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Home My WebLink AboutAIO 041AREA INJECTION ORDER 41 Docket Number: AIO-18-032 Northstar Unit 1. July 18, 2018 Hilcorp’s application for Area Injection Order for Northstar Unit 2. July 24, 2018 Notice of hearing, affidavit of publication, email distribution, mailings 3. September 6, 2018 Transcript, sign in sheet and presentation 4. September 27, 2023 Hilcorp application to amend Area Injection Order (AIO 41.001) 5. August 16, 2024 Hilcorp request to allow water injection operations with slow inner annulus by outer annulus communication. (AIO 41.002) STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue Anchorage Alaska 99501 Re: THE APPLICATION OF Hilcorp Alaska, ) Docket Number: AIO-18-032 LLC for an order authorizing underground ) Area Injection Order 41 injection of fluids for enhanced oil recovery in ) Northstar Unit the Northstar-Kuparuk Oil Pool within the ) Northstar-Kuparuk Oil Pool Northstar Unit ) Beaufort Sea, Alaska November 28, 2018 IT APPEARING THAT: 1. By application dated July 18, 2018, Hilcorp Alaska, LLC (Hilcorp), as operator and sole working interest owner of the Northstar Unit (NU), requested an order authorizing underground injection for enhanced oil recovery (EOR) purposes in the Northstar-Kuparuk Oil Pool, within the NU. 2. Pursuant to 20 AAC 25.540, the Alaska Oil and Gas Conservation Commission (AOGCC) scheduled a public hearing for September 6, 2018. On July 23, 2018, the AOGCC published notice of that hearing on the State of Alaska's Online Public Notice website, the AOGCC's website, electronically transmitted the notice to all persons on the AOGCC's email distribution list and mailed printed copies of the notice to all persons on the AOGCC's mailing distribution list. On July 24, 2018, the notice was published in the Anchorage Daily News. 3. No comments on the application were received. 4. The hearing commenced at 10:00 a.m. on September 6, 2018. Evidence in support of the application was provided by representatives of Hilcorp. FINDINGS: 1. Affected Area: The Affected Area lies offshore in the Beaufort Sea, about 12 miles northwest of Prudhoe Bay, within the NU. The Northstar-Kuparuk Oil Pool (NSKOP) is being developed from the Northstar artificial island drill site, which is located in Section 11, Township (T) 13N, Range (R) 13E, Umiat Meridian (UM). 2. Owners and Landowners: Hilcorp is the operator and 100% working interest owner, and the State of Alaska (State), Department of Natural Resources and the U.S. Government are the landowners, of the Affected Area. 3. Exploration. Delineation, and Production History: Shell Oil Company (Shell) drilled the discovery well BF 47-1 (PTD #183-074; also known as Seal Island A-1) into the Ivishak (below the Kuparuk) between June and December 1983 from a surface location in Section 11, T13N, R13E, UM to a bottom hole location in Section 2 in that same township. BF 47-1 encountered oil indicators in the Kuparuk Formation (Kuparuk). Shell confirmed this discovery with three additional exploratory wells: OCS Y-0181 #1 (PTD# 184-017, also known as Seal Island A-2) drilled February to May 1984; BF 57-1 (PTD #184-093, also known as Seal Island A-3) drilled July to November 1984; and OCS Y-0180 #1 (PTD# 184- 220, also known as Seal Island A-4) drilled February to July 1985 (all into the Ivishak). A10 41 November 28, 2018 Page 2 of 12 Amerada Hess drilled additional confirmation wells Northstar 1 (PTD # 185-085), from October to December 1985, and Northstar 2 (PTD #186-013), from January to March 1986. To date, about 30 wells have been logged across the Kuparuk reservoir within the Northstar Unit while drilling to the Ivishak. Three-dimensional seismic survey and well log data have been used to determine the geologic structure and reservoir distribution at the Kuparuk. Well log, conventional and sidewall core, nodal analysis, pressure transient analysis, Repeat Formation Tester, and well test information were used to establish reservoir and fluid properties for the proposed pool. 4. Pool Identification: The NSKOP is defined in Conservation Order (CO) 739 as the accumulation of hydrocarbons common to, and correlating with, the interval between the measured depths of 12,156 and 12,446 feet on the resistivity well log recorded in development well Northstar (NS) NS -15 (PTD #202-054). 5. Geology: a. Structure: Within the development area, the structure at the top of the NSKOP forms a southeast -trending, four -way -closure anticline that measures about 7 miles by 2 miles and is cut by several southeast- and north -trending, normal faults. The top of the anticline lies at about -8,800 feet TVDSS.' b. Stratigrauhy: Within the NU, Cretaceous -aged reservoir sandstones within the Kuparuk are informally divided into two intervals, the Kuparuk C -Sands (C -Sands) and the underlying Kuparuk A -Sands (A -Sands; see Figure 1, below). The Kuparuk C -Sands consist of bioturbated and burrowed glauconitic sandstones, shaly sandstones, siltstones and shales. These sediments were most likely deposited in an offshore shelf setting. The thickness of the C -Sands interval vanes across the field: it is thinnest on the crest of the anticline and thickens off structure, a variation that is believed to be the result of syndepositional fault activity. A 10- to 50 -foot thick, laterally continuous interval of shale separates the C -Sands from the underlying A -Sands. The A -Sands consist of three to five upward -coarsening intervals. The overall thickness of the A -Sands is relatively uniform, and it does not appear to be influenced by faulting or the present-day structure. The A -Sands were deposited in an offshore setting. Together, the C- and A -Sands have a combined thickness ranging from 160 to 330 true vertical feet. c. Rock Properties: Porosity ranges from 12% to 27%, averaging 20%. Permeability ranges from 0.5 to 1,400 millidarcies and averages 220 millidarcies. Water saturation estimates for the reservoir sandstones range from 9% to 35 %, with an average of about 29%. d. Faults: The vertical displacement of faults cutting the proposed NSKOP ranges up to 175 feet but is generally less than 50 feet. Because of the relatively thin -bedded nature of reservoir sands within proposed pool, some faults may act as flow barriers. e. Trap Configuration and Seals: Well log and seismic information indicate that structural dip controls the hydrocarbon accumulation within the A -Sands to the northeast and east. To avoid confusion, when depths presented represent true vertical depth subsea, the footage will be preceded by a minus sign and followed by the acronym TVDSS (e.g., 3,000 feet true vertical subsea will be depicted as -3,000 feet TVDSS). A10 41 November 28, 2018 Page 3 of 12 Faults control the accumulation to the south, southwest, and west. For the accumulation in the C -Sands, a combination of structural dip and faulting define the boundary. 500292307300 2020540 BP NORTHSTAR UNIT NS -15 1189 FSL 645 FEL TWP: 13 N - Range: 13 E - Sec. 11 Figure 1. Northstar NS -15, Reference Log for Northstar Kuparuk C -Sands and Northstar Kuparuk A -Sands Oil Pools slwrl a .rw w>4wq rom PO W M M 2S pMl AS WGC as %� rwea> .NAM xao arr owo xo z ue¢ o. awa..y no wwgw �nrr+n n Zoo wu vM uwwn <MD om,on coo m �r ® 11300 a�0o awo 11400 11500 e� i - -8500 '.. 11600° -8500 moo 1100 7j 11800 arw - 11600 1700 Northstar �w 12000 Kuparuk + C 12100 woo I 12200 .moo C -Sands Shale 6000 Shale 12300 A3 9000 nz A -Sands s000 12400 ciao Al Northstar Kuparuk 12500 `4 12600 lzroo • 12806 B3D] 99M TD=15370 Figure 1. Northstar NS -15, Reference Log for Northstar Kuparuk C -Sands and Northstar Kuparuk A -Sands Oil Pools AIO 41 November 28, 2018 Page 4 of 12 The top seal for the proposed NSKOP is formed by about 400 true vertical feet of shale and siltstone assigned to the HRZ shale and the Kalubik Formation, in descending stratigraphic order. f. Reservoir Compartmentalization: At present, the A -Sands appear to be pressure -isolated from the overlying C -Sands: measurements in NS -08 and NS -18 indicate that there is a 700 -psi difference between these reservoir sand intervals, and no production impacts were observed in NS -08 after NS -18 was brought online. 6. Freshwater Strata: The Environmental Protection Agency determined there are no underground sources of drinking water beneath the NU when it issued a Class I Underground Injection Control permit (permit AK -1002-A, dated June 23, 2000) for the Northstar project. 7. Reservoir Fluid Contacts: The Kuparuk A -Sands contain a gas -condensate cap with an oil rim. The overlying Kuparuk C -Sands contain only gas condensate. From Repeat Formation Tester (RFT) measurements, Hilcorp places the gas -oil contact at -9,035 feet TVDSS, the gas - water contact in the Kuparuk C -Sands at -9,075 feet TVDSS, and the oil -water contact in the Kuparuk A -Sands also at -9,075 feet TVDSS. 8. Reservoir Fluid Properties: Hilcorp considers the Kuparuk C- and A -Sands at Northstar to be a gas -condensate reservoir. However, for regulatory purposes the Kuparuk C- and A -Sands are considered oil reservoirs because the producing gas oil ratio (GOR) is less than 100,000 scf/stb. The API gravity of oil recovered from the NSKOP measures about 38° to 53° and averages 47.6°, and viscosity of the gas is 0.012 centipoise. The solution GOR is estimated to be 22,000 to 62,000 standard cubic feet per stock tank barrel, and the dew point pressure is estimated between 4,244 and 4,370 psig. Initial reservoir pressure was 4,425 psi at a datum depth of -9,000 feet TVDSS, and current reservoir pressure is 3,700 psi at -9,000 feet TVDSS. Reservoir temperature is about 197° F. The oil formation volume factor is estimated at 2.07 reservoir barrels per stock tank barrel of oil, and the gas formation volume factor is estimated at 261.4 standard cubic feet of gas per reservoir cubic foot. The reservoir may have a slight water drive. 9. Production History: Four wells currently produce from the NSKOP: NS -08, NS -15, NS -13, and NS -18. NS -08 began producing gas -condensate from the NSKOP in November 2010. NS -18 began producing gas condensate and oil from the NSKOP in August 2016. NS -15 began producing from the NSKOP in August 2017. NS -13 began producing from the NSKOP in August 2018. According to the AOGCC's records, cumulative production from the NSKOP through September 2018 is about 4.88 million barrels of oil and 158 billion cubic feet of gas .2 Gas produced from the NSKOP is currently used for lease purposes and injected into the Northstar Oil Pool (N SOP) for EOR purposes. The NU currently produces more than enough gas to meet the EOR needs of the NSOP and as such there's sufficient gas available to initiate an EOR project in the NSKOP. 10. In -Place and Recoverable Volume Estimates: Hydrocarbon Resource Estimated Volume3 Original Gas in Place 500 to 550 BCF Original Oil in Place 22 to 25 MMSTB z AOGCC Production Database, accessed November 14, 2018. s The acronym MMSTB signifies millions of stock tank barrels. The acronym BCF signifies billion cubic feet of gas. The acronym MMCFPD signifies millions of cubic feet of gas per day. rs•XIJI November 28, 2018 Page 5 of 12 Primary Recovery 9 MMSTB Primary + 50 MMCFPD Gas injection 13 MMSTB Primary + 80 MMCFPD Gas injection 14.6 MMSTB These estimates are based on a full field reservoir simulation model constructed by Hilcorp to model the NSKOP. 11. Future Development Plans: Hilcorp plans to convert the NS -18 well to gas injection service and leave the remaining three NSKOP producing wells on production. Additional NSKOP producers and injectors may be added in the future either through conversion of existing wells currently completed in the Northstar Oil Pool (NSOP) or through the drilling of new wells or sidetracks. 12. Injection Rates: The anticipated peak daily injection rate for the NSKOP is 120 MMCFPD with individual well rates of 50 to 80 MMCFPD and an anticipated sustained rate of approximately 65 MMCFPD. 13. Injection Pressures: Maximum injection pressure at the well head is estimated to be — 5,300 psig. The NSKOP will be tied into the same injection system that is used for the NSOP. Average injection pressure at the wellhead for the NSOP is approximately 4,850 psig, which would effectively limit the wellhead injection pressure for the NSKOP to 4,850 psig as well. 14. Confining Layers: Approximately 400 feet of Kalubik and HRZ shales overlie the NSKOP. Several hundred feet of shales in the Miluveach and Kingak formations underlie the NSKOP. 15. Fracture Propagation and Confinement: A leak off test in the Seal A-04 well tested the overlying confining shales to a gradient of 0.79 psi/ft, or 7,200 psi at the sandface, without breaking down the formation, so it is not expected that injection into the NSKOP, which would peak at 5,300 psig, would be sufficient to initiate or propagate fractures through the confining layers. 16. Reservoir Continuity: Pressure transient analysis indicates that the Kuparuk C -Sands are laterally continuous with no major flow barriers in the development area, while the Kuparuk A -Sands are less laterally continuous and more compartmentalized. 17. Reserves Distribution: The majority of the reserves in the NSKOP are assigned to the less compartmentalized Kuparuk C -Sands where wells will drain larger areas. AIO 41 November 28, 2018 Page 6 of 12 CONCLUSIONS: 1. An Area Injection Order is appropriate to authorize the injection of fluids for enhanced oil recovery purposes in the NSKOP within the Northstar Unit. 2. Reservoir simulation modeling shows gas injection into the NSOP will provide a substantial EOR benefit over primary recovery alone and maximize ultimate recovery from the NSKOP and prevent waste. 3. The maximum possible wellhead injection pressures of 5,300 psig 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 NSKOP. 4. There are no potential USDWs in the Affected Area. 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: n1;•xn November 28, 2018 Page 7 of 12 Affected Area: From the definition of the Northstar Hooligan Participating Area effective as of December 1, 2014. TR -101 That portion of ADL 312798, more particularly described as those lands located easterly of the west boundary of TI 3M, R13E, Umiat Meridian (UM) and T14N, R13E, UM, being the north -south line intersecting the north and south boundary of Block 470, within the offshore three-mile arc lines listed as State area of block 470 "Supplemental Official O.C.S. Block Diagram" approved 10/4/79, and those lands in Block 514 easterly of the west boundary of T13N, R13E, UM (being identical with Line2-3 of Block 514) and that portion of section 16, TUN, R 13E, UM within the NI/251/2 (being easterly of Line 3-4 of Block 514), being a portion of the listed State are of Block 514 on the "Supplemental Official O.C.S. Block Diagram" approved 12/9/79, lying within: T14N, RUE, UM Section 32: E'/2 Section 33 T13N, RUE, UM Section 4 Section 5: E %2 Section 8: NE '/4 Section 9: N'/2 TR -102 That portion of ADL 312799, more particularly described as those lands located in Block 471 within the offshore three-mile arc lines listed as State area of block 471 "Supplemental Official O.C.S. Block Diagram" approved 10/4/79, and those lans in NI/2, N1/2S1/2 of Block 515 within the offshore three-mile arc lines being a portion of the listed State area on the "Supplemental Official O.C.S. Block Diagram" approved 10/4/79, lying within: T14N, R13E, UM Section 33: S1/2 S1/2 OCS Block 470 Sections 34 and 35 AIO 41 November 28, 2018 Page 8 of 12 T13N, R13E, UM Sections 1-4 & 9-15 TR -103 That portion of ADL 312808, more particularly described as those lands located in S1/2S1/2 of Block 514, within sections 16 and 21, T13N, R13E, UM (being those lands lying easterly of Line 3-4 on Block 514), a portion of the State area on the "Supplemental Official O.C.S. Block Diagram" approved 12/9/79, and those lands in S1/2S1/2 of Block 515, being a portion of the State area on the "Supplemental Official O.C.S. Block Diagram, approved 10/4/79, and those lands within Block 558 located in Section 21, T13N, R13E, UM (being the portion easterly of Line 1-2 and northerly of Line 2-3 Block 558), listed as State area on the "Supplemental Official O.C.S. Block Diagram" approved 12/9/79 and those lands in Block 559 lying northerly of the south boundary of sections 21, 22, 23, and 24, T13N R13E, UM (being the northerly portion of Block 559), listed as State area on the "Supplemental Official O.C.S. Block Diagram" approved 10/4/79, lying within: T13N, R13E, UM Sections 13 and 14 Section 15: E 1/2 TR -104 That portion of ADL 312809, more particularly described as those lands located in Block 516 within the three-mile arc lines, listed as State area on the "Supplemental Official O.C.S. Block Diagram" approved 10/4/79, and those lands in Block 560 lying northerly of the south boundary of Section 24, T13N, RUE, UM (being identical with Line 4- 5 on Block 560), and lying easterly of the west boundary and northerly of the south boundary of T13N, R14E, UM (being identical with Lines 5-6 and 6-7 on Block 560), within the offshore Three -Mile arc lines, listed as State area on the "Supplemental Official O.C.S. Block Diagram" approved 12/9/79, lying within: T13N, R13E, UM AIO 41 November 28, 2018 Page 9 of 12 Section 13: N'h S1/2 OCS Block 516 TR -1 That portion of OCS-Y-0179 - more particularly described as that portion of block 470 shown as Federal 8(g) Area B on the Supplemental Official OCS Block Diagram, dated 10/4/79, based on Official Protraction Diagram NR 6-3, Beechey Point, approved April 29, 1975, and lying southerly of line 11 -12 and line 12-13 bisecting block 470, as shown on the Supplemental Diagram of the Supplemental Official OCS Block Diagram, dated 6/4/82, based on Official Protraction Diagram NR 6-3, Beechey Point, approved April 29, 1975, and those lands lying between the two lines bisecting block 471 (further described as "disputed area"). containing approximately 611.95 hectares, as shown on the Supplemental Official OCS Block Diagram, dated 10/04/79, based on Official Protraction Diagram NR 6-3, Beechey Point, approved April 29, 1975, and those lands lying northeasterly of the line bisecting block 515, containing approximately 190.97 hectares, as shown on the Supplemental Official OCS Block Diagram, dated 10/4179, based on Official Protraction Diagram NR 6-3, Beechey Point, approved April 29, 1975, lying south of the line commencing at Easting, Northing UTM6 Meters, NAD27 435076.08, 7825840.36 and ending at Easting, Northing UTM6 Meters, NAD27 437600.00, 7824000.00, as shown on Exhibit D (dated 9/21/01) - of Block 515, containing approximately 190.97 hectares (471.89 acres}. as shown on the Supplemental Official OCS Block Diagram, dated 10/4/79, based on Official Protection Diagram NR 6-3, Beechey Point, approved April 29, 1975; And that portion of Block 471 within S1/2SW1/4 and S1/2SW1/4SE1/4, containing approximately 99.83 hectares (246.68 acres). as shown on the Supplemental Official OCS Black Diagram, dated 10/4/79, based on Official Protraction Diagram NR 6-3, Beechey Point, approved April 29, 1975; AIO 41 November 28, 2018 Page 10 of 12 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 Northstar Unit NS -15 well between measured depths (MD) of 12,156 and 12,446 feet. 