(PSIA) Pressure Overburden Pressure Gradient Average* Maximum** Average* Maximum** Water Injection 1400 1 2000 4000 4623 *Based on current operations at a true vertical depth of 6100 feet ** Maximums vary according to actual depth Datum (TVDss) 6100 Average Injection Gradient 0.62 Maximum Injection Gradient 0.67 Overburden Pressure Gradient 0.72 CPF-3 Fluid Gradient (Water) 0.442 Gas Gradient (MI) 0.15 Calculations: Bottom Hole Pressure (BHP)=Datum (TVDss)* Injection Gradient (Water or MI) Hydrostatic Pressure = Datum (TVDss) * Fluid Gradient Well Head Pressure (WH P)=BHP-Hydrostatic Pressure BRPC Application for Area Injection Order pg. 38 Figure L-1: Well log from 2S-1313131 used in GOHFER fracture analysis MECHANICAL MODEL - 2S-13PI31 • Best and closest analog for 3 injection wells was 2S- 13PB1 • Poisson's ratio derived from shear compressional ratio • Young's modulus derived from shear compressional ratio and density log • Conversion to static Young modulus using Eiza transform • Pore pressure set to normally pressured BRPC Application for Area Injection Order pg. 39 _,,.. �,., m �, .�A _"7 �� -e -- �- __ ��tl1 �+wMMWi� i—� i 1N� R� nom..:' T k ....._ �. Figure L-3: Injection pressure modeled at 3000 1 PHANTOM FF - INJECTION PRESSURE AT 3000 BPD Engine Remlu BRPC Application for Area Injection Order pg. 41 Figure L-4: Fracture geometry, exhibiting containment within the Kuparuk formation at 3000 BOPD 3000 BPD INJECTION RATE - FRACTURE GEOMETRY BRPC Application for Area Injection Order pg• 42 Figure L-5: Injection pressure modeled at 6000 BOPD PHANTOM FF - INJECTION PRESSURE AT 6000 BPD ewiM n«wft BRPC Application for Area Injection Order pg. 43 Figure L-6: Water Injection Without Propped Fracture At 6,000 BPD 6000 BPD - INJECTION RATE - FRACTURE GEOMETRY BRPC Application for Area Injection Order pg. 44 M-1: Oil/Water Sample Analysis, North Tarn 1 A Kunaruk, North Slope Renorl of Analysis Sample Number. 7912540 Sample Name: EXPLOR-X .Am.: Miscellaneous Unit; Miscellaneous Sample Point Resc: Expinraliml sample Sampled Dote: 112312012 7:001)OANI Additional Sample Details Location description 13ivuFs Runge Nodh'ram lA lot Samnle Determinate Name Anal"ls Details Result DObf (-4007 DS&WWI I Walercul% Watetcul 61.0 Vol% D4007 MAWSolids Sediment 5.0 Vol% Mcnk by XRF•XRF Al(Alummo,o) 0.09 WI% Metals by XRF-XRF Co(Calcium) 0.36 WI% MMI, b'XRI'-)RF C12(Chladm) 0.89 W1% Mdak by XRF•XRF CF(Chmmium) V.05 Wt% McAds by XKF•XRF Cu(Copper) a005 Wt% Metals by XRF•XRF F.Omo) 0.71 Wt% Mclals by XRF•XRF K (P.M. nm) 0.30 W1% % Metals by XRF•XRF Nit(Mugnexiun) 0.07 Wt% Metals by XRF-XRF Nin(Mansansx) 19.05 WI% Nic ala by XRF•XRF M. Molybdcmunj 110.05 Wt% Meals by XRF-XKF No (Sodium) 0.77 W'1% MeldsM XRF•XRF Ni(M.W) 10.05 Wt% Metals by XRF•XRF P(Ph phtlm,) 0.05 WI% Nktak by XRF-XRF HE(Rmmine) 10.05 W1% Sktels by XRF•XRF S (Su1Nr) 4.83 W I % Metals by XRF•XRF S1 (Silicon) 4.01 WI% Manta by XKF•XRF T.