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. Produced gas from the NU; b. Tracer survey fluids to monitor reservoir performance; c. Fluids used to improve near wellbore injectivity; d. Fluids used to seal wellbore intervals which negatively impact recovery efficiency; e. Fluids associated with freeze protection; and f Standard oilfield chemicals. And that portion of Block 470 lying south of the line commencing at Easting, Northing UTM6 Meters, NAD27 431762.97, 7825801 .43 and ending at Easting, Northing UTM6 Meters, NAD27 432800.00, 7825812.7 1, containing approximately 15.01 hectares (37.09 acres). as shown on the Supplemental Diagram, dated 2/25/88, based on Supplemental Official OCS Block Diagram, dated 10/4/79, based on Official Protraction Diagram NR 6-3, Beechey Point, approved April 29, 1975. TR -2 That portion of Block 516 within NW1/4SW1/4 and SWI ANW1/4, containing approximately 267.28 hectares (660.45 acres), as shown on the Supplemental Official OCS Block Diagram, dated 10/4179, based on Official Protraction Diagram NR 6-3, Beechey Point, approved April 29, 1975. 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 Northstar Unit NS -15 well between measured depths (MD) of 12,156 and 12,446 feet. 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. Produced gas from the NU; b. Tracer survey fluids to monitor reservoir performance; c. Fluids used to improve near wellbore injectivity; d. Fluids used to seal wellbore intervals which negatively impact recovery efficiency; e. Fluids associated with freeze protection; and f Standard oilfield chemicals. AIO 41 November 28, 2018 Page 11 of 12 Rule 4 Authorized Injection Pressure for Enhanced Recovery Injection pressures will be managed so as not to exceed the maximum injection gradient of 0.79 psi/ft to ensure containment of injected fluids within the defined affected area and injection interval. Rule 5 Monitorin¢ Tubin¢-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 Northstar-Kuparuk Oil Pool and are located within a''/a-mile radius of a Northstar-Kuparuk Oil Pool injector shall be monitored daily. All monitoring results shall be documented and available for AOGCC inspection. Rule 6 Demonstration of Tubing/Casio¢ Annulus Mechanical Integrity The mechanical integrity of each injection well must be demonstrated before injection begins and before returning a well to service following any workover affecting mechanical integrity. An AOGCC-witnessed MIT must be performed after injection is commenced for the first time in a well, to be scheduled when injection conditions (temperature, pressure, rate, etc.) have stabilized. Subsequent tests must be performed at least once every four years thereafter. The AOGCC must be notified at least 24 hours in advance to enable a representative to witness an MIT. Unless an alternate means is approved by the AOGCC, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1,500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, that shows stabilizing pressure and does not change more than 10 percent during a 30 -minute period. Results of MITs must be readily available for AOGCC inspection. Rule 7 Well Inte¢rity 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 Northstar Kuparuk Oil Pool is not cemented), the Operator shall notify the AOGCC by the next business day and submit a plan of corrective action on a Form 10-403 for AOGCC approval. The Operator shall immediately shut in the well if continued operation would be unsafe or would threaten contamination of freshwater. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the AOGCC for all injection wells for which well integrity failure or lack of injection zone isolation is indicated. Rule 8 Notification of Improper Class 11 Iniection Injection of fluids other than those listed in Rule 3 without prior authorization is considered improper Class II injection. Upon discovery of such an event, the operator must immediately notify the AOGCC, provide details of the operation, and propose actions to prevent recurrence. This requirement is in addition to and does not relieve the operator of any other obligations under the notification requirements of any other State or Federal agency, regulation or law. Rule 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 may 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 AIO 41 November 28, 2018 Page 12 of 12 sound engineering and geoscience principles, and will not result in an increased risk of fluid freshwater. DONE at Anchorage, Alaska and dated November 28, 2018. 60�� Z9 Hollis S. French Daniel T. Seamount, Jr. Cath P. Foerster Chair, Commissioner 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 most 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 pan 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 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 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION 333 West 7th Avenue Anchorage Alaska 99501 Re: THE APPLICATION OF Hilcorp Alaska, ) Docket Number: AIO-18-032 LLC for an order authorizing underground ) Area Injection Order 41 injection of fluids for enhanced oil recovery in ) Northstar Unit the Northstar-Kuparuk Oil Pool within the ) Northstar-Kuparuk Oil Pool Northstar Unit ) Beaufort Sea, Alaska November 28, 2018 IT APPEARING THAT: 1. By application dated July 18, 2018, Hilcorp Alaska, LLC (Hilcorp), as operator and sole working interest owner of the Northstar Unit (NU), requested an order authorizing underground injection for enhanced oil recovery (EOR) purposes in the Northstar-Kuparuk Oil Pool, within the NU. 2. Pursuant to 20 AAC 25.540, the Alaska Oil and Gas Conservation Commission (AOGCC) scheduled a public hearing for September 6, 2018. On July 23, 2018, the AOGCC published notice of that hearing on the State of Alaska's Online Public Notice website, the AOGCC's website, electronically transmitted the notice to all persons on the AOGCC's email distribution list and mailed printed copies of the notice to all persons on the AOGCC's mailing distribution list. On July 24, 2018, the notice was published in the Anchorage Daily News. 3. No comments on the application were received. 4. The hearing commenced at 10:00 a.m. on September 6, 2018. Evidence in support of the application was provided by representatives of Hilcorp. FINDINGS: 1. Affected Area: The Affected Area lies offshore in the Beaufort Sea, about 12 miles northwest of Prudhoe Bay, within the NU. The Northstar-Kuparuk Oil Pool (NSKOP) is being developed from the Northstar artificial island drill site, which is located in Section 11, Township (T) 13N, Range (R) 13E, Umiat Meridian (UM). 2. Owners and Landowners: Hilcorp is the operator and 100% working interest owner, and the State of Alaska (State), Department of Natural Resources and the U.S. Government are the landowners, of the Affected Area. Exploration. Delineation. and Production History: Shell Oil Company (Shell) drilled the discovery well BF 47-1 (PTD #183-074; also known as Seal Island A-1) into the Ivishak (below the Kuparuk) between June and December 1983 from a surface location in Section 11, T13N, R13E, UM to a bottom hole location in Section 2 in that same township. BF 47-1 encountered oil indicators in the Kuparuk Formation (Kuparuk). Shell confirmed this discovery with three additional exploratory wells: OCS Y-0181 #1 (PTD# 184-017, also known as Seal Island A-2) drilled February to May 1984; BF 57-1 (PTD #184-093, also known as Seal Island A-3) drilled July to November 1984; and OCS Y-0180 #1 (PTD# 184- 220, also known as Seal Island A-4) drilled February to July 1985 (all into the Ivishak). AIO 41 November 28, 2018 Page 2 of 12 Amerada Hess drilled additional confirmation wells Northstar 1 (PTD # 185-085), from October to December 1985, and Northstar 2 (PTD #186-013), from January to March 1986. To date, about 30 wells have been logged across the Kuparuk reservoir within the Northstar Unit while drilling to the Ivishak. Three-dimensional seismic survey and well log data have been used to determine the geologic structure and reservoir distribution at the Kuparuk. Well log, conventional and sidewall core, nodal analysis, pressure transient analysis, Repeat Formation Tester, and well test information were used to establish reservoir and fluid properties for the proposed pool. 4. Pool Identification: The NSKOP is defined in Conservation Order (CO) 739 as the accumulation of hydrocarbons common to, and correlating with, the interval between the measured depths of 12,156 and 12,446 feet on the resistivity well log recorded in development well Northstar (NS) NS -15 (PTD #202-054). 5. Geology: a. Structure: Within the development area, the structure at the top of the NSKOP forms a southeast -trending, four -way -closure anticline that measures about 7 miles by 2 miles and is cut by several southeast- and north -trending, normal faults. The top of the anticline lies at about -8,800 feet TVDSS.1 b. Stratigraphy: Within the NU, Cretaceous -aged reservoir sandstones within the Kuparuk are informally divided into two intervals, the Kuparuk C -Sands (C -Sands) and the underlying Kuparuk A -Sands (A -Sands; see Figure 1, below). The Kuparuk C -Sands consist of bioturbated and burrowed glauconitic sandstones, shaly sandstones, siltstones and shales. These sediments were most likely deposited in an offshore shelf setting. The thickness of the C -Sands interval varies across the field: it is thinnest on the crest of the anticline and thickens off structure, a variation that is believed to be the result of syndepositional fault activity. A 10- to 50 -foot thick, laterally continuous interval of shale separates the C -Sands from the underlying A -Sands. The A -Sands consist of three to five upward -coarsening intervals. The overall thickness of the A -Sands is relatively uniform, and it does not appear to be influenced by faulting or the present-day structure. The A -Sands were deposited in an offshore setting. Together, the C- and A -Sands have a combined thickness ranging from 160 to 330 true vertical feet. c. Rock Properties: Porosity ranges from 12% to 27%, averaging 20%. Permeability ranges from 0.5 to 1,400 millidarcies and averages 220 millidarcies. Water saturation estimates for the reservoir sandstones range from 9% to 35 %, with an average of about 29%. d. Faults: The vertical displacement of faults cutting the proposed NSKOP ranges up to 175 feet but is generally less than 50 feet. Because of the relatively thin -bedded nature of reservoir sands within proposed pool, some faults may act as flow barriers. e. Trap Configuration and Seals: Well log and seismic information indicate that structural dip controls the hydrocarbon accumulation within the A -Sands to the northeast and east. To avoid confusion, when depths presented represent true vertical depth subsea, the footage will be preceded by a minus sign and followed by the acronym TVDSS (e.g., 3,000 feet true vertical subsea will be depicted as -3,000 feet TVDSS). AIO 41 November 28, 2018 Page 3 of 12 Faults control the accumulation to the south, southwest, and west. For the accumulation in the C -Sands, a combination of structural dip and faulting define the boundary. 2020540 BP NORTHSTAR UNIT NS -15 1189 FSL 645 FEL TWP: 13 N - Range: 13 E - See. 11 -85001 -9000 1 Figure 1. Northstar NS -15, Reference Log for Northstar Kuparuk C -Sands and Northstar Kuparuk A -Sands Oil Pools gfpY 11300 ewa mNnl a '�'a WGIHh wm to zm oroae zoo m eNs a¢ 11500 aw iwa6> h.Mwrq zJo ar zW z a¢c ayou., N wNw4 MW ® ,w mapvs, xagNN W tlMl R VN <MD mwrn n wr Nmwn, 11600 V- -85001 -9000 1 Figure 1. Northstar NS -15, Reference Log for Northstar Kuparuk C -Sands and Northstar Kuparuk A -Sands Oil Pools gfpY 11300 ewa 11400 aaoo 11500 aw --8500 �, 11600 °b0 awa 11700 11600 V- 11:00 sraa Northstar K 12000 Kuparuk ° C 12100 aeon 12200 X00 Shale e000 12300 A3 -9000 a000 -A2" 12400 atro Al Northstar Kuparuk 12500 a A 12600 9W 1270: 9>U 12800 9KU TD=15370 -85001 -9000 1 Figure 1. Northstar NS -15, Reference Log for Northstar Kuparuk C -Sands and Northstar Kuparuk A -Sands Oil Pools A10 41 November 28, 2018 Page 4 of 12 The top seal for the proposed NSKOP is formed by about 400 true vertical feet of shale and siltstone assigned to the HRZ shale and the Kalubik Formation, in descending stratigraphic order. f. Reservoir Compartmentalization: At present, the A -Sands appear to be pressure -isolated from the overlying C -Sands: measurements in NS -08 and NS -18 indicate that there is a 700 -psi difference between these reservoir sand intervals, and no production impacts were observed in NS -08 after NS -18 was brought online. 6. Freshwater Strata: The Environmental Protection Agency determined there are no underground sources of drinking water beneath the NU when it issued a Class I Underground Injection Control permit (permit AK -1002-A, dated June 23, 2000) for the Northstar project. 7. Reservoir Fluid Contacts: The Kuparuk A -Sands contain a gas -condensate cap with an oil rim. The overlying Kuparuk C -Sands contain only gas condensate. From Repeat Formation Tester (RFT) measurements, Hilcorp places the gas -oil contact at -9,035 feet TVDSS, the gas - water contact in the Kuparuk C -Sands at -9,075 feet TVDSS, and the oil -water contact in the Kuparuk A -Sands also at -9,075 feet TVDSS. 8. Reservoir Fluid Properties: Hilcorp considers the Kuparuk C- and A -Sands at Northstar to be a gas -condensate reservoir. However, for regulatory purposes the Kuparuk C- and A -Sands are considered oil reservoirs because the producing gas oil ratio (GOR) is less than 100,000 scf/stb. The API gravity of oil recovered from the NSKOP measures about 38° to 53° and averages 47.6°, and viscosity of the gas is 0.012 centipoise. The solution GOR is estimated to be 22,000 to 62,000 standard cubic feet per stock tank barrel, and the dew point pressure is estimated between 4,244 and 4,370 psig. Initial reservoir pressure was 4,425 psi at a datum depth of -9,000 feet TVDSS, and current reservoir pressure is 3,700 psi at -9,000 feet TVDSS. Reservoir temperature is about 197° F. The oil formation volume factor is estimated at 2.07 reservoir barrels per stock tank barrel of oil, and the gas formation volume factor is estimated at 261.4 standard cubic feet of gas per reservoir cubic foot. The reservoir may have a slight water drive. 9. Production History: Four wells currently produce from the NSKOP: NS -08, NS -15, NS -13, and NS -18. NS -08 began producing gas -condensate from the NSKOP in November 2010. NS -18 began producing gas condensate and oil from the NSKOP in August 2016. NS -15 began producing from the NSKOP in August 2017. NS -13 began producing from the NSKOP in August 2018. According to the AOGCC's records, cumulative production from the NSKOP through September 2018 is about 4.88 million barrels of oil and 158 billion cubic feet of gas.2 Gas produced from the NSKOP is currently used for lease purposes and injected into the Northstar Oil Pool (NSOP) for EOR purposes. The NU currently produces more than enough gas to meet the EOR needs of the NSOP and as such there's sufficient gas available to initiate an EOR project in the NSKOP. 10. In -Place and Recoverable Volume Estimates: Hydrocarbon Resource Estimated Volume Original Gas in Place 500 to 550 BCF Original Oil in Place 22 to 25 MMSTB z AOGCC Production Database, accessed November 14, 2018. 3 The acronym MMSTB signifies millions of stock tank barrels. The acronym BCF signifies billion cubic feet of gas. The acronym MMCFPD signifies millions of cubic feet of gas per day. AIO 41 November 28, 2018 Page 5 of 12 Primary Recovery 9 MMSTB Primary + 50 MMCFPD Gas injection 13 MMSTB Primary + 80 MMCFPD Gas injection 14.6 MMSTB These estimates are based on a full field reservoir simulation model constructed by Hilcorp to model the NSKOP. 11. Future Development Plans: Hilcorp plans to convert the NS -18 well to gas injection service and leave the remaining three NSKOP producing wells on production. Additional NSKOP producers and injectors may be added in the future either through conversion of existing wells currently completed in the Northstar Oil Pool (NSOP) or through the drilling of new wells or sidetracks. 12. Injection Rates: The anticipated peak daily injection rate for the NSKOP is 120 MMCFPD with individual well rates of 50 to 80 MMCFPD and an anticipated sustained rate of approximately 65 MMCFPD. 13. Injection Pressures: Maximum injection pressure at the well head is estimated to be — 5,300 psig. The NSKOP will be tied into the same injection system that is used for the NSOP. Average injection pressure at the wellhead for the NSOP is approximately 4,850 psig, which would effectively limit the wellhead injection pressure for the NSKOP to 4,850 psig as well. 14. Confining Lavers: Approximately 400 feet of Kalubik and HRZ shales overlie the NSKOP. Several hundred feet of shales in the Miluveach and Kingak formations underlie the NSKOP. 15. Fracture Propagation and Confinement: A leak off test in the Seal A-04 well tested the overlying confining shales to a gradient of 0.79 psi/ft, or 7,200 psi at the sandface, without breaking down the formation, so it is not expected that injection into the NSKOP, which would peak at 5,300 psig, would be sufficient to initiate or propagate fractures through the confining layers. 16. Reservoir Continuity: Pressure transient analysis indicates that the Kuparuk C -Sands are laterally continuous with no major flow barriers in the development area, while the Kuparuk A -Sands are less laterally continuous and more compartmentalized. 17. Reserves Distribution: The majority of the reserves in the NSKOP are assigned to the less compartmentalized Kuparuk C -Sands where wells will drain larger areas. AIO 41 November 28, 2018 Page 6 of 12 CONCLUSIONS: 1. An Area Injection Order is appropriate to authorize the injection of fluids for enhanced oil recovery purposes in the NSKOP within the Northstar Unit. 2. Reservoir simulation modeling shows gas injection into the NSOP will provide a substantial EOR benefit over primary recovery alone and maximize ultimate recovery from the NSKOP and prevent waste. The maximum possible wellhead injection pressures of 5,300 psig 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 NSKOP. 4. There are no potential USDWs in the Affected Area. 