(7itaniumj 10.05 Wt% Memla by XRF•XRF Zn (Zinc) 10.05 W't% Metal, by XRF•XRF Ra (Barium) 4026 Wt% Metals by XRF•XRF Sr(Sbmnium) 0.07 W1% Metals by XRF•XRF V(Vxmdium3 '01M W'1% Metals by XRF-XRF Ae(Silvcl 10.05 W'1% Metal, by XRF•XRF As (Aesunic) 0M W1% Metals by XRl'-XRF C. (Cobalt) 10.05 W9% Meals by XRF-XRF Pb(l.ead) 1.0.05 W1% Metak by XRF•XRF Se(Selcmum) 10.05 W1% BRPC Application for Area Injection Order pg. 45 M-2: Gas Sample Analysis, North Tarn 1 A (Continued) Kuparuk. North Slope Mort of Analvds Sample Number: 7909009 Sample ,Name, EXPLOR-X Area: Misoellxnmtus Unit: Miseellancous Sample Point Des9: Exploration sample Sampled Dale: 11:512012 7:00:00AM A9tllil9.oal5olunic P&MUL, location doeriptlon BRwks Range North Tam l A Gas pIMwT�3R},7^7 BRPC Application for Area Injection Order pg. 46 Sample Analysis Details iml Determinale Name Ressaft l!061 D-1945-NarOm N2(NhMn) 0.926 Mol% LM945•NaGas Carton Dioxide 0.679 Mol% D-1945•N4IOas Methane 89.762 Mol% 0.19a5•NatGaa Edw.c 5.234 Mn15b D-1945-NexGae Propunc 1-816 Mol% D-1945•N®Gas 1-Bunuve. 0234 Mol% D-1945•NMGns n-Bumne 0.4611 Mol % D-1945•Nal(iae i -Pentane 0.144 Mol% D-1945•NMGa3 .Pw.. 0.161 Mol% D-190-NMGas Total C(a 0,182 Mol% D-1945-NulOm ToW Ms 0.237 Mel% D-1915•Nadc'. C6ffi Hnvier 0.576 Mol% D-1945•NalGes ca Heavier 0.157 Mol% D -1945 -NOG. Ar rage Moleculm WI 18.5 We.[ D-1945•NMGas DTU11den) CF (Dry) 1111.5 Blu'SCF D -1945 -Na w, HTCI,9dea1 CF (SM) 1094.7 Rlw'SCF D-1945•Nav(im HFD7RMCF(Dty) 1110-9 BWSCF D -1945 -NAG. BTUlR.1 CF(Seli 1091.5 MWECF D-1943•Natfee Conipressibliuy Factor 0.9974 D-1945-NutGas Net Heat orl'umbustion 109D. BlWit 04945•NaCas Specific ( wlty Ideal 06400 IM945•NalUm SFccirw Cra"Iy Real 0.6414 Oniinv l'bm Pm% Lox Pmxrure 29. psi Onliar tcrnp-Prcaa Temperature M. DegF pIMwT�3R},7^7 BRPC Application for Area Injection Order pg. 46 M-3: SMU Kuparuk Pool Crude Oil Sample Analysis, North Tarn 1A Kuparul:, Ngtrth Mom Regort or Ansivaix Sample Number. 7912528 Sample Name: EXPLOR•X Area: mhB lle¢cnus Crnil: Miscellaneous Sample Point Doc: Eadlumion sample Sampled Date: I2M'2012 10:28:Ot1AM Additional Samole Details Localioa description Draula Range North Form I A BRPC Application for Area Injection Order P9. 47 Samnln Analynt. Dewus jy{ Dela10111 eName REye IIOht U4928 KF WMre Water in Code Water 5.000 Vol% L -5002A DemRyCmk Dmtsily API Giaeity 23.9 API 11-7042 ViwVbcSmbuWr Viscosity 22.1 61 D-7042 Vise•Viw Smbinger Temparnum 100.0 DSeBF Carbon NumbrCmde by GC C1 0.00 Wt% Carbon NumbrCmde by GC C3 0.00 Wt % Cadwn NumbwUnde by GC nC4 0.00 Wt % Carbon Nmnher•Cmde by GC iC4 0.00 Wt % Carlam Nonba•Cmde by GC nC5 0.