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: A10 41 November 28, 2018 Page 7 of 12 Affected Area: From the definition of the Northstar Hooligan Pa icit)atina Area effective as of December], 2014. TR -101 That portion of ADL 312798, more particularly described as those lands located easterly of the west boundary of TUM, R13E, Umiat Meridian (UM) and T14N, R13E, UM, being the north -south line intersecting the north and south boundary of Block 470, within the offshore three-mile arc lines listed as State area of block 470 "Supplemental Official O.C.S. Block Diagram" approved 10/4/79, and those lands in Block 514 easterly of the west boundary of TUN, RUE, UM (being identical with Line2-3 of Block 514) and that portion of section 16, T13N, R 13E, UM within the N1/2S1/2 (being easterly of Line 3-4 of Block 514), being a portion of the listed State are of Block 514 on the "Supplemental Official O.C.S. Block Diagram" approved 12/9/79, lying within: T14N, RUE, UM Section 32: E %2 Section 33 T13N, R13E, UM Section 4 Section 5: E'/2 Section 8: NE '/4 Section 9: N '/2 TR -102 That portion of ADL 312799, more particularly described as those lands located in Block 471 within the offshore three-mile arc lines listed as State area of block 471 "Supplemental Official O.C.S. Block Diagram" approved 10/4/79, and those lans in N1/2, N1/2S1/2 of Block 515 within the offshore three-mile arc lines being a portion of the listed State area on the "Supplemental Official O.C.S. Block Diagram" approved 10/4/79, lying within: T14N, R13E, UM Section 33: Sl/2 SI/2 OCS Block 470 Sections 34 and 35 A10 41 November 28, 2018 Page 8 of 12 TUN, R13E, UM Sections 1-4 & 9-15 TR -103 That portion of ADL 312808, more particularly described as those lands located in S1/2S 1/2 of Block 514, within sections 16 and 21, T13N, R13E, UM (being those lands lying easterly of Line 3-4 on Block 514), a portion of the State area on the "Supplemental Official O.C.S. Block Diagram" approved 12/9/79, and those lands in S1/2S1/2 of Block 515, being a portion of the State area on the "Supplemental Official O.C.S. Block Diagram, approved 10/4/79, and those lands within Block 558 located in Section 21, T13N, RUE, UM (being the portion easterly of Line 1-2 and northerly of Line 2-3 Block 558), listed as State area on the "Supplemental Official O.C.S. Block Diagram" approved 12/9/79 and those lands in Block 559 lying northerly of the south boundary of sections 21, 22, 23, and 24, T13N RUE, UM (being the northerly portion of Block 559), listed as State area on the "Supplemental Official O.C.S. Block Diagram" approved 10/4/79, lying within: TUN, R13E, UM Sections 13 and 14 Section 15: E 1/2 TR -104 That portion of ADL 312809, more particularly described as those lands located in Block 516 within the three-mile arc lines, listed as State area on the "Supplemental Official O.C.S. Block Diagram" approved 10/4/79, and those lands in Block 560 lying northerly of the south boundary of Section 24, TUN, R13E, UM (being identical with Line 4- 5 on Block 560), and lying easterly of the west boundary and northerly of the south boundary of T13N, R14E, UM (being identical with Lines 5-6 and 6-7 on Block 560), within the offshore Three -Mile are lines, listed as State area on the "Supplemental Official O.C.S. Block Diagram" approved 12/9/79, lying within: T13N, R13E, UM AIO 41 November 28, 2018 Page 9 of 12 Section 13: N'/2 S1/2 OCS Block 516 TR -1 That portion of OCS-Y-0179 - more particularly described as that portion of block 470 shown as Federal 8(g) Area B on the Supplemental Official OCS Block Diagram, dated 10/4/79, based on Official Protraction Diagram NR 6-3, Beechey Point, approved April 29, 1975, and lying southerly of line 11 -12 and line 12-13 bisecting block 470, as shown on the Supplemental Diagram of the Supplemental Official OCS Block Diagram, dated 6/4/82, based on Official Protraction Diagram NR 6-3, Beechey Point, approved April 29, 1975, and those lands lying between the two lines bisecting block 471 (further described as "disputed area"). containing approximately 61 1.95 hectares, as shown on the Supplemental Official OCS Block Diagram, dated 10/04/79, based on Official Protraction Diagram NR 6-3, Beechey Point, approved April 29, 1975, and those lands lying northeasterly of the line bisecting block 515, containing approximately 190.97 hectares, as shown on the Supplemental Official OCS Block Diagram, dated 10/4179, based on Official Protraction Diagram NR 6-3, Beechey Point, approved April 29, 1975, lying south of the line commencing at Fasting, Northing UTM6 Meters, NAD27 435076.08, 7825840.36 and ending at Easting, Northing UTM6 Meters, NAD27 437600.00, 7824000.00, as shown on Exhibit D (dated 9/21/01) - of Block 515, containing approximately 190.97 hectares (471.89 acres}. as shown on the Supplemental Official OCS Block Diagram, dated 10/4/79, based on Official Protection Diagram NR 6-3, Beechey Point, approved April 29, 1975; And that portion of Block 471 within S 1 /2S W 1 A and S 1 /2S W 1 ASE 1 /4, containing approximately 99.83 hectares (246.68 acres). as shown on the Supplemental Official OCS Block Diagram, dated 10/4/79, based on Official Protraction Diagram NR 6-3, Beechey Point, approved April 29, 1975; A10 41 November 28, 2018 Page 10 of 12 Rule 1 Authorized Infection 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 Northstar Unit NS -15 well between measured depths (MD) of 12,156 and 12,446 feet. 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. Produced gas from the NU; b. Tracer survey fluids to monitor reservoir performance; c. Fluids used to improve near wellbore injectivity; d. Fluids used to seal wellbore intervals which negatively impact recovery efficiency; e. Fluids associated with freeze protection; and f. Standard oilfield chemicals. And that portion of Block 470 lying south of the line commencing at Easting, Northing UTM6 Meters, NAD27 431762.97, 7825801 .43 and ending at Easting, Northing UTM6 Meters, NAD27 432800.00, 7825812.71, containing approximately 15.01 hectares (37.09 acres). as shown on the Supplemental Diagram, dated 2/25/88, based on Supplemental Official OCS Block Diagram, dated 10/4/79, based on Official Protraction Diagram NR 6-3, Beechey Point, approved April 29, 1975. TR -2 That portion of Block 516 within N W 1 /4S W l /4 and SWI /4N W 1 /4, containing approximately 267.28 hectares (660.45 acres), as shown on the Supplemental Official OCS Block Diagram, dated 10/4179, based on Official Protraction Diagram NR 6-3, Beechey Point, approved April 29, 1975. Rule 1 Authorized Infection 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 Northstar Unit NS -15 well between measured depths (MD) of 12,156 and 12,446 feet. 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. Produced gas from the NU; b. Tracer survey fluids to monitor reservoir performance; c. Fluids used to improve near wellbore injectivity; d. Fluids used to seal wellbore intervals which negatively impact recovery efficiency; e. Fluids associated with freeze protection; and f. Standard oilfield chemicals. AIO 41 November 28, 2018 Page 11 of 12 Rule 4 Authorized Iniection Pressure for Enhanced Recovery Injection pressures will be managed so as not to exceed the maximum injection gradient of 0.79 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 Northstar-Kuparuk Oil Pool and are located within a'/4 -mile radius of a Northstar-Kuparuk Oil Pool injector shall be monitored daily. All monitoring results shall be documented and available for AOGCC inspection. Rule 6 Demonstration of Tubing/Casing Annulus Mechanical Integrity The mechanical integrity of each injection well must be demonstrated before injection begins and before returning a well to service following any workover affecting mechanical integrity. An AOGCC-witnessed MIT must be performed after injection is commenced for the first time in a well, to be scheduled when injection conditions (temperature, pressure, rate, etc.) have stabilized. Subsequent tests must be performed at least once every four years thereafter. The AOGCC must be notified at least 24 hours in advance to enable a representative to witness an MIT. Unless an alternate means is approved by the AOGCC, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1,500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, that shows stabilizing pressure and does not change more than 10 percent during a 30 -minute period. Results of MLTs 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 Northstar Kuparuk Oil Pool is not cemented), the Operator shall notify the AOGCC by the next business day and submit a plan of corrective action on a Form 10-403 for AOGCC approval. The Operator shall immediately shut in the well if continued operation would be unsafe or would threaten contamination of freshwater. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the AOGCC for all injection wells for which well integrity failure or lack of injection zone isolation is indicated. Rule 8 Notification of Improper Class II Iniection Injection of fluids other than those listed in Rule 3 without prior authorization is considered improper Class Il 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 may 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 AIO 41 November 28, 2018 Page 12 of 12 sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater. DONE at Anchorage, Alaska and dated November 28, 2018. //signature on file// //signature on file// //signature on file//k' Hollis S. French Daniel T. Seamount, Jr. Cathy P. Foerster „' Chair, Commissioner Commissioner Commissioner �h �+nos cu's'sv 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 I0days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day Bernie Karl K&K Recycling Inc. Gordon Severson Penny Vadla P.O. Box 58055 3201 Westmar Cir. 399 W. Riverview Ave. Fairbanks, AK 99711 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 George Vaught, Jr. Darwin Waldsmith Richard Wagner P.O. Box 13557 P.O. Box 39309 P.O. Box 60868 Denver, CO 80201-3557 Ninilchik, AK 99639 Fairbanks, AK 99706 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 41.001 Sarah Hannegan Alaska Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 Re: Docket Number: AIO-23-030 Request for Administrative Approval to Area Injection Order 41 to authorize water as an approved injection fluid Northstar Unit (NU) Northstar-Kuparuk Oil Pool (NKOP) Dear Ms. Hannegan: By letter dated September 27, 2023, Hilcorp Alaska, LLC (Hilcorp) requested administrative approval to add water to the list (found in Rule 3) of fluids authorized for enhanced oil recovery injection in Area Injection Order No. 41 (AIO 41). In accordance with 20 AAC 25.556(d), the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS, with the condition listed below, Hilcorp’s request for administrative approval to add water as an approved enhanced oil recovery injection fluid. Production from the NU does not yield enough produced gas to balance reservoir voidage in both the NKOP and the Northstar Oil Pool (NOP) simultaneously. The current reservoir management plan calls for maintaining reservoir pressure in the NOP above bubble point and minimum miscibility pressure. As such, the NOP receives enough gas to balance reservoir voidage and the NKOP ends up not being able to inject enough gas to be able to balance the voidage and thus the reservoir pressure has dropped from over 4,000 psi to under 3,000 psi. Declining reservoir pressure will lead to reduced liquids recovery from the NOP. The Northstar field currently produces approximately 14,000 BWPD, all of which is disposed of in the field’s Class I disposal wells, and water production is expected to rise as the field continues to mature. Hilcorp proposes injecting this produced water into the NKOP to enhance ultimate recovery. In July 2023 Hilcorp conducted an AOGCC approved water injectivity test on the NS- 15 well (API No. 50-029-23073-00-00) and it was found that this well could inject the entire produced water stream at pressures well below those that would be expected to initiate fractures. The injectivity test injected water at three different injection pressures and held steady at those AIO 41.001 December 07, 2023 Page 2 of 3 pressures for several hours. No degradation of injectability was noticed during this test. The NKOP is a gas condensate reservoir with an oil rim of varying thickness, several NOP producers penetrate the NKOP below or near its oil water contact. Several of these wells produce at marginal GORs and are either cycled or are long term shut in and would be good candidates to convert to NKOP water injection service. The current voidage replacement ratio (VRR) in the NKOP with gas only injection is 0.82, with injecting all the produced water in the NKOP for EOR purposes the VRR would increase to 0.92 and yield an expected increase in the NKOP of approximately 180 psi over what is forecast with gas only injection by 2030. Liquids recovery from a gas condensate reservoir is maximized by maintaining the reservoir pressure as high as possible, thus the 180 psi increase should yield additional recovery from the NKOP. The Northstar Field production facilities have a water handling capacity of 30,000 BWPD, so currently the field is producing at less than half the water handling capacity. The excess capacity currently available means that water breakthrough in the NKOP or continuing encroachment of the aquifer in the NOP will not result in reduced liquid hydrocarbons production anytime in the near future. Hilcorp has demonstrated that produced water can be safely injected into the NKOP and that water injection should improve ultimate recovery. Seawater and produced waters from other fields has not been demonstrated to be compatible with the NKOP at this time. In order to inject seawater and/or produced water from other fields Hilcorp will first need to demonstrate the compatibility of those water sources with the NKOP. Conversion of any well to water injection service in the NKOP will require Hilcorp to submit a sundry application and obtain AOGCC approval before injection can commence. NOW THERFORE IT IS ORDERED THAT Rule 3 of AIO 41 shall be amended to read as follows: Rule 3 Authorized Fluids for Injection for Enhanced Recovery Fluids authorized for injection are: a. Produced gas from the NU; b. Tracer survey fluids to monitor reservoir performance; c. Fluids used to improve near wellbore injectivity; d. Fluids used to seal wellbore intervals which negatively impact recovery efficiency; e. Fluids associated with freeze protection; f. Standard oilfield chemicals; and g. Produced water from the NU. As a condition of this approval Hilcorp must submit a sundry application, and receive AOGCC approval of the application, before converting any wells to water injection service in the NKOP. AIO 41.001 December 07, 2023 Page 3 of 3 DONE at Anchorage, Alaska and dated December 07, 2023. Jessie L. Chmielowski Gregory C. Wilson Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Gregory Wilson Digitally signed by Gregory Wilson Date: 2023.12.07 14:40:11 -09'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2023.12.07 15:09:25 -09'00' From:Carlisle, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Area Injection Order 41.001 (KRU) Date:Thursday, December 7, 2023 3:35:02 PM Attachments:AIO41.001.pdf Docket Number: AIO-23-030 Request for Administrative Approval to Area Injection Order 41 to authorize water as an approved injection fluid Northstar Unit (NU) Northstar-Kuparuk Oil Pool (NKOP) Samantha Carlisle Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: samantha.carlisle@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.carlisle%40alaska.gov Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER 41.002 Ms. Sara Hannegan Alaska Islands Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Docket Number: AIO-24-023 Request for Administrative Approval to Area Injection Order 41; Water Injection Northstar Unit (NU) NS-20 (PTD 202-188), Kuparuk Oil Pool Dear Ms. Hannegan: By emailed letter dated August 16, 2024, Hilcorp Alaska, LLC (Hilcorp) requested administrative approval to continue water injection with a known inner annulus by outer annulus (IAxOA) pressure communication. In accordance with 20 AAC 25.556(d), the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS, subject to conditions, Hilcorp’s request for administrative approval to continue water injection in the subject well. Hilcorp has submitted this application in conjunction to a Sundry Application 324-475 to convert this Kuparuk producer into a water only Kuparuk injector. Hilcorp has determined there is a slow IA by OA pressure communication, and that due to the wellbore configuration and cemented annuli, there is a reduced monitorable annuli which increases the risk of potential out of zone injection. Hilcorp has performed diagnostics including a passing state-witnessed mechanical integrity test (MIT) of the tubing and a combination MIT of the tubing and IA on August 27, 2023. Hilcorp also performed a passing non-witnessed mechanical integrity test (MIT) of the IA (to a pressure of 3275 psi) on November 21, 2023. This indicates that NS-20 exhibits at least two competent barriers to the release of well pressure. Hilcorp maintains live transmitters on the inner and outer annulus and alarm functions in the Supervisory Control and Data Acquisition (SCADA) system with remote shut down capabilities that create layers of protection from an over pressure event. These inner and outer annulus alarms and shut in protocols combined with the planned inner and outer annulus operating pressure limits enable AOGCC to continue to authorize water injection. Conclusion 4. Of AIO 41 states “There are no potential USDWs in the Affected Area.” AOGCC believes Hilcorp can safely manage the slow IAxOA communication with periodic pressure bleeds by maintaining the IA to a pressure not to exceed 2,000 psi and OA to not to exceed AIO 41.002 September 6, 2024 Page 2 of 3 1,000 psi. Accordingly, the AOGCC believes that the well’s condition does not compromise overall well integrity so as to threaten human safety or the environment. AOGCC’s approval to continue water only injection in NS-20 is conditioned upon the following: 1) Hilcorp shall record wellhead pressures and injection rate daily; 2) Hilcorp shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3) Hilcorp shall perform a MITIA every two years to the greater of the maximum anticipated injection pressure or 0.25 x packer TVD, but not less than 1,500 psi; 4) Hilcorp shall perform a MITT every two years to the greater of the maximum anticipated injection pressure or 0.25 x packer TVD, but not less than 1,500 psi; 5) Hilcorp shall perform a static bottom hole pressure survey (SBHPS) every two years to observe for any increases in bottom bole pressure that could indicate communication with formations other than the Kuparuk; 6) Hilcorp shall limit the well’s inner annulus operating pressure to 2,000 psi and the outer annulus operating pressure to 1,000 psi. Audible control room alarms and SCADA well shut in logic shall be set at or below these limits; 7) Hilcorp shall monitor the inner and outer annulus pressures in real time with its SCADA system; 8) Hilcorp shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 9) After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 10) The next required MITIA and MITT shall be completed within 10 days of initial injection, when temperature and pressures have stabilized. The Commission must be provided the opportunity to witness the MIT for a test to establish a new test due date. DONE at Anchorage, Alaska and dated September 6, 2024. Jessie L. Chmielowski Gregory C. Wilson Commissioner Commissioner Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.09.05 21:55:48 -08'00' Gregory Wilson Digitally signed by Gregory Wilson Date: 2024.09.06 09:57:50 -08'00' AIO 41.002 September 6, 2024 Page 3 of 3 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. From:Coldiron, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Area Injection Order 41.002 (Hilcorp) Date:Friday, September 6, 2024 10:07:25 AM Attachments:aio41.002.pdf Docket Number: AIO-24-023 Request for Administrative Approval to Area Injection Order 41; Water Injection Northstar Unit (NU) NS-20 (PTD 202-188), Kuparuk Oil Pool Samantha Coldiron AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: samantha.coldiron@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.coldiron%40alaska.go v 5 Hilcorp Alaska, LLC Sara Hannegan, Alaska Islands Operations Manager 3800 Centerpoint Dr, Suite 1400 Anchorage, Alaska 99503 Page 1 of 5 8/16/2024 Commissioner Jessie Chmielowski Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Subject: Northstar well NS20 (PTD# 202188). Request to allow water injection operations with slow inner annulus by outer annulus communication. Dear Commissioner Chmielowski, Hilcorp Alaska, LLC requests administrative approval for continued water injection into Northstar well NS20 (PTD# 202188) with slow inner annulus (IA) by outer annulus (OA) communication. No increase to Maximum Operating Annulus Surface Pressure (MOASP) is required. NS20 has historically been a natural ﬂowing Ivishak producer. In 2005, IA by OA communication was conﬁrmed to be present. An OA cement down squeeze was attempted and completed on 8/28/2005 under sundry number 305-220. The well continued to display IA by OA communication, but it was determined to be manageable by bleeds and the well remained an operable producer. The well was then converted to a Kuparuk producer in 2023. An AOGCC witnessed MIT-IA to 3275psi passed on 11/21/2023 under sundry number 323-602. However, when gas lift pressure is applied to the IA, a slow IA by OA pressurization is observable. Hilcorp Alaska, LLC has determined that well NS20 is safe to operate in its current condition and requests administrative approval for continued water injection services based on the following: x OA pressure can be maintained below MOASP by managing the OA pressurewith periodic annular bleeds. x MIT-IA passed to 3275psi. x IA and OA pressure are continually monitored with pressure gauges and can perform automated well shut ins based on high pressure. The cumulative incremental hydrocarbon recovery associated with water injection in NS20 through year end of 2030 is between 85,000 and 240,000 bbls of oil. If you have any questions, please call me at 907-309-1196 or Brenden Swensen at 907-748-8581. Sincerely, Sara Hannegan Alaska Islands Operations Manager Attachments: TIO Plot, Wellbore Schematic By Samantha Coldiron at 8:28 am, Aug 19, 2024 Digitally signed by Sara Hannegan (2519) DN: cn=Sara Hannegan (2519) Date: 2024.08.16 15:01:28 - 08'00' Sara Hannegan (2519) Page 2 of 5 Administrative Approval Request Well: NS20 PTD: 202-188 Northstar Well NS20 Technical Justiﬁcation for Administrative Approval Request 8/16/2024 Well History and Status NS20 was an Ivishak producer drilled and completed in 2002. An outer annulus (OA) down squeeze was performed in 2005 in attempt to remediate an IA by OA communication. This communication was believed to be occurring at a casing joint at 1071’ MD based on drilling operations. The well was shut in in April of 2019 for an uncompetitive GOR. In August of 2023, the well was converted from an Ivishak producer to a Kuparuk producer by setting a plug to isolate the Ivishak. The well was also uncompetitive in the Kuparuk. NS20 is a good candidate for converting to a water injector for pressure support in the Northstar Kuparuk oil pool. Please see water injection conversion sundry application submitted on 8/16/2024 for additional information and context. Recent Week Events 3/3/2024 Pull live gaslift valves, set dummy gaslift valves 1/19/2024 Kuparuk SBHPS, Pull temporary plug 1/17/2024 Set temporary plug in attempt to perform water shut oƯ 11/25/2023 Set live gaslift valve design 11/21/2023 MIT-IA pass to 3275psi under sundry 323-602 for gaslift injection 9/11/2023 Perforate Kuparuk under sundry 323-374 8/27/2023 CMIT-IA passed to 2540psi under sundry 323-374 for Kuparuk conversion 8/13/2023 Pump cement packer into IA 7/28/2023 Punch tubing in preparation for cement placement 7/19/2023 Set composite plug in preparation for cement placement 7/18/2023 Ivishak SBHPS Barrier and Hazard Evaluation The primary and secondary barrier systems consist of the 3-1/2” tubing and 9-5/8” production casing and associated hardware. A passing pressure test of the inner annulus to 3275psi on 11/21/2023, which tests both barriers, demonstrates competent primary and secondary barrier systems. No further diagnostics or repair attempts are proposed at this time. The annuli well pressure transmitters are set to alert the board operator with audio and visual warnings via the SCADA system if the annuli pressures exceed the high and high-high alarm set points. Logic will be placed into the SCADA system to shut the well in during a high-high pressure event on either the IA or OA. The well annuli pressure alerts are set as follows: Annulus High High-High (MOASP) IA 1000 2000 OA 500 1000 Pressure on the outer annulus will be maintained below MOASP of 1000 psi when the well is online with periodic bleeds of the OA. Page 3 of 5 Administrative Approval Request Well: NS20 PTD: 202-188 Proposed Operating and Monitoring Plan 1. Record wellhead pressures and injection rate daily. 2. Submit a report monthly of well pressures, injection rates and bleeds to the AOGCC. 3. Perform a MIT-IA every 2 years to the greater of the maximum anticipated injection pressure or 0.25 x packer TVD, but not less than 1500 psi. a. Sundry 323-374 required a CMIT-IA and MIT-T. The CMIT-IA was selected over a MIT- IA for operational reasons when performing the mechanical integrity tests. However, as an injector, it makes more sense to perform the MIT-T and MIT-IA separately. 4. Perform a MIT-T every 2 years to the greater of the maximum anticipated injection pressure or 0.25 x packer TVD, but not less than 1500 psi. a. MIT-T will test production tubing between top of cement and top Kuparuk perforation, the area not monitorable by an MIT-IA. 5. Perform a static bottom hole pressure survey (SBHPS) every 2 years to observe for any increases in bottom hole pressure that could indicate communication with formations other than the Kuparuk. a. Kuparuk pressures are expected to remain below Ivishak pressures due to under injection of the Kuparuk and pressure maintenance of the Ivishak. i. Ivishak pressure is ±5,160psi @ 11,100’ TVD (NS20 SBHPS 7/18/2023) ii. Kuparuk pressure is ±2,760psi @ 9,000’ TVD (NS20 SBHPS 1/19/2024) b. The cement in the tubing prevents a water ﬂow logging tool string from getting below the depths of interest for conﬁrmation of formation isolation. Thus, a water ﬂow log or temperature survey cannot conﬁrm zonal conformance and is not applicable. 6. IA MOASP= 2000 psi, OA MOASP= 1000 psi with audible control room alerts set at or below these limits. a. SCADA well shut in logic will be put in place at or below these limits. 7. IA and OA pressures will be monitored with pressure gauges through SCADA system. 8. The well will be shut-in and the AOGCC notified if there is any change in the wells mechanical condition. 9. After well shut-in due to a change in the well’s mechanical condition, AOGCC approval shall be required to restart injection. A production tubing caliper was run in 2023 and indicated minimal damage. The production tubing is a corrosion resistant chrome alloy. Based on the longevity of chrome tubulars, repeating tubing calipers is of little value and not included in this monitoring plan. Page 4 of 5 Administrative Approval Request Well: NS20 PTD: 202-188 TIO Plot Shut in, IA below OA, no bleeds Gas lift applied to IA, bleeds of OA Kuparuk Recomplete IA bled, OA slowly tracks, no OA bleeds IA above OA, OA bleeds _____________________________________________________________________________________ Page 5 of 5 Current SchemaƟc Northstar Unit Well: NS-20 Last Completed: 6/03/2003 PTD: 202-188 CASING DETAIL Size Type Wt/ Grade/ Conn DriŌ ID Top Btm 13-3/8"Surface 68 / L-80 / Btrc.12.415 Surf 4,151’ 9-5/8"ProducƟon 47 / L-80 / Btrc.8.525 Surf 16,424’ 7"Liner 26 / L-80 / Hyd. 521 6.276 15,290’18,194’ 4-1/2”Liner 12.6 / 13Cr80 / Vam Ace 3.958 17,978 18,530’ TUBING DETAIL 3-1/2”Tubing 9.2 / 13Cr80 / Vam Ace 2.992 Surf 17,986’ JEWELRY DETAIL No Depth Item 1 1,005’3-1/2” TRM-4E SSSV w/ X Proﬁle, ID=2.812” 2 6,599’ST 2:Port= 16, Dev=61, VLV= BK-DGLV, TVD= 4,493’ (set 2-29-24) 3 10,748’ST 1:Port= 24, Dev=62, VLV= BK-DGLV, TVD= 6,496’ (set 3-3-2024) 4 15,290’9-5/8”X7” Baker Liner Top Packer 5 17,450’3-1/2” Fiber OpƟc Flowmeter (2.797” ID) 6 17,864’5’ of tubing punch holes 7 17,873’3-1/2” Fiber OpƟc Flowmeter (2.797” ID) 8 17,878’3-1/2” Fiber OpƟc Flowmeter (2.797” ID) 9 17,911’Composite Bridge Plug set 7/19/2023 10 17,912’3-1/2” HES X NIP, ID = 2.75” 11 17,934’7”x4-1/2” PKR, ID 3.875” 12 17,960’3-1/2” HES X NIP, ID = 2.75” 13 17,971’3-1/2” HES XN NIP, ID = 2.635” 14 17,978’7”x5” Baker ZXP Liner Top Packer, ID = 4.390” 15 17,986’4-1/2” Self-Aligning WLEG, ID = 3.958” 16 18,000’7”x5” Baker Liner Hanger, ID = 4.390” 17 18,009’5”x4-1/2” XO, ID = 3.910” PERFORATION DETAIL Top (MD)Btm (MD)Top (TVD)Btm (TVD)FT Date Status 15,903 15,916 9,068 9,074 13’9/11/23 Open 15,980 15,993 9,108 9,115 13’9/11/23 Open 18,410 18,444 11,012 11,040 34’3/16/14 Closed 18,420 18,451 11,020 11,046 31’1/30/10 Closed 18,449 18,480 11,044 11,070 31’1/28/10 Closed 18,450 18,469 11,045 11,061 19’8/02/03 Closed 18,471 18,490 11,063 11,078 19’8/01/03 Closed 18,491 18,510 11,079 11,095 19’7/26/03 Closed OPEN HOLE / CEMENT DETAIL 13-3/8"552 BBL CMT in 16” Hole 9-5/8"769 BBL CMT in 12-1/4” Hole 7”41.5 BBL CMT in 8-1/2” x 9” Hole 4-1/2”25 BBLS CMT in 6-1/8” Hole WELL INCLINATION DETAIL KOP @ 545’ Max Hole Angle = 63° @ 10,180’ TREE & WELLHEAD Tree ABB-VGI 5-1/8” 6,500# Wellhead ABB-VGI 13-5/8” MulƟbowl 6,500# GENERAL WELL INFO API: 50-029-23118-00 Completed – 6/03/2003 Kuparuk Recomplete – 9/11/2023 4 Hilcorp Alaska, LLC Sara Hannegan, AKI Operations Manager 3800 Centerpoint Dr, Suite 1400 Anchorage, Alaska 99503 09/27/2023 Chairman Brett Huber, Sr. Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 RE: Application for Amendment to Area Injection Order 41, Rule 3 to authorize water as an approved injection fluid for the Northstar-Kuparuk Oil Pool. Dear Chairman Huber, Hilcorp Alaska, LLC (Hilcorp) requests administrative approval to allow injection of water into the Northstar-Kuparuk Oil Pool to enhance recovery. Hilcorp submits that the requested water injection will not cause waste or damage to the Northstar- Kuparuk Oil Pool and the injection volumes can be properly allocated. Hilcorp therefore requests amendment to AIO 41 Rule 3 to include water as an authorized injection fluid. Enclosed in this letter is additional information supporting this application. If the commission has questions or desires more information please contact me at 907-309-1196. Sincerely, Sara Hannegan Alaska Islands OperaƟons Manager By Samantha Carlisle at 9:34 am, Sep 28, 2023 Digitally signed by Sara Hannegan (2519) DN: cn=Sara Hannegan (2519) Date: 2023.09.27 15:23:10 - 08'00' Sara Hannegan (2519) Additional Information in Support of Application Introduction Production from the Northstar Unit does not yield enough produced gas to balance reservoir voidage in both the Ivishak Oil Pool and the Kuparuk Oil Pool simultaneously. The current injection management strategy involves maintaining a stable reservoir pressure in the Ivishak Oil Pool, above bubble point and miscibility pressure. To achieve this strategy, the Ivishak Oil Pool receives enough gas to match voidage, and the remaining produced gas is injected into the Kuparuk Oil Pool. The volume of gas entering the Kuparuk Oil Pool does not match voidage, and as such, the pressure in the Kuparuk Oil Pool has declined from over 4000 psi to under 3000 psi. Declining reservoir pressure in the Kuparuk Oil Pool will result in lower liquid recovery. Currently the Northstar Unit processes approximately 14,000 bwpd from the Ivishak Oil Pool and Kuparuk Oil Pool combined. Water production is expected to increase as these oil pools mature and the aquifer continues to encroach. Produced water is disposed of in one of two disposal wells, NS-10 or NS-32, injecting into the Schrader Bluff Formation. Hilcorp would like to repurpose this disposal water as pressure maintenance and enhanced recovery water injection in the Kuparuk Oil Pool. Applicable Area Injection Order (AIO): AIO 41 Rule 3 Authorized Fluids for Injection for Enhanced Recovery Fluids authorized for injection are: a. Produced gas from the NU; b. Tracer survey fluids to monitor reservoir performance; c. Fluids used to improve near wellbore injectivity; d. Fluids used to seal wellbore intervals which negatively impact recovery efficiency; e. Fluids associated with freeze protection; and f. Standard oilfield chemicals. AIO 41 Northstar Unit, Rule 10 authorizes the AOGCC to administratively waive the requirement of any rule stated within AIO 41 or to administratively amend AIO 41 so 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. The proposed change is to amend AIO 41 Rule 3 to include water as an approved injection fluid. Proposed Amendments to Area Injection Orders and Conservation Orders AIO 41 Rule 3 Authorized Fluids for Injection for Enhanced Recovery Fluids authorized for injection are: a. Produced gas from the NU; b. Tracer survey fluids to monitor reservoir performance; c. Fluids used to improve near wellbore injectivity; d. Fluids used to seal wellbore intervals which negatively impact recovery efficiency; e. Fluids associated with freeze protection; and f. Standard oilfield chemicals. g. Water Appendix 1: Northstar-Kuparuk Water InjecƟon Metering and Allocation The primary water injection pumps at Northstar have an orifice style master meter downstream of the pump discharge. Disposal well NS-32 has a sonic meter attached to its flowline. The two injection disposal wells, NS-10 and NS-32 are then allocated by difference by comparing NS-32’s sonic meter to the master meter and allocating the difference to NS-10 when both wells are on injection. Under normal operating conditions NS-10 and NS-32 are rarely online at the same time, allowing rate off of the master meter to be the directly allocated rate. For any additional water injection wells, a sonic meter or similar will be installed on each additional flowline. A similar process will be used for allocation purposes, comparing aggragate individual well meters metered rate against the master meter. Under normal conditions, Kuparuk injection wells are expected to take the majority of the injection rate allowing for all injection to be metered. Under abnormal conditions, in events when NS-10 is needed for injection, the difference of aggrigate individual well meters versus the master meter will allocate remaining rate to NS-10. Injection Pressure 1. Northstar Unit AIO 41 Rule 4 states that injection pressures will be managed so as not to exceed the maximum injection gradient of 0.79 psi/ft to ensure containment of injection fluids within the defined affected area and injection interval. 2. If approved as an authorized injection fluid, water injection into the Kuparuk Oil Pool will comply with AIO 41 Rule 4. Water Injection Wells 1. Northstar Unit AIO 41 Rule 2 authorizes injection through existing wells that AOGCC has approved for conversion to a service well for injection in conformance with 20 AAC 25.280. 2. An application for Sundry Approval (Form 10-403) must be approved by the AOGCC for each well prior to commencement of water injection. Field Trial Hilcorp requested and received approval for a limited water injection field trial in Northstar Kuparuk well NS-15 in May of 2023. The injection field trial was performed between 07/22/2023 and 07/25/2023 and included multiple injection pressure steps to monitor injectivity. The target steps were 1600 psi, 2000 psi, and 2400 psi. Results are shown below: Injection pressure was held stable for a period of hours at each step to verify injectivity remained constant. The total volume of water injected was approximately 29,900 bls over 2.5 days. Injection Well Placement The Kuparuk Oil Pool accumulation is a gas condensate reservoir with an oil rim of varying thickness. Multiple Ivishak Oil Pool producers penetrate the Kuparuk Oil Pool below or near the oil/water contact and would be in a suitable location for downdip water injection. Several of these producers are at the marginal Injection Pressure (psi) Injection Rate (bwpd) 1618 9,143 1947 12,259 2135* 14,294* * NS-15 was able to inject all available water before reaching 2400 psi injection pressure GOR for the Northstar Unit and under normal operating conditions only cycle on for a limited time during the winter months. Two have been Long Term Shut In (LTSI) for multiple years and are not expected to be competitive producers in the Ivishak Oil Pool again. Long Term Water Injection Imapact The current reservoir management strategy prioritizes the Ivishak Oil Pool resulting in a Voidage Replacement Ratio (VRR) of approxiamtely 0.82 in the Kuparuk Oil Pool. Injecting an additional 14,000 barrels of water into the Kupark Oil Pool would increase the VRR to approximately 0.92. Dynamic reservoir simulation of the Kupark Oil Pool shows an increase in average reservoir pressure of approximately 180 psi by 2030 when compared to a base case withouth water injection. The producing facility at Northstar Unit is capable of processing 30 mbwpd and is currently operating at less than 50% capacity leaving excess capacity to handle potential breakthrough from water injection. Conclusion Hilcorp requests that water be added to the authorized injection fluids list per AIO 41 Rule 3. Water injection in the Kuparuk Oil Pool will help slow reservoir pressure decline and enhance recovery without jeopradizing the injection management strategy that prioritizes the Ivishak Oil Pool. 3 AOGCC 9/6/2018 ITMO: APPLICATION OF HILCORP AK... ALASKA OIL AND GAS CONSERVATION COMMISSION In the Matter of the Application of Hilcorp ) Alaska, LLC for an Area Injection Order ) to Authorize a Lean Gas Enhanced Recovery ) Injection Project in the North Star/Kuparuk ) Oil Pool in the North Star Unit, North ) Slope, Alaska. ) Docket No.: AIO 18-032 PUBLIC HEARING September 6, 2018 2:00 o'clock p.m. Alaska OiL and Gas Conservation Commission Hearing Room 333 W. 7th Avenue Anchorage, Alaska BEFORE COMMISSIONERS: Hollis French, Chair Cathy Foerster Daniel T. Seamount Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 9/6/2018 ITMO: APPLICATION OF HILCORP AK... Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 2 1 TABLE OF CONTENTS 2 Opening remarks by Chairman French 03 3 Remarks by Mr. Shine 10 4 Remarks by Mr. Kanyer 14 5 Remarks by Mr. Yancey 17 6 Remarks by Ms. Rivard 18 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 9/6/2018 ITMO: APPLICATION OF HILCORP AK... Page 3 1 P R O C E E D I N G S 2 (On record - 2:04 p.m.) 3 CHAIRMAN FRENCH: Let's go ahead and get 4 started. It's about 2:04 in the afternoon of September 5 6th, 2018. We're here at 333 West Seventh Avenue in 6 Anchorage, Alaska, the headquarters of the Alaska Oil 7 and Gas Conservation Commission. To my right is 8 Commissioner Cathy Foerster, to my left is Commissioner 9 Dan Seamount, I'm Hollis French, the Chair of the 10 Commission. 11 We're here today on docket number AIO 18-032, 12 pertaining to the North Star/Kuparuk oil pool in the 13 North Star unit and its application for an injection 14 order. Just a quick clarification, the public notice 15 that went out erroneously stated that this was CO -18- 16 032. It's not a conservation order proceeding, as 17 stated above it's an AIO 18-032. 18 Hilcorp Alaska, LLC by its application dated 19 July 18, 2018, requests that the Alaska Oil and Gas 20 Conservation Commission issue an area injection order 21 to authorize a lean gas enhanced recovery injection 22 project in the North Star/Kuparuk oil pool in the North 23 Star unit. 24 Samantha Carlisle will be recording today's 25 proceedings. You can get a copy of the transcript from Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 9/6/2018 ITMO: APPLICATION OF HII,CORP AK... Page 4 1 Computer Matrix Reporting once we send it over to them 2 for transcription. 3 Hilcorp is here to testify. Is there anybody 4 else planning to testify today besides Hilcorp 5 employees? 6 (No comments) 7 CHAIRMAN FRENCH: I don't hear or see anyone. 8 So with that I'll just let you know that as usual we'll 9 be asking the questions during the testimony, we may 10 take a recess to consult with staff if additional 11 information or clarifying questions are necessary. 