(m WI% Carbon Number -Crude by GC: iC5 0.00 WI% Carbon NumbwCmde by CC C'6 0.05 Wt% Carbon Numbu C.mde by 0C C7 0.14 Wl% Carbon NumbwC.rude M GC Cg 0.73 Wl % Carbon NumbmCrude by GC C9 1.35 W1% % Carbon NumbrCmde by GC CIO 2.P.1 W[% Carhon NumbmCmde by GC CII 316 W1% Coban NumberCmde by GC C12 4.48 Wr% Carbon NumberCmde by CC C13 4,87 Wt % Carbon NumbeK,.d. by GC C14 4.79 WI% Carbon NumherCrmle by GC Cls 4,12 W'1% Carbon NmnherCmde by GC C16 3.91 Wr% C robun NumtrCmde by GC C17 332 W1% Carlon NumbrCmde by CC cis 3.32 W1% Carbon NumberCmde by GC C19 2.96 'All % Carbon NumberrCmdeby GC CIO 2.77 Wt% Carbon Number<nKk by CC C21 2.60 Wt% Carbon NumbrCrude by GC C22 2.41 W1% Carbon Nmnher•C,.de by CC C23 2,28 WI % BRPC Application for Area Injection Order P9. 47 0-1: Map of Proposed SMU Kuparuk Development Wells BRPC Application for Area Injection Order pg, 48 20 21 22 23 24 19 P Raider HP -P -Silver R Plyntom K Rebel ., HP -K -Trigger - HP -II -Diablo 29 28 27 6 25 30 2M-17 L Ringo 21A 36 HP-W.-Argo2 Stardust 32 33 34 35 EE Flika� 31 HP -CC -FURY HP -I -Mustang 1A lAAT 5 4 3 1 6 NT -7---_ Mustang -7. NT -1A 54 HP -D- Cactus fAA3PB1 - 8 9 HP -B -Domino 10 11 12 T G Winchester V Ginger X. 2L-03 M Bingo t� X. JJ Mesquite HP -EE -Clover HP -F -Falcon Pd HP -R -Shamrock Scale = 1:43 584 0 2000 4000 6000 77 16 15�� BRPC Application for Area Injection Order pg, 48 Schlumberger »l ;"'y T71 Formation Water A®Gcc Salinity Determination West Sak 2559015 Company Field Well Date Logged Date Processed API Number Log Analyst Reviewed by Brooks Range Petroleum Kuparuk West Sak 2559015 21 -Nov -2012 11 -Dec -2012 50-103-20013-00-00 Jason Burt, Ph.D. Douglas Hupp 11are opinions based on inferences from electrical or other measurements and we cannot, and do not guarantee the accuracy or correctness of any interpretations and e shall not, except in the case of gross or willful negligence on our pad, be liable or responsible for any lass, cost, damages or expenses incurred or sustained by anyone resulting ram any interpretation made by any of our officers, agents or employees. These interpretations are also subject to clause 4 of our general terms and conditions as set out in our current rice schedule. Schlumberger -Private Apache Log Date: 21--March-1980 Field: Kuoaruk Well: West Sak 255900 15 Resistivity of NaCl Water Solutions Schlumheruer Gen -6 itemar6an-3i Comeraion approximated 6711:= Iti IRS a 077VIT:i 6.77)rF or 1, A, IIT, ♦ 21.5)7(Tx+21511°C 10 e 6 5 4 3 2 1 as 0.6 05 04 Resistivity 03 of solution (ohm -m) 01 O6hW w 01 6.08 006 005 0.64 5IR 002 0.01 I 5o 75 100 125 150 760 An 100 150 4 °C 10 20 30 40 50 60 70 80 90100 120 140 160180 200 Tempaawre Schlumberger -Private grainsfgal PPM at75°F mo 10 'a0 15 b0 20 '570 25 $00 30 % 40 !oq7 50 770 1e0 X70 zoo 100 NO 150 -(� 150 concentration q� Ippm or 240 grains/tial) �0 300 aq 900 100 o% 500 'zfb0 '00 t7 0 A� 1.000 'b[qq 1.500 40% 2A00 boa 25N 0 3,000 60 4 4,000 00 0 5,000 4"00 )zg00 4600 10,000 o� 5,000 20,000