12 Keep in mind as you testify that you must speak into 13 the microphone, check and see that the green light is 14 on so that those in the audience and the court reporter 15 can hear your testimony. Remember to reference your 16 slides so that someone reading the public record can 17 follow along. For example refer to slides by their 18 number if numbered or by their titles if not numbered. 19 of course keep your testimony on point to the AIO 20 requested today and don't testify in the form of cross 21 examination. 22 Commissioners Foerster or Seamount, anything to 23 add? 24 COMMISSIONER FOERSTER: I have a question. We 25 have someone in the audience who says he's from BHGE Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 9/6/2018 ITMO: APPLICATION OF HILCORP AK... Page 5 1 and I'm wondering what BHGE stands for. 2 UNIDENTIFIED VOICE: (Indiscernible - away from 3 microphone)..... 4 COMMISSIONER FOERSTER: Oh, okay. 5 CHAIRMAN FRENCH: Thank you. Welcome to the 6 hearing. So let's go ahead and have the Hilcorp 7 witnesses come forward, I'll swear you all in at once 8 and then when you introduce yourselves you can let us 9 know if you want to be recognized as an expert and if 10 so in which specific discipline or area. 11 So, gentlemen, if you'd all raise your right 12 hands. 13 (Oath administered) 14 IN UNISON: I do. 15 CHAIRMAN FRENCH: Excellent. You can -- you 16 can -- why don't we just go left to right for 17 introductions and then we'll -- then we'll go from 18 there. 19 MR. KANYER: I am Chris Kanyer, I'm a reservoir 20 engineer for Hilcorp. I am with Hilcorp for the last 21 six and half years as a reservoir engineer. And I 22 worked at North Star as a reservoir engineer for the 23 last three and a half years. 24 MR. YANCEY: My name is Daniel Yancey, I'm a 25 geoscientist and I work Endicott and North Star. I've Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 9/6/2018 ITMO: APPLICATION OF HII,CORP AK... Page 6 1 been with Hilcorp for just about four years. Prior to 2 that I worked with EP from 2006 to 2014. 3 MR. SHINE: Good afternoon. My name is Jim 4 Shine. I'm a landsman with Hilcorp and I work on the 5 North Slope asset team. 6 MR. RIVARD: My name's Wyatt Rivard, I'm the 7 well integrity engineer for the North Slope team. And 8 I've been a well integrity engineer for four years with 9 Hilcorp and then five years as a Schlumberger wireline 10 field engineer prior to that. 11 CHAIRMAN FRENCH: Great. And who is going to 12 start off? 13 COMMISSIONER SEAMOUNT: I would like to ask for 14 your educational backgrounds. 15 COMMISSIONER FOERSTER: Well, they're not 16 asking to be recognized as experts just yet. 17 COMMISSIONER SEAMOUNT: Oh, they're not? 18 COMMISSIONER FOERSTER: No. 19 COMMISSIONER SEAMOUNT: Okay. Sorry. 20 CHAIRMAN FRENCH: Although it's likely to 21 happen. Who wants to be an expert? Okay. Let's go 22 left to right. Mr. Kanyer, tell us about your -- is it 23 reservoir engineering that you want to be so 24 designated? 25 MR. KANYER: That's correct. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 9/6/2018 ITMO: APPLICATION OF HILCORP AK... Page 7 1 CHAIRMAN FRENCH: Tell us about -- tell us 2 about your education. 3 MR. KANYER: I have -- my education background. 4 I have a bachelor's and master's degree in mathematics 5 from Washington State University, I also have a 6 master's in petroleum engineering from University of 7 Alaska Fairbanks. And I've had 11 years of oil and gas 8 experience and six and a half as a reservoir engineer. 9 COMMISSIONER FOERSTER: What were the first 10 five? 11 MR. KANYER: Different backgrounds of 12 operations engineering, also as a regulatory tech under 13 Chevron. And I also worked for Halliburton in an 14 accounting and procurement position for a short period 15 of time. 16 CHAIRMAN FRENCH: Did I count correctly, you 17 have two bachelor's and two master's? 18 MR. KANYER: I have one bachelor's in 19 mathematics and two master's, one in mathematics and 20 one in petroleum engineering. 21 CHAIRMAN FRENCH: I see. Any objection from 22 the Commission on Mr. Kanyer's being recognized as a 23 reservoir engineer? 24 COMMISSIONER FOERSTER: How many total years of 25 reservoir engineering do you have? Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email sahile@gci.net AOGCC 9/6/2018 ITMO: APPLICATION OF HILCORP AK... 1 MR. KANYER: Six and a half. 2 COMMISSIONER FOERSTER: You okay with that? 3 COMMISSIONER SEAMOUNT: I'm fine. No 4 objection. 5 COMMISSIONER FOERSTER: Okay. 6 CHAIRMAN FRENCH: No objection. Mr. Yancey. 7 MR. YANCEY: Yes, this is Daniel Yancey. My 8 education, I have a bachelor's degree in geoscience 9 from Virginia Tech along with a minor in mathematics. 10 I also have a master's degree in geoscience with a 11 concentration in geophysics from Virginia Tech. I have 12 been in the oil and gas industry for just over 12 13 years. Part of that was with BP up here and in 14 Houston, but the vast majority of my career has been 15 here. 16 CHAIRMAN FRENCH: And were your job duties in 17 the geoscience area? 18 MR. YANCEY: Correct. 19 CHAIRMAN FRENCH: Okay. Excellent. Any 20 objection to finding Mr. Yancey an expert in 21 geoscience? 22 COMMISSIONER FOERSTER: No. 23 COMMISSIONER SEAMOUNT: No objection. 24 CHAIRMAN FRENCH: You shall be so deemed. Yes, 25 sir. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 9/6/2018 ITMO: APPLICATION OF HILCORP AK... Page 9 1 MR. RIVARD: So Wyatt Rivard. I have a 2 bachelor's in aerospace engineering from Embry -Riddle 3 Aeronautical University. So four years with Hilcorp 4 and five years with Schlumberger so nine years of 5 industry experience. 6 CHAIRMAN FRENCH: And in what discipline or 7 field are you seeking to be an expert? 8 MR. RIVARD: Well, integrity. 9 CHAIRMAN FRENCH: Well, integrity. And how 10 much of your work -- I mean, is -- you work from being 11 an aerospace -- did you say aeroscience? 12 MR. RIVARD: Aerospace engineering. 13 CHAIRMAN FRENCH: How do those skills transfer 14 over to well integrity? 15 MR. RIVARD: It's metallurgy and fluid 16 dynamics, it's actually surprisingly similar. So and 17 then Schlumberger experience was downhole diagnostics 18 so just a lot of well intervention experience. 19 CHAIRMAN FRENCH: And how many years with 20 Schlumberger? 21 MR. RIVARD: Five years. 22 CHAIRMAN FRENCH: And how many now with 23 Hilcorp? 24 MR. RIVARD: Four. 25 CHAIRMAN FRENCH: And all in the same kind of Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahileCgci.net AOGCC 1 general discipline? 9/6/2018 ITMO: APPLICATION OF HILCORP AK... Page 10 2 MR. RIVARD: Reasonably, yeah. 3 CHAIRMAN FRENCH: Okay. I don't have any 4 objection. 5 COMMISSIONER FOERSTER: No. 6 COMMISSIONER SEAMOUNT: I know that's very 7 interesting. 8 CHAIRMAN FRENCH: You're a well completion 9 expert or well construction did you say or..... 10 MR. RIVARD: Well integrity. 11 COMMISSIONER FOERSTER: Well integrity. 12 CHAIRMAN FRENCH: Well integrity. Yeah, very 13 good. Well integrity. 14 COMMISSIONER FOERSTER: It doesn't quite sound 15 as sexy as rocket scientist though. 16 CHAIRMAN FRENCH: Who wants to lead off? 17 MR. SHINE: I will. 18 CHAIRMAN FRENCH: Mr. Shine. Welcome. 19 JIM SHINE 20 previously sworn, called as a witness on behalf of 21 Hilcorp Alaska, LLC, testified as follows on: 22 DIRECT EXAMINATION 23 MR. SHINE: Thank you. Thank you, Mr. 24 Chairman, and Commissioners Seamount and Foerster. For 25 the record my name is Jim Shine, I'm a landsman with Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gei.net AOGCC 9/6/2018 ITMO: APPLICATION OF HILCORP AK... Page 11 1 Hilcorp Alaska here in Anchorage. And as a preliminary 2 matter we'd like to request that our PowerPoint 3 presentation and the testimony you're about to receive 4 on our AIO application be considered part of our -- 5 part of the record and included in our application to 6 the Commission. 7 Moving to slide two here is -- we've already 8 gone through introduction of the panel here. I'll do a 9 brief overview of some of the preliminary matters. Our 10 application to the Commission was -- did not contain 11 any confidential information nor will our presentation. 12 And as another preliminary matter the surface owners 13 adjacent to the North Star unit includes the State of 14 Alaska and the federal government and we provided 15 notice as required by AOGCC regulations, provided 16 notice -- hard copies of this application to both 17 agencies. 18 The AIO that is before the Commission is 19 intended to enhance recovery in Kuparuk oil pool in the 20 North Star unit, prevent economic and physical waste 21 and improve the overall recovery of hydrocarbons in the 22 North Star/Kuparuk oil pool. 23 Moving on to slide three is a map showing the 24 location of the North Star unit in the innershore state 25 waters and the Beaufort Sea and the federal OCS waters. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 9/6/2018 ITMO: APPLICATION OF HILCORP AK... Page 12 1 The blown up map will show you an actual -- the red 2 outline is the outline of the North Star unit comprised 3 of four state leases and three federal OCS leases. The 4 area injection order area that is before the Commission 5 right now is wholly contained within the North Star 6 unit and is actually the exact same area as the 7 Hooligan participating area which you can see in the -- 8 which is the kind of orange crosshatched area in the 9 blown up map down there on the lower left. 10 CHAIRMAN FRENCH: Mr. Shine, I have a question 11 just about the lower left-hand sort of blowup of the 12 bigger scale map. Where is the actual North Star sort 13 of, you know, installation..... 14 MR. SHINE: The..... 15 CHAIRMAN FRENCH: .....on that lower left-hand 16 side, it looks..... 17 MR. SHINE: I think the North Star island you 18 can see is a very small dot right -- yeah, that's 19 exactly where it's located. 20 CHAIRMAN FRENCH: It says North Star on it? 21 MR. SHINE: Yeah. 22 CHAIRMAN FRENCH: Okay. That's it. Yep, very 23 good. Thank you. 24 MR SHINE: Yeah. Moving on to slide four. The 25 North Star unit is whole -- is 100 percent owned by Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 9/6/2018 ITMO: APPLICATION OF HILCORP AK... Page 13 1 Hilcorp and Hilcorp as the operator. The unit was 2 formed in 1990 and as I mentioned it's a co -managed 3 unit between the Alaska Department of Natural 4 Resources, Division of Oil and Gas, and the Federal 5 Bureau of Safety and Environmental Enforcement. The 6 seven leases contained within the unit encompass 20,134 7 acres. There are three actively -- active unit 8 participating areas, The North Star PA, the Fido PA 9 which is in the far eastern edge of the unit and then 10 the Hooligan PA which contains about roughly 7,500 11 acres. 12 And as I mentioned on the previous slide the 13 proposed affected area injection order area is 14 contained -- is wholly contained within the Hooligan PA 15 area. It's the same unit -- same boundary as the 16 Hooligan PA. 17 And with that I'd move to slide five and I 18 think Mr. Kanyer will address some more technical 19 information. 20 COMMISSIONER SEAMOUNT: Mr. Shine. 21 MR. SHINE: Yes, sir. 22 COMMISSIONER SEAMOUNT: What did you name it 23 the Hooligan PA? 24 MR. SHINE: Commissioner Seamount, that was -- 25 preceded my time at Hilcorp or I wasn't a BP employee Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 9/6/2018 ITMO: APPLICATION OF HILCORP AK... Page 14 1 at the time that was named, but I actually don't have a 2 good answer for why it's the Hooligan PA, drew a name 3 out of the hat. 4 COMMISSIONER SEAMOUNT: Sounds like some 5 Russians were involved. 6 COMMISSIONER FOERSTER: Or fishermen. 7 COMMISSIONER SEAMOUNT: Or fishermen. Yeah. 8 Oh, that's it. That'll work. 9 CHAIRMAN FRENCH: Mr. Kanyer. Welcome. 10 CHRIS KANYER 11 previously sworn, called as a witness on behalf of 12 Hilcorp Alaska, LLC, testified as follows on: 13 DIRECT EXAMINATION 14 MR. KANYER: I'll speak to slide number 5. So 15 just an overview of the field, a snapshot in time. The 16 field was discovered by the Shell Seal Island number 1 17 well in 1983. To date we have currently 30 wells on 18 the island, 20 are active producers or 20 are 19 producers, one of those is shut-in, seven are gas 20 injectors, one is shut-in, two disposal wells, one 21 suspended well. As you see the total production of 22 July, we produced roughly 175 million barrels to date. 23 You can see that's heavily dominated by the Ivishak at 24 over 170 million barrels, five of which are coming from 25 the Kuparuk reservoir. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 9/6/2018 ITMO: APPLICATION OF HILCORP AK... Page 15 1 As noted earlier there are two shut-in wells. 2 One is shut-in for integrity. That well is NS -24. NS - 3 25 is currently shut-in for reservoir management 4 purposes, trying to improve GOR in existing producers 5 as a current active Ivishak injector that is shut-in. 6 And then we have one well that is suspended, NS -26. 7 As I continue to look at slide number 6, here's 8 a field production history plot. We tried to annotate 9 some key events here in the initial development. You 10 can see in 2001 we began with Ivishak production, we 11 followed on through -- until 2008 when they drilled the 12 Fido prospect which is NS -34, sidetrack 34-A. That is 13 also in the Ivishak. Initial production from the 14 Kuparuk was from the Kuparuk C sand, NS -8, in August of 15 2010 followed by some more recent work. In August, 16 2016 we began producing the NS -18 in the Kuparuk A and 17 C sands and NS -15 last year in the Kuparuk A and C. As 18 of this last month, August, 2018, we've also added the 19 NS -13 well in the Kuparuk A sands. As you see on the 20 plot red is plotted for gas, water in blue, green is 21 oil. 22 CHAIRMAN FRENCH: So it looks like North Star's 23 making about 10,000 barrels a day, is that about right? 24 MR. KANYER: Correct. We have a seasonal 25 fluctuation due to warmer ambient temps we recover less Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2.,Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 9/6/2018 ITMO: APPLICATION OF HILCORP AK... Page 16 1 through the NGL recovery process in the summer. In the 2 wintertime we're averaging somewhere between 10 and 3 12,000 barrels a day, over the summer is now reaching 4 into the 8,000 barrels range. 5 COMMISSIONER SEAMOUNT: Doesn't look like 6 there's been much decline in 10 years. 7 MR. KANYER: Correct. Over the last several 8 years with the Kuparuk development that has improved 9 the field life and maintaining production as well as 10 the added gas from the Kuparuk has allowed us to 11 improve the recovery and the EOR project in Ivishak. 12 So that's the main -- the main purpose of the last four 13 years of flat -- flat production. 14 Moving on to slide seven, you see exhibit B, 15 the injection area plat. In the purple outline you see 16 Hooligan PA. This is a spider plot indicating the well 17 paths of the majority of the wells coming from the 18 North Star Island. We do have some expiration well 19 paths on here, but for our intents and purposes we have 20 the island here as I indicate in section 11, with the 21 wells spidering out. We have one well indicated which 22 we'll blowup in the next slide, that's NS -18. This is 23 our first proposed gas injection well for this EOR 24 project. Current production wells, we do have the NS -8 25 well which resides right here in the middle of section Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 9/6/2018 ITMO: APPLICATION OF HILCORP AK... Page 17 1 11 nearby the island. That is the first producer. As 2 I mentioned earlier we added the NS -15 well which is 3 here in section 10, followed by NS -13 here last month. 4 In 2016 we added NS -18 as our first Kuparuk A and C 5 producer out here in section three. 6 And as we move to slide 8 and focus in further, 7 this is a quarter mile dashed blue circle, the area of 8 review of this proposed injection well. And you can 9 see that this well is not nearby any existing well at 10 the top of the Kuparuk which is where the wells are 11 located by their well names. That's where the well 12 path crosses the Kuparuk so we don't have any well 13 within a quarter mile of the NS -18 well that penetrates 14 the Kuparuk. We have existing producers on here, NS -8 15 and NS -15. And you can see they're a section's width 16 or a mile away from the given injector that we're 17 proposing. 18 As we move forward I'm going to have Daniel 19 Yancey here talk a little bit more about the geology. 20 DANIEL YANCEY 21 previously sworn, called as a witness on behalf of 22 Hilcorp Alaska, LLC, testified as follows on: 23 DIRECT EXAMINATION 24 MR. YANCEY: This is Daniel Yancey, we're on 25 slide nine. Just to talk a little bit about the Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 9/6/2018 ITMO: APPLICATION OF HILCORP AK... Page 18 1 stratigraphy and how we define it. NS -15 is what we've 2 defined the pool based off of for the Kuparuk. It 3 consists of the A sands at the base and then also the C 4 sands. You see this in all of the wells. The A sands 5 tend to be a fairly consistent thickness, the C sands 6 vary. And the other important thing to talk about here 7 specifically are the confining layers since we're 8 talking about injection here. Above the Kuparuk there 9 is over 2,000 feet tvd of non -permeable shale composed 10 of the HRZ, the Colville as well. And below the A 11 sands there's over 1,500 feet of non -permeable shale, 12 the Kingak. Again this is just to stress the point of 13 the confining layers that we feel very comfortable with 14 above and below the Kuparuk section. 15 WYATT RIVARD 16 previously sworn, called as a witness on behalf of 17 Hilcorp Alaska, LLC, testified as follows on: 18 DIRECT EXAMINATION 19 MR. RIVARD: And this is Wyatt Rivard. I can 20 speak a little bit more to the fracture pressure 21 gradients out at North Star. On this slide, slide 10, 22 you can see the green line there is our observed 23 fracture pressure gradients we obtained from leak off 24 tests from a number of exploratory wells early on in 25 the field. For the Kuparuk down at 9,000 tvd we have a Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 9/6/2018 ITMO: APPLICATION OF HILCORP AK... Page 19 1 15.2 pound per gallon leak off test that was obtained 2 on the CLA-4 well. So that gives us a bottom hole 3 fracture pressure of roughly 7,200 psi. So if we work 4 our way back up to surface for a gas injector with a .1 5 psi per foot gradient that gives us a surface pressure 6 of about 6,300 psi. And why I say that is because our 7 current -- our gas injection system out at North Star 8 operates around 4,800 to 4,900 psi and the maximum that 9 it could possibly achieve if we're able to create 10 enough back pressure would be around 5,700 psi. So 11 with the system that we have right now there's really 12 no way that we could exceed that fracture pressure for 13 the shales around the Kuparuk. 14 CHAIRMAN FRENCH: And this 1,500 just comes 15 from the capacity of your compressors? 16 MR. RIVARD: Yes. Exactly. Exactly. And so 17 the system that currently feeds the Ivishak injectors 18 will be the same system that feeds the Kuparuk 19 injectors. 20 So then on the next slide, slide 11, just to go 21 into a little bit on the well construction for the NS - 22 18 well. This will be our first Kuparuk injection 23 well, but it's fairly comparable to the other wells 24 that we may one day convert if we wanted to do another 25 injection well out there. So it was originally Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 9/6/2018 ITMO: APPLICATION OF HILCORP AK... Page 20 1 completed as an Ivishak producer, we recompleted it as 2 a Kuparuk producer in 2016. The nine and five-eighths 3 production casing that we perforated to access the 4 Kuparuk, it's run down to 14,668 feet measured depth 5 with 400 -- 574 barrels of cement. We had an estimated 6 top of cement around 8,100 foot measured depth. So our 7 perforations into the Kuparuk, the top of those 8 perforations are at 14,202 feet. So we have a large 9 margin of good cement above those perforations. We did 10 run a bond log across that nine and five-eighths above 11 the perforations up to the packer or up to the tubing 12 tail I should say, so we were able to confirm at least 13 300 feet roughly of good cement there above the 14 perforation. 15 We did obtain an MITIA in August of 2016 to 16 3,100 psi to confirm that tubing that we installed, the 17 four and a half inch tubing, the packer and the 18 production casing. And when we go to apply for the 19 conversion 10.403 sundry we're going to have to request 20 a variance for that tubing packer to perforation 21 distance, it's at 328 feet so it's a little in excess 22 of the 200 feet. So we'll be requesting that. We'll 23 also be conducting our MITIAs as per 20 AAC 25.402 and 24 the 10.02(a) guidance bulletins both for the initial 25 MIT and for the four year follow-up MITs. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net 9/6/2018 ITMO: APPLICATION OF HILCORP AK... Page 21 1 MR. KANYER: This is Chris Kanyer again, I'm 2 going to be going over slide 12. Just as a baseline I 3 put in this slide what the conservation order 739, the 4 Kuparuk oil pool rules, states as the in place volumes, 5 the original gas in place between 500 and 550 bcf with 6 original oil in place 22 to 25 million barrels with 7 primary coverage somewhere roughly around 40 percent. 8 We do assume that these volumes are fairly accurate 9 today. The gas in place volumes are very close to what 10 we would assume since we proposed the pool rules two 11 years ago, the original oil in place may be revised 12 upwards given our GOR response today, there might be 13 slightly additional oil in the recovery of this pool. 14 But for the intents and purposes of two years ago to 15 today, there hasn't been a great revision in structure, 16 reservoir volume or the in place volumes. 17 As we move on to slide 13 which is our last 18 prepared slide pending any other further questions. 19 This is the result of the geologically interpreted 20 compositional model. Two years ago we -- we started 21 with a compositional model, we had one well and we 22 tried to understand what was in place regarding that. 23 In the last two years we brought on two additional 24 producers, the NS -18 and NS -15 wells to grain a little 25 bit more understanding of tank size, continuity and Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 9/6/2018 ITMO: APPLICATION OF HILCORP AK... Page 22 1 just connectivity between the wells, faults, 2 transmissibility among many other things. We found 3 that we have a very good match on this new model. We 4 took the compositional model (indiscernible) with the 5 geologic interpretation and we found that we have a 6 very good match on bottom hole pressure and GOR through 7 time up until day. As you see the green dots here are 8 actuals on this cumulative production of oil through 9 time. This is our cum oil through time. We have a 10 good bottom hole pressure and GOR match up through 11 today. I have three projected lines here. The first 12 line is the red dashed line. This would say that this 13 is our current path on depletion without our EOR 14 project. I have a green wedge in here indicating that 15 the wells themselves will start beginning having 16 lifting issues due to tubing size and gas lift design. 17 So additional production is likely possible 18 given well intervention, but with the scenario two in 19 pink being a 50,000 a day gas injection rate into NS -18 20 or scenario three which is this brownish dashed colored 21 being a 80 million a day gas injection rate in NS -18, 22 we do see significant recoveries. In our 50 million 23 case we see roughly a 4 million barrel recovery gain 24 over the initial expected nine. With 80 million we 25 have five and a half. We range 50 to 80 here given the Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 9/6/2018 ITMO: APPLICATION OF HILCORP AK... Page 23 1 unknown of how much gas injection NS -18 will be taking. 2 we do have the excess capacity of gas supply given the 3 Ivishak is fully supported with the gas production of 4 the Kuparuk wells 18 and 15. With the results of 15 -- 5 NS -15 last year we do have an excess supply of gas 6 which we can now begin to recycle into the Kuparuk and 7 provide this beneficial recovery of the Kuparuk. Today 8 we do see in the order of 80 to 100 million a day of 9 excess gas possible. And I'm assuming that NS -18 will 10 roughly take roughly 65 million, somewhere right in 11 that range. 12 To provide a bit of an idea of additional 13 recovery in a range of possibilities I've provided the 14 two scenarios below. The possibility of adding 15 additional gas injection is likely and it depends on 16 the results of the initial injector, how much gas it 17 can take. We do see the benefit of the excess gas 18 being recycled into the Kuparuk and as you noticed that 19 these curves do not need artificial lift necessary, 20 they continue to produce. The bottom hole pressure 21 support by the gas injection does keep the wells on 22 longer, it does improve the recovery of each of the 23 wells that are existing in the field. 24 With that we don't have any additional slides, 25 but we're happy to answer more questions. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 9/6/2018 ITMO: APPLICATION OF HILCORP AK... Page 24 1 COMMISSIONER SEAMOUNT: I have a question. 2 This question's for Mr. Yancey. Can we go back to 3 slide number 9. On that stratigraphic cross section on 4 the left, where would you place the Kuparuk field with 5 regard to the Kuparuk -- I mean, the North Star field 6 with regard to the Kuparuk? 7 MR. YANCEY: So the Kuparuk C is located right 8 here in that stratigraphic cross section and the A is 9 here. 10 COMMISSIONER SEAMOUNT: So it's right in the 11 middle. And do you have -- you don't have any HRZ here 12 do you? 13 MR. YANCEY: We do. 14 COMMISSIONER SEAMOUNT: Oh, you do? 15 MR. YANCEY: Yes, sir. 16 COMMISSIONER SEAMOUNT: Okay. I don't see it 17 on the log, but must be up higher. 18 MR. YANCEY: It's above here..... 19 COMMISSIONER SEAMOUNT: Okay. 20 MR. YANCEY: .....but it is noted on this -- 21 this strat chart over here. This is just the very 22 beginning of the shale above and the same thing below, 23 but, yes, we do have HRZ here. 24 COMMISSIONER SEAMOUNT: As an interesting 25 aside, if you take a log from the Cretaceous section in Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 9/6/2018 ITMO: APPLICATION OF HILCORP AK... Page 25 1 the Rockies and compare it to the North Slope they're 2 pretty similar. As a Cretaceous seaway, I guess. 3 MR. YANCEY: Uh-huh. 4 COMMISSIONER SEAMOUNT: That's all I have. 5 COMMISSIONER FOERSTER: I don't have any 6 questions. 7 CHAIRMAN FRENCH: Commissioner Foerster, no 8 questions. I'm looking at staff to see if there's any 9 need to take a break and huddle up? 10 (No comments) 11 CHAIRMAN FRENCH: I'm getting the sense that we 12 don't have to. 13 Gentlemen, thanks for your presentation. We'll 14 take this matter under advisement, get an order to you 15 soon I would imagine. 16 And with that we're going to be adjourned at 17 about 2:33. Have a good afternoon. 18 (Hearing adjourned 2:33 p.m.) 19 (END OF REQUESTED PORTION) 20 21 22 23 24 25 Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 9/6/2018 ITMO: APPLICATION OF HILCORP AK... Page 261 1 C E R T I F I C A T E 2 UNITED STATES OF AMERICA ) )ss 3 STATE OF ALASKA ) 4 I, Salena A. Hile, Notary Public in and for the 5 State of Alaska, residing in Anchorage in said state, 6 do hereby certify that the foregoing matter in Docket 7 No.: AIO 18-032 was transcribed to the best of our 8 ability; 9 IN WITNESS WHEREOF I have hereunto set my hand 10 and affixed my seal this 19th day of September 2018. 11 12 Salena A. Hile 13 Notary Public, State of Alaska My Commission Expires: 09/16/2022 14 15 16 17 18 19 20 21 22 23 24 25 Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Docket Numbers: AIO-18-032 Northstar-Kuparuk Oil Pool, Northstar Unit Application for Area Injection Order September 6, 2018 at 2:00 pm NAME AFFILIATION Testify (Yes or no) �gvn i)AYLCUV:5S oAtG�r L tib P �IIIM S14Ioe IIII Chr'�s fonuor H; �ca�o ue5 w -� �,�� it 112 Ye o FAIJ\cures Mr�G,a el K� �oGCC No 6 bk (a',gad � 46C ivo N, Northstar Unit Presentation in Support of Proposed Kuparuk Oil Pool Area Injection Order ("AIO") Docket CO -18-032 September 6, 2018 Integrity * Urgency * Ownership * Alignment * Innovation 1 Introductions • Jim Shine, Landman, Hilcorp Alaska, LLC • Chris Kanyer, Reservoir Engineer, Hilcorp Alaska, LLC • Daniel Yancey, Geoscientist, Hilcorp Alaska, LLC • Wyatt Rivard, Well Integrity Engineer, Hilcorp Alaska, LLC Agenda • Confidentiality Issues: None • Request to recognize Mr. Kanyer, Mr. Yancey, & Mr. Rivard as Experts • Land & Ownership Review • Summary of Request & Technical Presentation • O&A oil Field Overview / Kuparuk Oil Pool Area 0 5 io tY Kuparuk Oil Pool Area • Northstar Unit was formed in 1990 • Unit is co -managed by the Alaska DNR and federal Bureau of Safety and Environmental Enforcement (BSEE) 11 NONMSTARNNOANOMPTIUPATIN MM Ib...b,A tplWNu ' • Unit is comprised of 20,134 acres. l • There are 4 state oil & gas leases and 3 federal OCS - - leases. (9,840 acres are federal). ___... mx wwvxn.wwu.. : +cuax FZ . rxiw..uoas • There are currently three unit participating areas • Northstar PA • Fido PA (entirely federal) • Hooligan PA (7,656 acres; 3.3% federal) ,yam,., • Comprised of Kuparuk A& C sands • Hilcorp proposes the affected area of the Kuparuk Oil Pool AIO be applied to the Hooligan PA boundary rd Field Overview • Discovered in 1983 by Shell Seal Island #1 (BF -47 #1) • Currently 30 wells drilled to date (w/ 4 sidetracks) 0 20 Producer wells (1 shut in) 0 7 Gas Injection wells (1 shut in) 0 2 Disposal wells 0 1 Suspended well • Total cumulative production is 175.69mmbo (July 2018) 0 Kuparuk:5.19mmbo 0 Sag River: Ommbo 0 Ivishak: 170.50mmbo • Currently shut-in (integrity) 0 NS -24 (Sag River — Producer - Integrity) 0 NS -25 (Ivishak — Injector — Reservoir Management) • NS -26 is suspended 5 Field Production History Northstar Monthly Production (Daily Average) 1,000,000 Initial lvishak Development 10/2001 100,000 10,000 SSy 1\1\ti�95ry �� y\1\ti��a ~\1\ti0�y 1\1\ti��b y\1\ti�� y\y\ti�sp ~\1\ti0�°� 1� ~ti 7ti p y\1\ry�tib ~\y\v�tih y\y\ry�~rO ~\y\ry�11 ~\y\ry01� 1\1\ry��9 E Exhibit B: Injection Area Plat 7 Exhibit K: NS -18 Area of Review Map NS -15 i 8,883 HILCORP ALASKA LLC Northstar Kuparuk Sole= 8OVfinch By-- DJY o bob NS -23 A 8,982 NS49 A 8,962 NS -24 . -9,m SEAL A-01 PF -8,8]9 N5-08 NS -28 f $923 Northstar Kuparuk Stratigraphy Z LU Q Z 0W O3 O my W N W O N O Z W N O W U Q W W U W D TRIASSIC Z QW OZ PERMIAN w �w UJ p PENNSYLVANIAN JLU N W SW NE MA 7,,Exhibit F: NS -15 well with Top and Base Kuparuk defined arulc Kuparu Kingak Fm Shublik Fm. 0 9. Lisburne Gp. NORTHSTAR NS -15 tfi. �% rDa ] D mane �-OCO�v D!b o 60 eGBV Dp1iD3 oe maw XecaaD Dm`re"an � r xw anw "418r a 12161) t 2 --- -}� R TKUPC rz16o ' i 12200---_— 12220 72240 12260 .12280. _... .-__ 12300. 12320 12340 - 42360..,. . . 12360 ...72400: 1z•:zn 2440 NS1 r AR_8K(1PQ; ., 72450 12480 Top for este bhshment of pool rules = 72158' PAD The Northstar Unit Kuparuk Oil Pool is defined as the hydrocarbon bearing intervals common to and correlating with the interval between 12,156' MD and 12,466' MD in the NS -15 well Base fes e.tsbf.hment of pool rules = 12448' MD 9 Exhibit J: Northstar Pressure Gradients Pressure (psi) 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 11,000 12,000 13,000 0 1,000 2,000 3,000 4,000 y W 5,000 Q 6,000 v 7,000 r 8,000 d i 9,000 H 10,000 11,000 12,000 13,000 Equivalent Mud Weight (ppg) 10 Frac Gradients Reservoir Pressure x Seal -A-01 from Mud Weight x Seal -A-02 OH • Seal -A-01 X x Seal -A-02 RD • Seal -A-02 OH X X X Seal -A-03 • Seal -A-02 RD XX Seal -A-04 • Seal -A-03 x Northstar 1 Seal -A-04 X Northstar 2 • North Star 1 Reservoir Pressures from Drill Stem Tests c Seal -A-01 X ° Seal -A-02 OH Seal -A-03 ° Northstar 1 reservoir pressure 10 gradient fracture pressure gradient HRZ and Kuparuk Fm. Miluveach Fm. Overburden Kingak Fm. Sag River Fm. _ XX Ivishak Fm. Hydrostatic X15 9 11 13 17 19 Equivalent Mud Weight (ppg) 10 NS -18 Well Construction ,Q. WT. • Recompleted as Kuparuk Producer in 2016 9-5/8 production casing run to 14668' MD ra� Q and cemented with 574 bbls cement in 12- "� 1/4 " hole. Estimated TOC at 8100' MD w/ • 30% excess and 53 bbls lost during cement ,., job. M Kuparuk Perfs • Bond log run across 9-5/8" after 4-1/2" tubing run shows good cement bond to at least tubing tail at 13,932' MD. • Tubing packer (13,874' MD) to upper Kuparuk perfs (14,202' MD) = 328' • MIT -IA on 8/6/16 passed to 3100 psi • Initial and follow-up MIT-IAs will be per 20 AAC 25.402 and Guidance Bulletin 10-02A 4 1/1• T111. 11 CO 739 - Kuparuk Oil Pool Rules: In -Place and Recoverable Volume Estim 8. In -Place and Recoverable Volume Estimates: Hydrocarbon Resource Original Gas in Place Original Oil in Place Primary Recovery Primary + Waterflood Estimated Volume 500 to 550 BCF 22 to 25 MMSTB 40% 46% These estimates are calculated using volumetrics supported by material balance calculations that assume some aquifer support. 3 The acronym MMSTB signifies millions of stock tank barrels. The acronym BCP signifies billion cubic feet of gas. 12 Northstar Kuparuk Cumulative Production Plot - Depletion & EOR Project 2010 2015 2020 2025 2030 Three Well Depletion - current producers 9,000 - (NS -08, NS -15, & NS -18) Three Production Wells (NS -08, NS -13, & NS -15) 12,990 +3,990 One -50MMcfd GI NJ Conversion (NS -18) Three Production Wells (NS -08, NS -13, & NS -15) 14,560 +5,560 OnRAKA_I� 13 15,000- 14,000- -------- ----- - - ---- - -------- --- -- ------ - ------ ------ -- --------------------------------------- ------ -- - ------ - - - - ------ - ........ 13,000- -- --------------- - ------------------------------------------------------------------------------------------------- ---------------------------------- ------------------------------------ 12,000 - - --- --- - -- ---------------------------------................................................... ......................................................... : ---------------- I ............................... —11,000 I . .................... ............................ --r --- -- ------------------ ------------------------- ---------------------------------- -------- ----------------------------------------------- ca10,000 - -- - - ------------------------------------------ --------------------------------------------------- ------------------------ 1- ........... ................... ...... d --------- -------- -------------------------------- ---------------------------- ------- ------ --- ------ -------- ---------- 8,000 - - - - - - - ------------------------ --------------------------------------------------- _-, ------------- - ---------------------- ------------------------------------- 0 7,000- - ---- --- - ----------------------- -------------- -------------------- - ---------- ---------------_--- --------------------------- -------------------------------------------- 6,000 ................................................... .................................... ----------------------------- --------------------------------------------------------- _7 - - -- ------- �5 5,000 - - -------- --- ---------------------------------- L -------------_-------------- ......... - -- - - ------------------------ ------------ -------------------------------------------- E 4,000 - - ---- ----------------- ---------------- --------------------------41:`---------- -................................................... --------------------------------------------------------- 3,000] - --- - - --------- I ............................ : ---------- ------- 4 Cumulative Oil Production —All Kuparuk — Historical Data ---- Cumulative Oil Production —All Kuparuk Scenano#1 —Depletion E 2,000 -- - --- ------- ---------- .................. ---------- Cumulative Oil Production —All Kuparuk Scenario#2 — 50MMcfd .... 1.000 - ____ .............. ,* : . . ........... : -------------------------------------- GINJ Cumulative Oil Production —All Kuparuk Scenano#3 — - . ..... f�A"~�_IkH --------------------------- ----------- ......... . . 2010 2015 2020 2025 2030 Three Well Depletion - current producers 9,000 - (NS -08, NS -15, & NS -18) Three Production Wells (NS -08, NS -13, & NS -15) 12,990 +3,990 One -50MMcfd GI NJ Conversion (NS -18) Three Production Wells (NS -08, NS -13, & NS -15) 14,560 +5,560 OnRAKA_I� 13 BACKUP SLIDES Kuparuk A Cross-section: S to N 0 M Kuparuk A core from SEAL A-03 15 Kuparuk A Cross-section: NW to SE Northstar Kuparuk Average Reservoir Pressure Plot - Depletion & EOR Pin ZI 4 7 2015 2020 2025 2030 Reservoir Pressure — Kuparuk — Historical Data ---- Reservoir Pressure — Kuparuk — Scenario#1 — .....— Depletion ----- Reservoir Pressure — Kuparuk — Scenario#2 — 50MMcfd GINJ Reservoir Pressure — Kuparuk — Scenario#3 — 80MMcfd GINJ 17 Exhibit D: Ivishak Reservoir Pressure vs. Time • NSW • NSW x NSW• NS09 • NS12 • NS13 NS14 - NS16 • NS16 NS17 • NS13 < NS19 • NSM x NS21 • NSM NS23 NS24 ♦ NSM - NS27 • N529 • NS31 • NSW • NSM N911 • NSM ♦ NSM —Average P.nm 5350 5325 5300 5275 in 5250 a 0 5225 a 0 5200 0 5175 5150 0 0 � 5125 5100 m 5075 a e 5050 Z w 5025 m z 5000 Uly'k. 4950 4925 4900 Initial 4875 NNN MMMyy OVVt�OON((pp QOQ coo NNOJqq QO1 OOOO--r-.-NNNNMMMM«VVN 0000 000 OOOOOOOOOOOOOOOOpppO0000000�e-r-r-�r-r-e--r----------- m 4?t?tSm Zfm °,?Tm 01 �040<"0mo�Zswo`' O'Mn?3�" Y��S'13mc' Timo-R010 I¢ O'¢ O'¢ OROma¢ Oma¢ O-7¢ Oma¢ Oma¢ Oma¢ Oma¢ Oma¢ Oma¢ Oma¢ O� IN Exhibit E: Ivishak Monthly Production and Water Cut % vs. Time IE+88 1000000 100000 10000 1000- 100- 2001 2802 2003 2004 2005 —...__-.T--:.__,_ zoos 20D7 2006 zoos zom10 201 zou 2012 zola zola 2015 x010 20v — Gas Production (MCfPM) — Od Production (BOPM) — Water Production (BWPM) — Water Cu[ 19 Exhibit H: Combined Northstar Kuparuk and Ivishak Formation Injectant Gas Composition Analysis Name Result Units Line Pressure 2104 psig Line Temperature 65.10 deg F Methane (Normalized) 80282 Mole% Ethane (Normalized) 7.574 Mole% Propane (Normalized) 4.013 Mole% i -Butane (Normalized) 0.516 Mole°/ n -Butane (Normalized) 0.902 Mole% i -Pentane (Normalized) 0.182 Mole°/ n -Pentane (Normalized) 0.185 Mole% C6 Group (Normalized) 0.140 Mole% C7 Group (Normalized) 0.113 Mole% C8 Group (Normalized) 0.062 Mole% C9 Group (Normalized) 0.023 Mole% C6t (Normalized) 0.338 Mole% Carbon Dioxide (Normalized) 5.514 Mole% Nitrogen (Normalized) 0.494 Mole% Oxygen Contamination <0.001 Mole% Specific Gravity Ideal @ 14.696 psia 0.7221 Specific Gravity Real @ 14.696 psis 0.7242 BTU Gross Dry Ideal @ 14.696 psia 1125.1 Btuld BTU Gross Dry Real @ 14.65 psia 1125.2 Btuld BTU Gross Saturated Ideal @ 14.73 psia 1108.1 Btuld BTU Net Ideal @ 14.696 psia 1018.8 Btuld Molecular Weight (calculated) 20.90 BTU Gross Saturated Real @ 14.65 psia 1102-1 Btuld Specific Gravity Real @ 14.65 psia 0.7242 Compressibility Factor 0.9968 (Sample collected 1/22/2018) 20 i STATE OF ALASKA ADVERTISING ORDER NOTICE TO PUBLISHER SUBMIT INVOICE SHOWNG ADVERMNG ORDER NO., CERTIFIED AFFIDAVIT OF PUBLICATION WITH ATTACHED COPY OFADVERTISMENT. ADVERTISING ORDER NUNMER 1 n AO-19-002 FROM: Alaska Oil and Gas Conservation Commission AGENCY CONTACT: Jody Colombie/Samantha Carlisle DATE OF A.O. 7/23/2018 AGENCY PHONE: (907) 279-1433 333 West 7th Avenue Anchorage, 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: LEGAL DISPLAY : CLASSIFIED OTHER (Specify below) DESCRIPTION PRICE CO-18-032 Initials of who prepared AO: Alaska Non -Taxable 92-600185 SUBMIF NVE]ICE SHUWDQO'ADVERFISINO. .�::0@DERNO.;CER-MIBD�AFFIDAYII�QE�:�: .............. .. .. ... ... .. ........ TUBLWATIDN WIFH:ATTAGNIDCOPYOF: AUV£RFtBRIBNT:`{O' '' AOGCC 333 West 7th Avenue Anchorage, Alaska 99501 Page I of I Total of All Lages S REF Type I Number Amount Date Comments I PvN IVCO21795 2 AO AO-19.002 3 4 FTN AMOUNT SY Act Template PGM LGR Object FY DIST LIQ t 19 A14100 3046 19 2 3 5 ail 1 Pure ng u n i I Title: Purchasing Authority's Signature Telephone Number 1. 5ii&ng aty name must appear on all inwices and docume resale.nts relating to this purchase. Telt s to is registered fo x free transactions under Chapter 32, IRS code. Registration number 92-73-0006 K. Ites are for the "clusive use of the state and not for re' m DIST F 30N. DLvtslon F,sca1[Original A... s hnsca}ry . all. iRs Form: 02-901 Revised: 7/23/2018 Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Re: Docket Numbers: CO -18-032 Northstar-Kuparuk Oil Pool, Northstar Unit Application for Area Injection Order Hilcorp Alaska, LLC (Hilcorp), by applications dated July 18, 2018, requests the Alaska Oil and Gas Conservation Commission (AOGCC) issue an Area Injection Order to authorize a lean gas enhanced recovery injection project in the Northstar-Kuparuk Oil Pool in the Northstar Unit. The AOGCC has scheduled a public hearing on the application for September 6, 2018, at 2:00 p.m. at 333 West 7t' Avenue, Anchorage, Alaska 99501. In addition, written comments regarding this application may be submitted to the AOGCC, at 333 West 7`h Avenue, Anchorage, Alaska 99501. Comments must be received no later than the conclusion of the September 6, 2018 hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact the AOGCC at (907) 279-1433, no later than September 1, 2018. Hollis S. French Chair, Commissioner Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Re: Docket Numbers: CO -18-032 Northstar-Kuparuk Oil Pool, Northstar Unit Application for Area Injection Order Hilcorp Alaska, LLC (Hilcorp), by applications dated July 18, 2018, requests the Alaska Oil and Gas Conservation Commission (AOGCC) issue an Area Injection Order to authorize a lean gas enhanced recovery injection project in the Northstar-Kuparuk Oil Pool in the Northstar Unit. The AOGCC has scheduled a public hearing on the application for September 6, 2018, at 2:00 p.m. at 333 West 7`h 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 September 6, 2018 hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact the AOGCC at (907) 279-1433, no later than September 1, 2018. //signature on file// Hollis S. French Chair, Commissioner ANCHORAGE DAUX 11 AAAr NE D AFFIDAVIT OF PUBLICATION JUL 2 6 2018 AOGCC Account 9: 270227 ST OF AK/AK OIL AND GAS Order# 0001425118 Product ANC -Anchorage Daily News CONSERVATION COMMISSION Cost $154.40 Placement 0300 333 WEST 7TH AVE STE 100 Position 0301 nnirunonno nk oosnruvo STATE OF ALASKA THIRD JUDICIAL DISTRICT Joleesa StepetinSTATE oF dL^bueH j01 sawou being first duly sworn on oath deposes and says ALASKA OIL AND GAS CONSERVATION COMMISSION that he/she is a representative of the Anchorage Re: Docket Numbers: CO -18-032 Daily News, a daily newspaper. That said Northstar-Kuparuk oil Pool, Northstar unit Application for Area Injection Order newspaper has been approved by the Third Hilcorp Alaska, LLC (Hilcor ), by applications dated July 18, 2018, Judicial Court, Anchorage, Alaska, and it now requests the Alaska Oil an Gas Gas Conservation Commission (AOGCC) and has been published in the English language issue an Area Injection order to authorize a lean Kas enhanced recovery injection project in the NOrthstar-Kuparuk Oil Pool in the continually as a daily newspaper in Anchorage, Northstar unit. . Alaska, and it is now and during all said time The AOGCC has scheduled a public hearinx on the application for was printed in an office maintained at the September b, 2018, at 2:00 p.m. at 333 Wes 7th Avenue, Anchorage, Alaska 99501. aforesaid place of publication of said newspaper. In addition, written comments regarding this application may be That the annexed is a copy of an advertisement submitted to the AOGCC, at 333. West 7th Avenue, Anchorage, Alaska as it was published in regular issues (and not in 99501. Comments mb 2018 hearing received no later than the conclusion of the supplemental form) of said newspaper on If, because of a disabiffind theg special accommodations may be needed ro no titer thnt an September 1e 2018, contact the AOGCC at (907) 279-1433, July 24, 2018 - //si>pature on file// ollis S. French and that such newspaper was regularly Chair, Commissioner distributed to its subscribers during all of said Published: July 24, 2018 period. That the full amount of the fee charged for the foregoing publication is not in excess of the rate charged private individuals. Signed u J sa Steoetin Subscribed and sworn to before me this 24th day of Jam, 2018 lJ Notary Publi i nd for The State of Alaska. Third Division Anchorage, Alaska MY COMMISSIOjV(EJCPIRJS Notary Public BRITNEY L. THOMPSON State of Alaska 3, 2019 My Commission Expires Feb 2 Colombie, Jody 1 (DOA) From: Colombie, Jody J (DOA) Sent: Monday, July 23, 2018 2:23 PM To: Bell, Abby E (DOA); Bixby, Brian D (DOA); Boyer, David L (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Cook, Guy D (DOA); Davies, Stephen F (DOA); Earl, Adam G (DOA); Erickson, Tamara K (DOA); Foerster, Catherine P (DOA); French, Hollis (DOA); Frystacky, Michal (DOA); Guhl, Meredith D (DOA); Herrera, Matthew F (DOA); Jones, Jeffery B (DOA); Kair, Michael N (DOA); Laubenstein, Lou (DOA); Loepp, Victoria T (DOA); Martin, Teddy J (DOA); McLeod, Austin (DOA); Mcphee, Megan S (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Rixse, Melvin G (DOA); Roby, David S (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Wallace, Chris D (DOA); AK, GWO Projects Well Integrity; AKDCWellIntegrityCoordinator, Alan Bailey, Alex Demarban; Alicia Showalter; Allen Huckabay; Andrew Vandedack, Ann Danielson; Anna Lewallen; Anna Raff; Barbara F Fullmer; bbritch; bbohrer@ap.org; Ben Boettger; Bill Bredar; Bob Shavelson; Bonnie Bailey, Brandon Viator, Brian Havelock, Bruce Webb; Caleb Conrad; Candi English; Cody Gauer, Cody Terrell; Colleen Miller; Connie Downing; Crandall, Krissell; D Lawrence; Dale Hoffman; Danielle Mercurio; Darci Horner, Dave Harbour, David Boelens; David Duffy, David House, David McCaleb; David Pascal; ddonkel@cfl.rr.com; Diemer, Kenneth J (DNR); DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elizabeth Harball; Elowe, Kristin; Elwood Brehmer; Evan Osborne; Evans, John R (LDZX); Brown, Garrett A (DNR); George Pollock, Gordon Pospisil; Greeley, Destin M (DOR); Greg Kvokov; Gretchen Stoddard; gspfoff; Hurst, Rona D (DNR); Hyun, James J (DNR); Jacki Rose; Jason Brune; Jdarlington Qarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jill Simek; Jim Shine; Jim Watt, Jim White (im4thgn@gmail.com); Young, Jim P (DNR); Joe Lastufka; Radio Kenai; Burdick, John D (DNR); Easton, John R (DNR); Larsen, John M (DOR); Jon Goltz; Joshua Stephen; Juanita Lovett, Judy Stanek; Kari Moriarty; Kasper Kowalewski; Kazeem Adegbola; Keith Torrance; Keith Wiles; Kelly Sperback; Frank, Kevin J (DNR); Kruse, Rebecca D (DNR); Kyla Choquette; Gregersen, Laura S (DNR); Leslie Smith; Lori Nelson; Luke Keller, Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Michael Bill; Michael Calkins; Michael Moora; Michael Quick, Michael Schoetz; Mike Morgan; MJ Loveland; Motteram, Luke A; Mueller, Marta R (DNR); Nathaniel Herz; knelson@petroleumnews.com; Nichole Saunders; Nick Ostrovsky; NSK Problem Well Supv; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Renan Yanish; Richard Cool; Robert Brelsford; Robert Tirpack; Robert Warthen; Ryan Gross; Sara Leverette; Scott Griffith; Shahla Farzan; Shannon Donnelly, Sharon Yarawsky; Skutca, Joseph E (DNR); Smith, Kyle S (DNR); Spuhler, Jes J (DNR); Stephanie Klemmer, Stephen Hennigan; Stephen Ratcliff; Sternicki, Oliver R, Moothart, Steve R (DNR); Steve Quinn; Suzanne Gibson; sheffield@aoga.org; Tanisha Gleason; Ted Kramer, Teresa Imm; Terry Caetano; Tim Mayers; Todd Durkee; Tom Maloney, Tyler Senden; Umekwe, Maduabuchi P (DNR); Vern Johnson; Vinnie Catalano; Well Integrity; Well Integrity; Weston Nash; Whitney Pettus; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andy Bond; Bajsarowicz, Caroline J; Bruce Williams; Casey Sullivan; Corey Munk; Don Shaw; Eppie Hogan; Eric Lidji; Garrett Haag; Smith, Graham O (DNR); Heusser, Heather A (DNR); Fair, Holly S (DNR); Jamie M. Long; Jason Bergerson; Jesse Chielowski; Jim Magill; Joe Longo; John Martineck, Josh Kindred; Keith Lopez; Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Matt Armstrong; Melonnie Amundson; Franger, James M (DNR); Morgan, Kirk A (DNR); Umekwe, Maduabuchi P (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Rachel Davis; Richard Garrard; Richmond, Diane M; Robert Province, Ryan Daniel; Sandra Lemke; Scott Pins; Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); William Van Dyke; Zachary Shulman Subject: Public Notice AIO Northstar-Kuparuk Oil Pool (Hilcorp) Attachments: AIO-18-032 Public Hearing Notice Northstar-Kuparuk Oil Pool AIO.pdf Please see attached. Jody J. CoCombie AOGCC Specia(Assistant 7Caska Oil andCGas Conservation Commission 333 West 711 Avenue Anchorage, Alaska 99501 Office: (907) 793-1221 Fax: (907) 276-7592 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC(, State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jody Colombie at 907.793.1221 or iody.colombie@alasko.gov. 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 1 Hilcorp Alaska, LLC July 18, 2018 Hollis French, Chairman Post Office Box 244027 Anchorage, AK 99524-4027 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 Chris Kanyer, Reservoir Engineer Email Ckanver@bilcocp.com REI'1 Alaska Oil and Gas Conservation Commission JUL 2 0 201$ 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 A®GCC RE: Application for a Northstar Area Injection Order for the Kuparuk Formation Dear Commissioner French, Hilcorp Alaska, LLC ("Hilcorp"), as the sole Working Interest Owner and Operator of the Northstar Unit/Field, herby applies for an Area Injection Order (AIO) to cover proposed enhanced recovery operations in the Northstar Kuparuk Oil Pool ("NKOP"), described in Conservation Order No. 739. Injection operations will be confined to the area within the defined NKOP. The Northstar Unit ("Unit') is comprised of four State of Alaska leases and three federal leases, together encompassing approximately 20,134 unitized acres. The Unit is jointly managed by the State of Alaska Department of Natural Resources ("DNR") and the federal Bureau of Safety and Environmental Enforcement (`BSEE"). Copies of the current Northstar Unit exhibits are attached hereto. The affected area of the proposed area injection order falls entirely within the Northstar Unit and precisely matches the legal boundary of the established 7,656 acre Hooligan Participating Area (See Exhibit A: Northstar Unit and Participating Area Map). The proposed order is designed to prevent economic and physical waste and improve the ultimate recovery of remaining hydrocarbons in the NKOP. By adding gas injection to the Kuparuk Reservoir, Hilcorp will be able to maximize recovery from the Kuparuk reservoir, while allowing for continued production from the established Ivishak Enhanced Oil Recovery ("EOR") project. Hilcorp Alaska, LLC Proposed Rules for the Kuparuk AIO at Northstar Page 2 of 20 Application for a Northstar Area Injection Order - Kuparuk Formation Plat of Project Area - 20 AAC 25.402 (c)(1) At this time, only a single well, NS -18, is planned to become a Kupaurk injector. Exhibit B: Injection Area Plat is a map showing the location of NS -18 along with all other existing wells that penetrate the Kuparuk River injection zone as defined by the Hooligan Participating Area. None of the other development or service wells at Northstar penetrate the injection zone within one-quarter mile radius of NS -18. Operators / Surface Owners - 20 AAC 25.402 (c)(2) and (c)(3) The follow is a list of all operators and surface owners within one-quarter mile of the proposed injection area as described in this application Operator Hilcorp Alaska, LLC 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 Surface Owners Department of Natural Resources State of Alaska 550 W. 7th Avenue, Suite 800 Anchorage, AK 99501 Bureau of Ocean Energy Management Alaska OCS Region 3801 Centerpoint Dr., Ste. 500 Anchorage AK 99503-5820 An affidavit showing that the designated operators and surface owners within a one-quarter mile radius have been provided a copy of the application for injection is attached as Exhibit C: Notification Affidavit. Description of Operation - 20 AAC 25.402 (c)(4) The Northstar Unit currently consists of 30 wells, of which 27 are currently online and three are shut-in. Hilcorp is currently producing three unit wells (NS -08, NS -15, & NS - 18) from the Kuparuk sands. Production from the Northstar Unit began solely from the Ivishak reservoir in November 2001. At field startup the EOR project was initiated to deliver maximum benefit to ultimate oil recovery. Initially, imported gas from the Prudhoe Bay Unit ("PBU") was blended with Hilcorp Alaska, LLC Proposed Rules for the Kuparuk AIO at Northstar Page 3 of 20 Northstar produced gas to make a miscible injectant. In June 2005, miscible injection ceased and near -miscible gas injection began. At this time reservoir pressure decreased by approximately 100psi, but was still within proposed guidelines of the approved Ivishak EOR project under AIO23. (See Exhibit D: Ivishak Reservoir Pressure vs. Time). Continuous production from the Kuparuk reservoir began with the NS -08 well in November 2010. The produced Kuparuk gas and continued imports of PBU gas were used as the near -miscible gas injectant until imports terminated in 2014. At that time, the only injectant available to maintain the Ivishak EOR project was the produced gas from a single well (NS -08) in the Kuparuk reservoir. Additional Kuparuk production was added from the NS -18 and NS -15 wells in August 2016 and August 2017, respectively. Kuparuk Oil pool rules (Conservation Order No. 739) were approved in January 2018. As the result of increased gas production, mainly from the NS -15 well, there is excess gas capacity available. Over the past 24 months Ivishak reservoir pressure has nearly returned to initial reservoir pressure. As a result, existing Ivishak production wells have exhibited beneficial oil cut improvements. (See Exhibit E: Ivishak Reservoir Production and Water Cut % vs. Time). Due to the adequate source of gas injection volumes for the Ivishak EOR project, there exists sufficient supply to begin injection into the Kuparuk reservoir. Peak daily injection for the Kuparuk reservoir could be up to 120 MMCFD, with individual well injection rates expected around 50-80MMcfd. These volumes will vary based upon number or wells and existing excess supply from the Ivishak reservoir. Anticipated sustained injection rate is likely to be approximately 65 MMCFD. In 2018, Hilcorp anticipates performing one Kuparuk recompletion for production and converting one existing Kuparuk producer (NS -18) to gas injection. Going forward, Hilcorp anticipates additional Kuparuk development recompletions, workovers, gas injection conversions, and possibly new drill or sidetrack wells to expand the Kuparuk EOR project. The results of the initial gas injection conversion candidate will help dictate EOR project expansion. Note that these operations will be performed in parallel with the existing Ivishak EOR project. Pool Information - 20 AAC 25.402 (c)(5) The proposed Northstar Injection Area encompasses the Northstar Kuparuk Oil Pool (NKOP). The NKOP is defined as the accumulation of hydrocarbons common to and correlating with the interval between the measured depths ("MD') of 12,156' and 12,446' in the Northstar Unit NS -15 well. Geologic Information - 20 AAC 25.402 (c)(6) Iniection Interval: At Northstar, the Cretaceous -aged Kuparuk strata consist of three to five upward - coarsening A -sand packages, an intermediate shale and the Kuparuk C fining -upward sand Hilcorp Alaska, LLC Proposed Rules for the Kuparuk AIO at Northstar Page 4 of 20 package that in some areas (off the crest of the structure) is capped by a blocky sand. Total Kuparuk C -A thickness ranges from 160' TVD (NS -08) to 330' (NS -03). The Kuparuk C consists of bioturbated and burrowed glauconitic sandstones, shaley sandstones, siltstones and shales. The Kuparuk C was most likely deposited in an off- shore or shelf depositional setting. Kuparuk C thickness varies widely across the fields as observed in well logs. The Kuparuk C consists of a fining -upward sequence (lower Kuparuk C) and in some areas is capped by an upper sand package (upper Kuparuk Q. In general, the Kuparuk C is thinnest on the crest of the present-day anticline and thickens off -structure. The Kuparuk C sand thickness is 38' at the NS -08 well and thickens to 108' at NS -07. This variation in gross Kuparuk C thickness is most likely due to the movement of faults during Cretaceous rifting as the C -sands were deposited. The Kuparuk A thickness is much better behaved and does not appear to be influenced by faults or present day structure to the extent that the C sands are. The Kuparuk A sands consist of three to five coarsening -upward sand packages that are separated from the Kuparuk C by a shale barrier that varies in thickness from 10'-50' TVD. These were also deposited in an offshore setting. Structure: The Kuparuk accumulation at Northstar consists of the Kuparuk C and Kuparuk A reservoirs along the crest of a 4 mile by 2 mile anticline from ESE to WNW. The main anticlinal feature trends ESE to WNW and is faulted. Examples of this faulting can be readily observed in the subsurface on 3D (three dimensional) seismic data and at least two wells have fault cuts through the Kuparuk C and A. Current maps, production, production tests, RFT data and log data indicate an oil rim in the Kuparuk A with a gas condensate cap. The Kuparuk C is gas condensate. There is no direct evidence of the oil rim in the Kuparuk C. Confining Intervals: The Kuparuk Formation is bounded above by the Kalubik and HRZ intervals and bounded below by the Miluveach and Kingak Formations. Hilcorp Alaska, LLC Proposed Rules for the Kuparuk AIO at Northstar Page 5 of 20 Well Logs - 20 AAC 25.402 (c)(7) All openhole logs from the Northstar wells penetrating the Kuparuk were sent to the commission when the wells were completed. As presented in Exhibit F, well NS -15 is the type log for the Northstar Kuparuk Injection Area with stratigraphy and marker horizons annotated. Logs for the initial injection well NS -18 are included as Exhibit G. Casing Description - 20 AAC 25.402 (c)(8) During this phase of the Northstar Kuparuk development, NS -18 will be the only injector. NS -18 was originally completed as an Ivishak producer but the Ivishak was abandoned and the well was recompleted as a Kuparuk producer in the fall of 2016. NS -18 enters the Kuparuk formation at 14,202' MD. The 13-3/8" surface casing was run to 4,033' MD and cemented to surface. The 9-5/8 production casing was run to 14,668' MD and cemented with an estimated TOC (calculated) at 6500' MD. 4-1/2" tubing run was run to 13,915' MD with a packer set at 13,874' MD. The well received a passing MIT -IA to 3,100 psi on 8/6/16. The proposed casing program is included with the "Permit to Drill Form No. 10-401" for each well and is documents with the AOGCC in the completion record. A follow-up "Completion Report From 10-407" is also filed with AOGCC. API injection casing specifications are included on each drilling permit application. All wells used for injection service will be cased and cemented in accordance with 20 AAC 25.030. All injection casing is cemented and testing in accordance with 20 AAC 25.412 for both newly drilled and converted injectors. Injection Fluid - 20 AAC 25.402 (c)(9) A description of the recovery process and development scheme is included in Hydrocarbon Recovery - 20 AAC 25.402 (c)(14) of this document. The gas composition selected for the EOR scenario assumes the current injection gas for the Ivishak EOR project. Exhibit H is a listing of the composition of this source gas. Fluid incompatibility problems, including asphaltene deposition have not been observed in Ivishak injection wells and are not anticipated with the gas flood of the Kuparuk Reservoir. Injection Pressure - 20 AAC 25.402 (c)(10) The maximum injection pressure at the wellhead is estimated to be 5,300 prig. Operating history indicates that the average Ivishak injection pressure at the wellhead is roughly 4,850 prig. Kuparuk injection will tie in to the common gas injection header and injection pressures are also expected to average around 4,850 psig at the wellhead. Fracture Information - 20 AAC 25.402 (c)(11) The expected maximum injection pressure for the gas injection wells, 5,300 psi, is insufficient to initiate or propagate fractures through the confining strata, and, therefore, will not allow injection or formation fluid to enter any freshwater strata. Hilcorp Alaska, LLC Proposed Rules for the Kuparuk AIO at Northstar Page 6 of 20 Fracture Gradients Exhibit J presents a summary of the fracture pressure and reservoir pressures determined from leak off testing, mud weights and drill stem testing in the discovery and appraisal wells in the Northstar Unit. More specifically, the confining shale above the Kuparuk was tested in the Seal A-04 well. After the well was drilled out of the 9-5/8" casing shoe to a depth of 12,153'MD (8,976'TVD), a LOT to 15.2ppg EMW (0.7904psi/ft gradient) was performed on 4/28/1985. They also noted the formation did not break down at this pressure. Due to this data, the assumed frac gradient for the Kuparuk has been O.8psi/ft, or approximately 7,200psi at 9,000' TVD. Freshwater Strata EPA has determined that there are no underground sources of drinking water ("USDW") beneath the Northstar Unit, as stated in the Public Notice dated June 24, 2000, and the Fact Sheet for the proposed issuance of UIC Area Permit AK -1 002-A dated June 23, 2000. Formation Fluid - 20 AAC 25.402 (c)(12) At this time insufficient water has been produced from any existing production well from to Kuparuk formation to obtain a sufficient sample for analysis. As stated in the earlier section of Injection Fluid - 20 AAC 25.402 (c)(9), it is assumed that the proposed lean gas injectant will not have any fluid incompatibility problems. Aquifer Exemption - 20 AAC 25.402 (c)(13) As set forth above, the lack of fresh water and USDW's in the Northstar Injection Area eliminates the need for an aquifer exemption. The presence of hydrocarbons, either live or as residual, causes the Northstar Pool to be unsuitable as a source of drinking water. Hydrocarbon Recovery - 20 AAC 25.402 (c)(14) Individual sand parameters or characteristics have been studied in the Kuparuk A and C sands. Some data uncertainty exists regarding the Kuparuk A sands due to limited production history. Most data is derived from open hole log analysis, core data, nodal analysis, pressure transient analysis (PTA), PVT samples, and well test performance. To evaluate the performance of the Kuparuk reservoir, a 3-D full field model ("FFM") was constructed. The FFM has 800 foot (14.7 acre) grid blocks that cover the entire NKOP and the surrounding aquifer. There are 43 vertical layers with grid block thickness averaging 0 to 10 feet. Faults observed in the subsurface on 3D seismic data are included in the model. The FFM utilizes an 18 component equation of state derived from the Kuparuk C PVT sample from the NS -08 well in December 2010. Hilcorp has evaluated a gas injection EOR project and primary depletion scenarios. The gas cycling scenario assumes injection to begin immediately (August 2018) in the FFM. The gas composition selected for the EOR scenario assumes the current injection gas for the Ivishak EOR project, as stated earlier, with the composition listed in Exhibit H. Hilcorp Alaska, LLC Proposed Rules for the Kuparuk AIO at Northstar Page 7 of 20 Oil and natural gas liquid ("NGL") recoveries for these cases are given below with cumulative production plots shown in Exhibit I. # Scenario Gross EUR Oil Gross Incremental (MBO)* EUR (MBO) Three Well Depletion — current producers 1 (NS -08, NS -15, & NS -18) 9,000 - 2 Three Production Wells (NS -08, NS -13, & NS -15) One-50MMcfd GINJ Conversion (NS -18) 12,990 +3,990 Three Production Wells (NS -08, NS -13, & NS -15) 3 One—80MMcfd GINJ Conversion (NS -18) 14,560 +5,560 *Simulated EUR based on end of field life 2030 (based on model) As seen in the above scenarios, planned gas injection rates (50MMcfd to 80MMcfd of gas injection) will significantly increase the ultimate recovery of remaining hydrocarbons in the Kuparuk reservoir. The EOR project should be implemented immediately to deliver maximum benefit and ultimate recovery of hydrocarbons in the Kuparuk Formation. Mechanical Condition of Adjacent Wells - 20 AAC 25.402 (c)(15) During this phase of the Northstar Kuparuk development, NS -18 will be the only injector. Exhibit K: NS -18 Area of Review Map shows the location of NS -18 well and all other existing wells. None of the other development or service wells at Northstar penetrate the injection zone within one-quarter mile radius of NS -18. Proposed Area Injection Order Rules Hilcorp, in its capacity as Northstar Operator, respectfully requests that the Commission issue an order authorizing the underground injection of Class II fluids for enhanced oil recovery in the Northstar Kuparuk Oil Pool and consider the following rules to govern such activity. The affected area of the proposed area injection order falls entirely within the Northstar Unit and precisely matches the legal boundary of the established 7,656 acre Hooligan Participating Area (See Exhibit A: Northstar Unit and Participating Area Map). Rule 1: Authorized Injection 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 Northstar Unit NS -15 well between measured depths ("MD') of 12,156' and 12,446'. Rule 2: Fluid Injection 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 Hilcorp Alaska, LLC Proposed Rules for the Kuparuk AIO at Northstar Page 8 of 20 existing well that has been approved for conversion to a service well for injection in conformance with 20 AAC 25.280. Rule 3: Monitoring the Tubing -Casing Annulus Pressure Variations The tubing -casing annulus pressure of each injection well must be checked at least weekly to ensure there is no leakage and that it does not exceed a pressure that will subject the casing to a hoop stress greater than 70% of the casing's minimum yield strength. Rule 4: Reporting the Tubing -Casing Annulus Pressure Variations Tubing -Casing annulus pressure variations between consecutive observations need not be reported to the Commission. Rule 5: Demonstration of Tubing -Casing Annulus Mechanical Integrity A schedule must be developed and coordinated with the Commission that ensures that the tubing -casing annulus for each injection well is pressure tested prior to initiating injection, and following well workovers affecting mechanical integrity. A test surface pressure of 1500 psi or 0.25 psi/ft. multiplied by the vertical depth of the packer, whichever is greater, but not to exceed a hoop stress greater than 70% of the casings minimum yield strength must be held for at least a 30 minute period with decline no more than or equal to 10% of test pressure. The Commission must be notified at least 24 hours in advance to enable a representative to witness pressure tests. Rule 6: Well Integrity Failure Whenever injection rates and/or operating pressure observations or pressure tests indicate pressure communication or leakage of any casing, tubing or packer, the operator must notify the Commission on the first working day following the observation, obtain Commission approval to continue injection and submit a plan of corrective action on Form 10-403 for Commission approval. Rule 7: Plugging and Abandonment of Injection Wells An injection well located within the affected area must not be plugged or abandoned unless approved by the Commission in accordance with 20 AAC 25.105. Rule 8: Administrative Action Upon proper application, the Commission may administratively waive the requirements of any rule stated above or administratively amend this order as long as the change does not promote waste or jeopardize correlative rights, and is based on sound engineering principles. Conclusion Hilcorp's proposed creation of an Area Injection Order for the Kuparuk Reservoir is designed to prevent waste, protect correlative rights and improve the ultimate recovery of remaining hydrocarbons throughout the Northstar Unit. Hilcorp Alaska, LLC Proposed Rules for the Kuparuk AIO at Northstar Page 9 of 20 Hilcorp would be pleased to schedule a technical meeting with AOGCC staff to provide additional information in support of this proposal. Should you have any other questions regarding this proposal, please do not hesitate to contact the undersigned at 777-8377. Sincerely, ` Chris Kanyer, Reservoir Engineer Hilcorp Alaska, LLC Non -Confidential Enclosures: • Northstar Unit Exhibit map • Northstar Hooligan Participating Area Exhibits • Northstar Injection Area Plat • Notification Affidavit • Northstar Ivishak Reservoir Pressure vs. Time • Northstar Ivishak Monthly Production and Water Cut % vs. Time • Northstar Unit NS -15 well with Top and Base Kuparuk Defined • Northstar Unit NS -18 well with Top and Base Kuparuk Defined • Combined Northstar Kuparuk and Ivishak Formation Injectant Gas Composition. • Northstar Kuparuk Cumulative Production Plot - Depletion & FOR Project vs. Time • Northstar Pressure Gradients • Northstar Unit NS -18 well Area of Review Map CC: • DNR (becky.kruse@alaska.gov) • BSEE (kevin.pender ast&bsee go • BOEM (david.johnston@boem�) Hilcorp Alaska, LLC Proposed Rules for the Kuparuk AIO at Northstar Page 10 of 20 Exhibit A: Northstar Unit and Participating Area Map NORTHSTAR UNIT AND PARTICIPATING AREA L:.canon n�a; 1,, Y1665 -- NmtM1slar lege �OunE]-� eG#.gn N0+[M1915I IPGBP NYY16B: a) NmMil#r Un�M1a[I plump#r 101 AOU+1Y96 Nprehaa Gartiupa+Icp Arca N ly P mc9alvp#.rea o son 11 :. .. Northstar Unit Exhibit A i Y0+19 r»• � Y0161 tai \ no�71�1e6 J l 107. AM111606 Nrr 1M NouuaOB Hilcorp Alaska, LLC Proposed Rules for the Kuparuk AIO at Northstar Page 11 of 20 ENCLOSURE: Northstar Hooligan Participating Area Exhibits E Hooligan Pafi .Hong Area(HHPI) UNTMg IpRMBTM VMi KaRFEMEM EMz�MgwamMl. AfA pO6 VU rgrmnelf0\]�ppN.mw VmNpo1H A.IJI nJ\]riM A WAmaMMrrNeLaatlwrabrt I.1M31 64NNJ Kne Xkq IJJ.W wFMe�nervrswnaynnv4 n�pl... aW.n.m.r nuFp.mexgn... eMpnebmSwulna Msa6pia a4a xgaN '.f rpgemrrtl OCCX acs pbpnn� hE]u lnlvMalmeWrrt Nt MFp nuFwl Mn Yw Y] er4 W 6191rNyknc*Aw NbeM ll.n4.R�Y.VM.AxwrAFY KIMENNgrM�MYne en]iWwnulMYn x4ru MY Otic b. P wvwNl]Mp. pnp Mqn: wu p.[tv„ V4aW LI]R0�] ttl9 EXHIBRC Hooligan P.dwipatingM(NXPA) XORMTMUNi R6RMEFlIFM EXaGM0.eamExf. 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WFxv +oo.W m :x. wmx'.. mn. emm��ml0°Dela-YmeeF.eo;.R„m.mF.laun.e.xamale.m s:.�l.'s�.mom a+enerom]u FwYYm p,pemxnea, B,eenryveF4,W�sxw M,xF+W} wR]mmarenvu xREn� w5an avnaxo AaEna aoaam wxt p SwWm w.avawx.. uc uWmn v+vmu sas Hilcorp Alaska, LLC Proposed Rules for the Kuparuk AIO at Northstar Page 13 of 20 Exhibit B: Injection Area Plat Exhibit C Affidavit Of Chris Kanyer Regarding Notice To Surface Owners I, Chris Kanyer, on oath, do hereby verify the following: 1. I am employed as Reservoir Engineer at Hilcorp Alaska, LLC (Hilcorp Alaska). Hilcorp Alaska is the Operator of the Northstar Unit, and the applicant for the Northstar Area Injection Order to replace the currently authorized Area Injection Order No. 23. 2. Pursuant to 20 AAC 25.402(b)(3), on July, 2018, I caused copies of the application for the Northstar Area Injection Order to be mailed by first class mail or personal delivery to the following persons: Andrew T. Mack, Commissioner Department of Natural Resources State of Alaska 550 W. 7 t Avenue, Suite 1400 Anchorage, AK 99501 Dr. James Kendall, Regional Director Bureau of Ocean Energy Management Alaska OCS Region 3801 Centerpoint Dr., Ste. 500 Anchorage AK 99503-5820 STATE OF ALASKA ) ss THIRD JUDICIAL DISTRICT Becky Kruse, Unit Manager Division of Oil & Gas Department of Natural Resources State of Alaska 550 W. 7h Avenue, Suite 1100 Anchorage, AK 99501 Chris anyer, Hilcorp Alaska, LLC SUBSCRIBED TO AND SWORN before me thisw day of July, 2018. ESTAnTE ALASKA PUBLIC Shine II Expires Feb 28, 2022 NOTA Y UBLIC IN AND FOR THE STME OF ALSKA �( My Commission Expires: I Hilcorp Alaska, LLC Proposed Rules for the Kuparuk AIO at Northstar Page 15 of 20 5350 5325 5300 5275 vg 5250 6 v 5225 c 5200 0 5175 5150 m 0 V 5125 5100 2 5075 6 5050 5025 c soon 4975 4950 4925 4900 4875 Exhibit D: Ivishak Reservoir Pressure vs. Time Exhibit E: Ivishak Monthly Production and Water Cut % vs. Time Hilcorp Alaska, LLC Proposed Rules for the Kuparuk AIO at Northstar Page 16 of 20 Exhibit F: NS -15 well with Top and Base Kuparuk defined Top of Kuparuk Oil Pool = 12,156' MD Base of Kuparuk Oil Pool = 12,446' MD .1 ■ 1 QQQ■ os�l�:r ■v��. QQ■ni'G�G'� ■■iii i 1 ■iineaii >. .1 rWOMAN 1 1 ■■G''ai■■ WIN ■■■!off ■■ter? rQIRISH ■r■fro Ago is r■.—=au MUMIME :1 i ■��Ei/�Ei ■■47■! r�pprr� • 1 1 ■FI■t: 77 NSIAR1 Top of Kuparuk Oil Pool = 12,156' MD Base of Kuparuk Oil Pool = 12,446' MD Hilcorp Alaska, LLC Proposed Rules for the Kuparuk AlO at Northstar Page 17 of 20 Hilcorp Alaska, LLC Proposed Rules for the Kuparuk AIO at Northstar Page 18 of 20 Exhibit H: Combined Northstar Kuparuk and Ivishak Formation Injectant Gas Composition (Sample collected 1/22/2018) Analysis Name Result Units Line Pressure 2104 Feist Line Temperature 65.10 deg F Methane (Normalized) 80.282 Mole°/ Ethane (Nomralized) 7.574 Mole°/ Propane (Normalized) 4.013 Mole% i -Butane (Normalized) 0.516 Mote% n-Butane(Normaitzed) 0.902 Mole% "r -Pentane (Nomralized) 0.182 Mole°/ n -Pentane (Normalized) 0.185 Mole°/ C6 Group (Normalized) 0.140 Mole% C7 Group (Normalized) 0.113 Mole°/ C8 Group (Normalized) 0.062 Mole% C9 Group (NDrmalized) 0.023 Mole°/ 06♦ (Normalized) 0.338 Male°/ Carbon Dioxide (Normalized) 5.514 Mole% Nitrogen (Normalized) 0.494 Mole°/ Oxygen Contamination <0.001 Mole% Specific Gravity Ideal @ 14.696 psia 0.7221 Specific Gravity Real @ 14.696 psia 0.7242 BTU Gross Dry Ideal @ 14.696 psis 1125.1 Btu/d BTU Gross Dry Real @ 14.65 psia 1125.2 Btuld BTU Gross Saturated Ideal @ 14.73 psis 1108.1 Btu/d BTU Net Ideal @ 14.696 psia 1018.8 Btuld Molecular Weight (calculated) 20.90 BTU Gross Saturated Real @ 14.65 psia 1102.1 Btuld Specific Gravity Real @ 14.65 psia 0.7242 Compressibility Factor 0.9968 Hilcorp Alaska, LLC Proposed Rules for the Kuparuk AIO at Northstar Page 19 of 20 Exhibit I: Northstar Kuparuk Cumulative Production Plot - Depletion & EOR Project vs. Time • Cumulative Oil Production —AII Kuparuk — Historical Data ---- Cumulative Oil Production —AII Kuparuk Scenario#1—Depletion ------ Cumulative Oil Production —AII Kuparuk Scenario#2-50MMcfd GINJ Cumulative Oil Production —AII Kuparuk Scenario#3-80MMcfd GINJ Hilcorp Alaska, LLC Proposed Rules for the Kuparuk AIO at Northstar Page 20 of 20 Exhibit J: Northstar Pressure Gradients Pressure (psi) 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 6,000 9,000 10,000 11,000 12,000 13,000 0 1,000 Frac Gradients Reservoir Pressure x Seal -A-01 from Mud Weight x Seal -A -020H • Seal -A-01 2,000 X x Seal -A-02 RD Seal -A-02 OH x Seal -A-03 • Seal -A-02 RD XX X % Seal -A-04 . Seal -A-03 3,000 x NOM1hstar 1 Seal -A-04 x Northstar 2 •North Star 1 4,000 HILCORP ALASKA LLC Northstar Kuparuk g ar onwv NS3 ♦ ;MS SEA M•n� ! av, , q NiW . a® xa6aW s,n 5,000 Reservoir Pressures from Drill Stem Tests o Seal -A -O7 6,000 % SeaFA-02 OH � � SealA-03 Northstar 1 t reservoir c 7,000 d pressure gradient 8,000 fracture pressure gradient I 9,000 HRZ and Kuparuk Fm. Miluveach Fm. Overburden 10,000 Kingak Fm. • t X 11,000 Sag River Fm. Ivishak Fm. 12,Oo0 Hydrostatic 9 11 13 15 17 1E 13,000 Equivalent Mud Weight (ppg) Exhibit K: NS -18 Area of Review Map HILCORP ALASKA LLC Northstar Kuparuk g ar onwv NS3 ♦ ;MS SEA M•n� ! av, , q NiW . a® xa6aW s,n HHilcorp Alaska, LLC July 23, 2018 RECEIVED JUL 2 6 2018 f- OGCC Jim Shine Landman - Sr. 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 Post Office Box 244027 Anchorage, AK 99524-4027 David Rob Phone: 907/777-8341 Roby Fax: 907/777-8301 Senior Reservoir Engineer jshine@hilcorp.com Alaska Oil and Gas Conservation Commission 333 W. 7" Avenue, Suite 100 Anchorage, AK 99501 RE: Hilcorp Alaska, LLC's Application for Northstar Area Injection Order for Kuparuk Formation — Updated Affidavit Dear Mr. Roby: Hilcorp Alaska, LLC ("Hilcorp Alaska"), respectfully submits the attached corrected affidavit regarding notice to surface owners to accompany Hilcorp Alaska's application for an Area Injection Order for the Kuparuk formation. Should you have any questions, please contact me directly at (907) 777-8341 orishinena hilcom com. Sincerely, Jim ine Landman — Sr. Hilcorp Alaska, LLC Attachment Affidavit Of Chris Kanyer Regarding Notice To Surface Owners I, Chris Kanyer, on oath, do hereby verify the following: 1. I am employed as Reservoir Engineer at Hilcorp Alaska, LLC (Hilcorp Alaska). Hilcorp Alaska is the Operator of the Northstar Unit, and the applicant for the Northstar Area Injection Order. 2. Pursuant to 20 AAC 25.402(b)(3), on July ZQ, 2018, I caused copies of the application for the Northstar Area Injection Order to be mailed by first class mail or personal delivery to the following persons: Andrew T. Mack, Commissioner Department of Natural Resources State of Alaska 550 W. 71h Avenue, Suite 1400 Anchorage, AK 99501 Dr. James Kendall, Regional Director Bureau of Ocean Energy Management Alaska OCS Region 3801 Centerpoint Dr., Ste. 500 Anchorage AK 99503-5820 Becky Kruse, Unit Manager Division of Oil & Gas Department of Natural Resources State of Alaska 550 W. 7h Avenue, Suite 1100 Anchorage, AK 99501 Chris Kanyer, Hilesrp Alaska, LLC STATE OF ALASKA ) ) ss THIRD JUDICIAL DISTRICT ) ? �/ SUBSCRIBED TO AND SWORN before me this 2 S=day of July, 2018. SZ= OF ALAS" UWARY PUBLIC JM11Nt M. Shine 11 Cortmiwbn EvWw Feb 2^ = NOTARYLIC IN AND FOR THE STA E F ALSKA My Commission Expires: