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DIO 042
DISPOSAL INJECTION ORDER NO. 42 Milne Point Unit Moose Pad Area 1. July 20, 2018 Hilcorp Alaska, LLC application for a DIO Milne Point Unit, Moose Pad Area 2. July 25, 2018 Notice of Public Hearing, Affidavit of Publication, Affidavit of Bulk Mailing and Email Distribution Lists 3. September 5, 2018 Sign -in sheet, hearing transcript and presentation 4. November 5, 2018 Application to Amend Rules 3 and 5 (D1042.001) 5. October 29, 2018 Application to Amend Rules 2 (DIO42.002) ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7" Avenue Anchorage, Alaska 99501 Re: THE APPLICATION OF Hilcorp Alaska, LLC. for disposal of Class II oil field wastes by underground injection in the Ugnu Formation in up to four wells located on the Moose Pad in the northwest portion of the Milne Point Unit Sections 12, 13, 14, 23, 24, T13N, R9E, and Sections 7, 18, 19, TON, R10E S.M. IT APPEARING THAT: Disposal Injection Order No. 42 Docket No. DIO-18-001 Ugnu Formation, Undefined Waste Disposal Pool Milne Point Unit October 24, 2018 Hilcorp Alaska, LLC (Hilcorp) requested authorization for underground disposal of Class II oil field waste fluids into up to four yet to be drilled wells (Class II wells) on the Moose Pad in the northwest portion of the Milne Point Unit (MPU). Hilcorp's Application for Disposal Injection Order (DIO) was received by the Alaska Oil and Gas Conservation Commission (AOGCC) on July 20, 2018. Pursuant to 20 AAC 25.540, the AOGCC scheduled a public hearing for September 5, 2018. On July 24, 2018, the AOGCC published notice of the opportunity for that hearing on the State of Alaska's Online Public Notice website and on the AOGCC's website, and electronically transmitted the notice to all persons on the AOGCC's email distribution list. On July 25, 2018, the notice was published in the ANCHORAGE DAILY NEWS. 3. At the September 5, 2018 hearing Hilcorp provided testimony and presented evidence in support of its Application. The record was closed at the end of the hearing. 4. The information submitted by Hilcorp and public records for MPU wells are the basis for this order. FINDINGS: 1. Location of Adjacent Wells (20 AAC 25.252(c)(1)) There are no active wells within the '/4 -mile area of review surrounding the disposal intervals for the proposed Class II wells. The plugged and abandoned Simpson Lagoon 32-14 well lies within '/4 mile of one proposed Class II well in the disposal interval. Future production and injection wells drilled from the Moose Pad may pass within '/4 mile of the proposed Class II disposal wells. Disposal Injection Order 42 October 24, 2018 Page 2 of 7 2. Notification of Operators/Surface Owners (20 AAC 25.252(c)(2) and 20 AAC 25.252(c)(3)) Hilcorp is the only operator and the State of Alaska, Alaska Department of Natural Resources (ADNR) is the only surface owner within Yo --mile radius of the proposed disposal wells. Hilcorp provided AOGCC a copy of an affidavit affirming that ADNR was provided a copy of the DIO application. 3. Geological Information on Disposal and Confining Zones (20 AAC 25.252(c)(4)) The proposed disposal injection operations will affect strata that are assigned to the lower Tertiary -aged Ugnu Formation (Ugnu). In Moose Pad area, the Ugnu consists of predominately discrete, coarse-grained, moderate to well -sorted, fluvial/deltaic, wet sands with average porosity of 30-32% and average permeability of 1,000 millidarcies. On the MPU M-01 type log, these clean sands are bounded by impermeable siltstones and mudstones. Hilcorp plans injection within the permeable upper Ugnu sands between the informal MP_LC and the MP UG15 geologic markers from 3,282' measured depth (MD, equivalent to -2,714' true vertical depth subsea, or TVDSS) to 3,912' MD (-3,187' TVDSS). Upper confinement for the proposed injection interval consists of laterally continuous layers of mudstone, siltstone, and coal that lie within the Ugnu between 2,854' (-2,413' TVDSS) and 3,282' MD (-2,714' TVDSS) in MPU M-01. These confining layers, which range in true vertical thickness (thickness) from 10' to 45' and have a combined thickness of about 90', will serve as effective barriers to prevent vertical migration of injected fluids. Lower confinement will be provided by laterally continuous layers of mudstone, siltstone and coal within the upper Ugnu between 3,912' MD (-3,187' TVDSS) and 4,033' MD (-3,280' TVDSS). These impermeable intervals range from 11' to 15' in thickness and have a combined thickness of 40'. The proposed disposal well area is partially bound to the east and west by north -south oriented faults with significantly less displacement than the thickness of the entire proposed injection interval. 4. Evaluation of Fluid Confinement (20 AAC 25.252(c)(9)) The porous and permeable nature of the wet, upper Ugnu sands allows injection of produced water at pressures that are lower than Hilcorp's stated formation -fracture pressure limit of 2,500 psi for unconsolidated sands. Future wells within 1/4 -mile must be constructed to ensure they do not serve as a conduit for fluid migration from the disposal zone. 5. Aquifer Exemption (20 AAC 25.252(c)(11)); Standard Laboratory Water Analysis of the Formation (20 AAC 25.252(c)(10)) Aquifer Exemption Order No. 2 governs the four potential Class II well locations near Moose Pad. Hilcorp does not have a water sample from the proposed disposal intervals in this area. Hilcorp provided information representing that it is cost -prohibitive to use subsurface aquifers near Moose Pad as a source of drinking water. 6. Well Logs (20 AAC 25.252(c)(5)) Log data from existing wells near Moose Pad are on file with the AOGCC. The representative well, MPU M-01, has a complete set of logs. Disposal Injection Order 42 October 24, 2018 Page 3 of 7 7. Demonstration of Mechanical Integrity and Disposal Zone Isolation (20 AAC 25.252(c)(6)) The proposed casing program is 10 -3/4 -inch surface casing set at 2,100' TVD and cemented to surface. A formation Integrity Test will be performed to 12.5 ppg equivalent and the production hole drilled. Production 7 -5/8 -inch casing will be set to 3,300' TVD and cemented to approximately 2,100' TVD and tested to 2,500 psi. A cement bond log will be run to confirm the cement top and that casing strings have adequate cement to prevent vertical migration of disposal fluids. Hilcorp requests packers be located more than 200' MD above the top of the disposal perforations. This will allow through -tubing access to the entire requested disposal zone. Tubing or other equipment will be designed and installed in accordance with 20 AAC 25.412. A casing mechanical integrity test will be performed in accordance with 20 AAC 25.412 prior to initiation of disposal operations. Hilcorp will perform mechanical integrity tests of the tubing and tubing -casing annulus (including packer) as part of the operations before disposal injection commences. Additional baseline assessments and subsequent evaluations may be necessary to confirm the wells have the proper mechanical integrity for disposal injection as proposed. Hilcorp will monitor the 7 -5/8 -inch casing by 5 -1/2 -inch tubing annulus pressure daily and report the results on the Monthly Injection Report. 8. Disposal Fluid Type, Composition, Source, Volume, and Compatibility with Disposal "Zone (20 AAC 25.252(e)(7)) Hilcorp requests approval to dispose of drilling, production, completion, workover wastes, and other associated wastes that are intrinsically derived from primary field operations. Hilcorp expects daily injection volumes of a maximum of 36,000 barrels for the first well, up to a cumulative 72,000 barrels with the proposed two wells. Over the expected 17 -year life of the project, Hilcorp expects to dispose of approximately 355 million barrels of liquids. This equates approximately to a plume of about 1,880' assuming a 300 -foot thickness, radial flow, and 100% pore -space displacement around each of the two planned disposal wells. Injected fluids are expected to be compatible with the lithology and in-situ formation water of the proposed disposal injection zone based on operating experience and past performance of MPU Class I disposal wells B-24, B-34 and B-50 (e.g., pressures, rates, and volumes). No compatibility issues have been reported associated with disposal injection into the Ugnu at Milne Point or other fields on the North Slope. 9. Estimated Injection Pressures (20 AAC 25.252(c)(8)) Hilcorp estimates average surface injection pressure will range from 2,000 to 2,300 psig while injecting 27,000 barrels per day per well for two wells. Maximum surface injection pressure could reach 2,500 psig if sporadic plugging of perforations or fracture -flow channels occurs. Accordingly, Hilcorp requested 2,500 psig as maximum allowed surface injection pressure. Disposal Injection Order 42 October 24, 2018 Page 4 of 7 10. Mechanical Condition of Wells Penetrating the Disposal Zone Within a i/4 -Mile Radius of Kenai Loop#3 (20 AAC 25.252(c)(12)) Simpson Lagoon 32-14 is the only well to penetrate the proposed disposal injection zone within a '/4 -mile radius of the four proposed disposal wells. Well construction records show that this well is properly plugged and abandoned; however, there is no cement across the lower proposed Ugnu disposal zone or the underlying sands assigned to the Schrader Bluff Oil Pool (Schrader Bluff), and only partial cement across the upper Ugnu disposal zone. I-Iilcorp's application states the cement plugs in the production casing across the surface casing shoe will prevent upward fluid movement from the Ugnu disposal zone in this well. CONCLUSIONS: I . The requirements of 20 AAC 25.252 for approval of an underground disposal application are met. 2. AEO No. 2 exempts the proposed Moose Pad disposal area for Class II injection activities only. 3. Hilcorp's plan to drill two disposal wells initially with another two wells as backup contingencies is a prudent approach for the MPU Moose Pad development. 4. Hilcorp's planned injection interval consists of poorly consolidated, porous and permeable Ugnu sands that lie from approximately 3,282' to 3,912' MD (-2,714' to -3,187' TVDSS), an interval that is about 473' thick with approximately 342' of net sand. 5. Upper confinement will be provided by a combined 90' of laterally continuous layers of mudstone, siltstone, and coal that lie within the Ugnu. 6. Lower confinement will be provided by laterally continuous layers of upper Ugnu mudstone, siltstone and coal that have a combined thickness of 40'. 7. No significant faults are present that could affect the proposed injection operations. 8. No compatibility issues have been reported associated with disposal injection into the Ugnu at Milne Point or other fields on the North Slope. 9. Fracture modeling indicates that disposed waste fluids will be contained within the receiving interval by confining lithologies, cement isolation of the well bore, and planned operating conditions. Modeling of rates up to 35,000 BPD per well predicts that fractures will not penetrate the upper confining zone or breach the lower confining zone. 10. Supplemental mechanical integrity demonstrations and regularly scheduled surveillance of injection operations—including baseline and subsequent temperature surveys, monitoring of injection performance (i.e., pressures and rates), and analyses of the data for indications of anomalous events—will ensure that waste fluids remain within the disposal interval and ensure appropriate operation of the field. 11. Increasing the distance between the packer and top of the disposal zone perforations will not compromise well integrity, so long as the top of production casing cement is at least 300' MD above the packer. Disposal Injection Order 42 October 24, 2018 Page 5 of 7 12. Hilcorp estimates a plume radius of about 1,880' for each disposal well over the 17 -year expected project life. 13. Future wells within 1/2 -mile of the proposed injection interval in each of the disposal wells must be constructed to ensure they do not serve as a conduit for fluid migration from the disposal zone. 14. The proposed Ugnu disposal interval is not isolated by cement from the underlying Schrader Bluff in the Simpson Lagoon 32-14 well. No disposal well should be drilled within 3,000' of Simpson Lagoon 32-14 until Hilcorp demonstrates confinement and well integrity issues have been resolved. NOW, THEREFORE, IT IS ORDERED THAT the following rules, in addition to statewide requirements under AS 31.05 and 20 AAC 25 (to the extent not superseded by these rules), govern Class II disposal injection operations into the Ugnu within up to four wells drilled from MPU Moose Pad: RULE 1: Infection Strata for Disposal Underground disposal of Class II oil field waste fluids is permitted into the Ugnu Formation in the interval that is common to, and correlative with, the interval from 3,282' to 3,912' MD (-2,714' to -3,187' TVDSS) in well MPU M-0 1. RULE 2: Authorized Fluids This authorization is limited to Class II oil field waste fluids generated during drilling, production, workover, or abandonment operations, including: Drilling fluids; drill cuttings; well workover fluids; stimulation fluids and solids; produced water; rig wash water; formation materials; naturally occurring radioactive materials; scale; tracer materials; glycol dehydration; reserve pit fluids; chemicals used in the well or for production processing at the surface (in direct contact with produced fluids); and precipitation accumulating in drilling and production impoundment areas. The eligibility of other fluids for Class II waste disposal injection will be considered by the AOGCC on a case-by-case basis upon application by the operator. AOGCC approval is required prior to initiating commercial Class II disposal injection. RULE 3: Infection Rate and Pressure Injection rates and pressures must be maintained such that the injected fluids will not initiate or propagate fractures through the confining intervals or migrate out of the approved injection stratum. Disposal injection is authorized at rates that do not exceed 35,000 BPD per well and wellhead injection pressures that do not exceed 2,500 psig. RULE 4: Demonstration of Mechanical Integrity An AOGCC-witnessed mechanical integrity test must be performed after injection is commenced for the first time in the well, to be scheduled when injection conditions (temperature, pressure, Disposal Injection Order 42 October 24, 2018 Page 6 of 7 rate, etc.) have stabilized. Subsequent mechanical integrity tests must be performed at least once every two years after the date of the first AOGCC-witnessed test if the well injects solids laden slurries, and at least once every four years if the well only injects solids -free fluids. RULE 5: Well Inteerity Failure and Confinement The Operator shall immediately shut in the well if continued operation would be unsafe or threaten contamination of freshwater, or if so directed by the AOGCC. If fluids are found to be fracturing through a confining interval or migrating out of the approved injection stratum, the operator must immediately shut in the well. Upon discovery of such an event, the operator must immediately notify the AOGCC, provide details of the operation, and propose actions to prevent recurrence. Injection may not be restarted unless approved by the AOGCC. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the AOGCC if the well indicates any well integrity failure or lack of injection zone isolation. The AOGCC may immediately suspend, revoke, or modify this authorization if injected fluids fail to be confined to the approved disposal interval. No disposal well may be drilled within 3,000' of the Simpson Lagoon 32-14 until existing confinement and well integrity issues have been resolved for that well. To facilitate through -tubing access to the entire requested disposal zone, packers in the disposal wells may be located more than 200' MD above the top of the disposal zone; however, packers shall not be located above the confining zone. In cases where the packer distance is more than 200' above the disposal zone, the production casing cement volume should be sufficient to place cement a minimum of 300' MD above the planned packer depth. RULE 6: Surveillance The operator shall run a baseline temperature log and perform a baseline step -rate test prior to initial injection. A subsequent temperature log must be run one month after injection begins to delineate the receiving zone of the injected fluids. Hilcorp shall perform an annual reservoir pressure survey of the disposal zone. Surface pressures and rates must be monitored continuously during injection for any indications of anomalous conditions. Results of daily wellhead pressure observations must be documented and available to the AOGCC upon request. The conduct of subsequent temperature surveys or other surveillance logging (e.g., water flow; acoustic) will be based on the results of the initial and follow-up temperature surveys and injection performance monitoring data. The annual report of underground injection (Form 10-413) shall also include data sufficient to characterize the disposal operation, including, among other information, the following: injection and annuli pressures (i.e., daily average, maximum, and minimum pressures); fluid volumes injected (i.e., in disposal and clean fluid sweeps); injection rates; an assessment of the fracture geometry; a description of any anomalous injection results; a calculated zone of influence for the injected fluids; and an assessment of the applicability of the disposal order findings, conclusions, and rules based on actual performance. The annual report shall also include a section titled "Induced Seismicity" in which Hilcorp shall detail its monitoring efforts and evaluate the risks. Disposal Injection Order 42 October 24, 2018 Page 7 of 7 RULE 7: Notification of Improper Class II Iniection Injection of fluids other than those listed in Rule 2 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. Additionally, notification or other legal requirements of any other State or Federal agency remain the operator's responsibility. RULE 8: Administrative Action Upon proper application, or its own motion, and unless notice and public hearing are otherwise required, the AOGCC may administratively waive the requirements of any rule stated herein or administratively amend this order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater or outside of the authorized injection zone. DONE at Anchorage, Alaska, and dated October 24, 2018. Hollis S. French Chair, Commissioner Daniel T. Seamount, Jr Commissioner Cathy . Fc Commissio 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 tiled within 33 days after the date on which the AOGCC mails, OR 30 days if One 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 las[ 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 nest day' that does not fall on a weekend or state holiday. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7' Avenue Anchorage, Alaska 99501 Re: THE APPLICATION OF Hilcorp Alaska, LLC. for disposal of Class II oil field wastes by underground injection in the Ugnu Formation in up to four wells located on the Moose Pad in the northwest portion of the Milne Point Unit Sections 12, 13, 14, 23, 24, TI 3N, R9E, and Sections 7, 18, 19, T13N, R10E S.M. IT APPEARING THAT: Disposal Injection Order No. 42 Docket No. DIO-18-001 Ugnu Formation, Disposal Pool Milne Point Unit October 24, 2018 Undefined Waste 1. Hilcorp Alaska, LLC (Hilcorp) requested authorization for underground disposal of Class 11 oil field waste fluids into up to four yet to be drilled wells (Class lI wells) on the Moose Pad in the northwest portion of the Milne Point Unit (MPU). Hilcorp's Application for Disposal Injection Order (DIO) was received by the Alaska Oil and Gas Conservation Commission (AOGCC) on July 20, 2018. 2. Pursuant to 20 AAC 25.540, the AOGCC scheduled a public hearing for September 5, 2018. On July 24, 2018, the AOGCC published notice of the opportunity for that hearing on the State of Alaska's Online Public Notice website and on the AOGCC's website, and electronically transmitted the notice to all persons on the AOGCC's email distribution list. On July 25, 2018, the notice was published in the ANCHORAGE DAILY NEWS. 3. At the September 5, 2018 hearing Hilcorp provided testimony and presented evidence in support of its Application. The record was closed at the end of the hearing. 4. The information submitted by Hilcorp and public records for MPU wells are the basis for this order. FINDINGS: 1. Location of Adjacent Wells (20 AAC 25.252(c)(1)) There are no active wells within the'/4-mile area of review surrounding the disposal intervals for the proposed Class Il wells. The plugged and abandoned Simpson Lagoon 32-14 well lies within '/4 mile of one proposed Class 11 well in the disposal interval. Future production and injection wells drilled from the Moose Pad may pass within %4 mile of the proposed Class II disposal wells. Disposal Injection Order 42 October 24, 2018 Page 2 of 7 2. Notification of Operators/Surface Owners (20 AAC 25.252(c)(2) and 20 AAC 25.252(c)(3)) Hilcorp is the only operator and the State of Alaska, Alaska Department of Natural Resources (ADNR) is the only surface owner within'/4-mile radius of the proposed disposal wells. Hilcorp provided AOGCC a copy of an affidavit affirming that ADNR was provided a copy of the DIO application. 3. Geoloeical Information on Disposal and Confining Zones (20 AAC 25.252(c)(4)) The proposed disposal injection operations will affect strata that are assigned to the lower Tertiary -aged Ugnu Formation (Ugnu). In Moose Pad area, the Ugnu consists of predominately discrete, coarse-grained, moderate to well -sorted, fluvial/deltaic, wet sands with average porosity of 30-32% and average permeability of 1,000 millidarcies. On the MPU M-01 type log, these clean sands are bounded by impermeable siltstones and mudstones. Hilcorp plans injection within the permeable upper Ugnu sands between the informal MP_LC and the MP UG15 geologic markers from 3,282' measured depth (MD, equivalent to -2,714' true vertical depth subsea, or TVDSS) to 3,912' MD (-3,187' TVDSS). Upper confinement for the proposed injection interval consists of laterally continuous layers ofmudstone, siltstone, and coal that lie within the Ugnu between 2,854' (-2,413' TVDSS) and 3,282' MD (-2,714' TVDSS) in MPU M-01. These confining layers, which range in true vertical thickness (thickness) from 10' to 45' and have a combined thickness of about 90', will serve as effective barriers to prevent vertical migration of injected fluids. Lower confinement will be provided by laterally continuous layers of mudstone, siltstone and coal within the upper Ugnu between 3,912' MD (-3,187' TVDSS) and 4,033' MD (-3,280' TVDSS). These impermeable intervals range from l V to 15' in thickness and have a combined thickness of 40'. The proposed disposal well area is partially bound to the east and west by north -south oriented faults with significantly less displacement than the thickness of the entire proposed injection interval. 4. Evaluation of Fluid Confinement (20 AAC 25.252(c)(9)) The porous and permeable nature of the wet, upper Ugnu sands allows injection of produced water at pressures that are lower than Hilcorp's stated formation -fracture pressure limit of 2,500 psi for unconsolidated sands. Future wells within 1/4 -mile must be constructed to ensure they do not serve as a conduit for fluid migration from the disposal zone. 5. Aquifer Exemption (20 AAC 25.252(c)(11)); Standard Laboratory Water Analysis of the Formation (20 AAC 25.252(c)(10)) Aquifer Exemption Order No. 2 governs the four potential Class 11 well locations near Moose Pad. Hilcorp does not have a water sample from the proposed disposal intervals in this area. Hilcorp provided information representing that it is cost -prohibitive to use subsurface aquifers near Moose Pad as a source of drinking water. 6. Well Loas (20 AAC 25.252(c)(5)) Log data from existing wells near Moose Pad are on file with the AOGCC. The representative well, MPU M-01, has a complete set of logs. Disposal Injection Order 42 October 24, 2018 Page 3 of 7 7. Demonstration of Mechanical Integrity and Disposal Zone Isolation (20 AAC 25.252(c)(6)) The proposed casing program is 10 -3/4 -inch surface casing set at 2,100' TVD and cemented to surface. A formation Integrity Test will be performed to 12.5 ppg equivalent and the production hole drilled. Production 7 -5/8 -inch casing will be set to 3,300' TVD and cemented to approximately 2,100' TVD and tested to 2,500 psi. A cement bond log will be run to confirm the cement top and that casing strings have adequate cement to prevent vertical migration of disposal fluids. Hilcorp requests packers be located more than 200' MD above the top of the disposal perforations. This will allow through -tubing access to the entire requested disposal zone. Tubing or other equipment will be designed and installed in accordance with 20 AAC 25.412. A casing mechanical integrity test will be performed in accordance with 20 AAC 25.412 prior to initiation of disposal operations. Hilcorp will perform mechanical integrity tests of the tubing and tubing -casing annulus (including packer) as part of the operations before disposal injection commences. Additional baseline assessments and subsequent evaluations may be necessary to confirm the wells have the proper mechanical integrity for disposal injection as proposed. Hilcorp will monitor the 7 -5/8 -inch casing by 5 -1/2 -inch tubing annulus pressure daily and report the results on the Monthly Injection Report. 8. Disposal Fluid Type, Composition, Source, Volume, and Compatibility with Disposal Zone (20 AAC 25.252(c)(7)) Hilcorp requests approval to dispose of drilling, production, completion, workover wastes, and other associated wastes that are intrinsically derived from primary field operations. Hilcorp expects daily injection volumes of a maximum of 36,000 barrels for the first well, up to a cumulative 72,000 barrels with the proposed two wells. Over the expected 17 -year life of the project, Hilcorp expects to dispose of approximately 355 million barrels of liquids. This equates approximately to a plume of about 1,880' assuming a 300 -foot thickness, radial flow, and 100% pore -space displacement around each of the two planned disposal wells. Injected fluids are expected to be compatible with the lithology and in-situ formation water of the proposed disposal injection zone based on operating experience and past performance of MPU Class I disposal wells B-24, B-34 and B-50 (e.g., pressures, rates, and volumes). No compatibility issues have been reported associated with disposal injection into the Ugnu at Milne Point or other fields on the North Slope. 9. Estimated Iniection Pressures (20 AAC 25.252(c)(8)) Hilcorp estimates average surface injection pressure will range from 2,000 to 2,300 psig while injecting 27,000 barrels per day per well for two wells. Maximum surface injection pressure could reach 2,500 psig if sporadic plugging of perforations or fracture -flow channels occurs. Accordingly, Hilcorp requested 2,500 prig as maximum allowed surface injection pressure. Disposal Injection Order 42 October 24, 2018 Page 4 of 7 10. Mechanical Condition of Wells Penetrating the Disposal Zone Within a %4 -Mile Radius of Kenai Loop #3 (20 AAC 25.252(c)(12)) Simpson Lagoon 32-14 is the only well to penetrate the proposed disposal injection zone within a'/4 -mile radius of the four proposed disposal wells. Well construction records show that this well is properly plugged and abandoned; however, there is no cement across the lower proposed Ugnu disposal zone or the underlying sands assigned to the Schrader Bluff Oil Pool (Schrader Bluff), and only partial cement across the upper Ugnu disposal zone. Hilcorp's application states the cement plugs in the production casing across the surface casing shoe will prevent upward fluid movement from the Ugnu disposal zone in this well. CONCLUSIONS: I . The requirements of 20 AAC 25.252 for approval of an underground disposal application are met. 2. AEO No. 2 exempts the proposed Moose Pad disposal area for Class 11 injection activities only. 3. Hilcorp's plan to drill two disposal wells initially with another two wells as backup contingencies is a prudent approach for the MPU Moose Pad development. 4. Hilcorp's planned injection interval consists of poorly consolidated, porous and permeable Ligon sands that lie from approximately 3,282' to 3,912' MD (-2,714' to -3,187' TVDSS), an interval that is about 473' thick with approximately 342' of net sand. 5. Upper confinement will be provided by a combined 90' of laterally continuous layers of mudstone, siltstone, and coal that lie within the Ugnu. 6. Lower confinement will be provided by laterally continuous layers of upper Ugnu mudstone, siltstone and coal that have a combined thickness of 40'. 7. No significant faults are present that could affect the proposed injection operations. 8. No compatibility issues have been reported associated with disposal injection into the Ugnu at Milne Point or other fields on the North Slope. 9. Fracture modeling indicates that disposed waste fluids will be contained within the receiving interval by confining lithologies, cement isolation of the well bore, and planned operating conditions. Modeling of rates up to 35,000 BPD per well predicts that fractures will not penetrate the upper confining zone or breach the lower confining zone. 10. Supplemental mechanical integrity demonstrations and regularly scheduled surveillance of injection operations—including baseline and subsequent temperature surveys, monitoring of injection performance (i.e., pressures and rates), and analyses of the data for indications of anomalous events—will ensure that waste fluids remain within the disposal interval and ensure appropriate operation of the field. 11. Increasing the distance between the packer and top of the disposal zone perforations will not compromise well integrity, so long as the top of production casing cement is at least 300' MD above the packer. Disposal Injection Order 42 October 24, 2018 Page 5 of 7 12. Hilcorp estimates a plume radius of about 1,880' for each disposal well over the 17 -year expected project life. 13. Future wells within 1/2 -mile of the proposed injection interval in each of the disposal wells must be constructed to ensure they do not serve as a conduit for fluid migration from the disposal zone. 14. The proposed Ugnu disposal interval is not isolated by cement from the underlying Schrader Bluff in the Simpson Lagoon 32-14 well. No disposal well should be drilled within 3,000' of Simpson Lagoon 32-14 until Hilcorp demonstrates confinement and well integrity issues have been resolved. NOW, THEREFORE, IT IS ORDERED THAT the following rules, in addition to statewide requirements under AS 31.05 and 20 AAC 25 (to the extent not superseded by these rules), govern Class 11 disposal injection operations into the Ugnu within up to four wells drilled from MPU Moose Pad: RULE 1: Infection Strata for Disposal Underground disposal of Class 11 oil field waste fluids is permitted into the Ugnu Formation in the interval that is common to, and correlative with, the interval from 3,282' to 3,912' MD (-2,714' to -3,187' TVDSS) in well MPU M-01. RULE 2: Authorized Fluids This authorization is limited to Class 11 oil field waste fluids generated during drilling, production, workover, or abandonment operations, including: Drilling fluids; drill cuttings; well workover fluids; stimulation fluids and solids; produced water; rig wash water; formation materials; naturally occurring radioactive materials; scale; tracer materials; glycol dehydration; reserve pit fluids; chemicals used in the well or for production processing at the surface (in direct contact with produced fluids); and precipitation accumulating in drilling and production impoundment areas. The eligibility of other fluids for Class It waste disposal injection will be considered by the AOGCC on a case-by-case basis upon application by the operator. AOGCC approval is required prior to initiating commercial Class Il disposal injection. RULE 3: Iniection Rate and Pressure Injection rates and pressures must be maintained such that the injected fluids will not initiate or propagate fractures through the confining intervals or migrate out of the approved injection stratum. Disposal injection is authorized at rates that do not exceed 35,000 BPD per well and wellhead injection pressures that do not exceed 2,500 psig. RULE 4: Demonstration of Mechanical Integrity An AOGCC-witnessed mechanical integrity test must be performed after injection is commenced for the first time in the well, to be scheduled when injection conditions (temperature, pressure, Disposal Injection Order 42 October 24, 2018 Page 6 of 7 rate, etc.) have stabilized. Subsequent mechanical integrity tests must be performed at least once every two years after the date of the first AOGCC-witnessed test if the well injects solids laden slurries, and at least once every four years if the well only injects solids-free fluids. RULE 5: Well Integrity Failure and Confinement The Operator shall immediately shut in the well if continued operation would be unsafe or threaten contamination of freshwater, or if so directed by the AOGCC. If fluids are found to be fracturing through a confining interval or migrating out of the approved injection stratum, the operator must immediately shut in the well. Upon discovery of such an event, the operator must immediately notify the AOGCC, provide details of the operation, and propose actions to prevent recurrence. Injection may not be restarted unless approved by the AOGCC. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the AOGCC if the well indicates any well integrity failure or lack of injection zone isolation. The AOGCC may immediately suspend, revoke, or modify this authorization if injected fluids fail to be confined to the approved disposal interval. No disposal well may be drilled within 3,000' of the Simpson Lagoon 32-14 until existing confinement and well integrity issues have been resolved for that well. To facilitate through-tubing access to the entire requested disposal zone, packers in the disposal wells may be located more than 200' MD above the top of the disposal zone; however, packers shall not be located above the confining zone. In cases where the packer distance is more than 200' above the disposal zone, the production casing cement volume should be sufficient to place cement a minimum of 300' MD above the planned packer depth. RULE 6: Surveillance The operator shall run a baseline temperature log and perform a baseline step-rate test prior to initial injection. A subsequent temperature log must be run one month after injection begins to delineate the receiving zone of the injected fluids. Hilcorp shall perform an annual reservoir pressure survey of the disposal zone. Surface pressures and rates must be monitored continuously during injection for any indications of anomalous conditions. Results of daily wellhead pressure observations must be documented and available to the AOGCC upon request. The conduct of subsequent temperature surveys or other surveillance logging (e.g., water flow; acoustic) will be based on the results of the initial and follow-up temperature surveys and injection performance monitoring data. The annual report of underground injection (Form 10-413) shall also include data sufficient to characterize the disposal operation, including, among other information, the following: injection and annuli pressures (i.e., daily average, maximum, and minimum pressures); fluid volumes injected (i.e., in disposal and clean fluid sweeps); injection rates; an assessment of the fracture geometry; a description of any anomalous injection results; a calculated zone of influence for the injected fluids; and an assessment of the applicability of the disposal order findings, conclusions, and rules based on actual performance. The annual report shall also include a section titled "Induced Seismicity" in which Hilcorp shall detail its monitoring efforts and evaluate the risks. Disposal Injection Order 42 October 24, 2018 Page 7 of 7 RULE 7: Notification of Improper Class II Infection Injection of fluids other than those listed in Rule 2 without prior authorization is considered improper Class 11 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. Additionally, notification or other legal requirements of any other State or Federal agency remain the operator's responsibility. RULE 8: Administrative Action Upon proper application, or its own motion, and unless notice and public hearing are otherwise required, the AOGCC may administratively waive the requirements of any rule stated herein or administratively amend this order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater or outside of the authorized injection zone. DONE at Anchorage, Alaska, and dated October 24, 2018. 1�,, otL,typ H //signature on file// //signature on file// //signature on file//" Hollis S. French Daniel T. Seamount, Jr. Cathy P. Foerster Chair, Commissioner Commissioner Commissioner AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 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 ofthe event or default after which the designated period begins to run is not included in the period, the Iasi 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.in on the next day that does not fall on a weekend or stale holiday. Bernie Karl Gordon Severson Penny Vadla K&K Recycling Inc. 3201 Westmar Cir. 399 W. Riverview Ave. P.O. Box 58055 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Fairbanks, AK 99711 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 THE STATE °fALASKA GOVERNOR BILL WALKER Mr. Reid Edwards Reservoir Engineer Hilcorp Alaska, LLC. 3800 Centerpoint Drive Anchorage, AK 99503 Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL DISPOSAL INJECTION ORDER NO. 42.001 Re: Docket Number: DIO-18-003 333 West 7th Avenue Anchorage, Alaska 99501 Main: 907.297.1433 Fax: 907.276.7542 www.cogcc.olaska.gov Request for administrative approval to amend Rule 3 and Rule 5 of Disposal Injection Order (DIO) 42. Milne Point Unit (MPU) Moose Pad Dear Mr. Edwards: By letter dated November 5, 2018, Hilcorp Alaska, Inc. (Hilcorp) requested administrative approval to amend Rule 3 to increase the maximum disposal volume from 35,000 to 45,000 barrels per day (BPD) per well based on a clarification of the Nodal Analysis Plot interpretation and amend Rule 5 based on a new three disposal well scenario. In support of the application to amend Rule 3, Hilcorp has referenced the Nodal Analysis Plot included in the DIO application and presented at the DIO hearing that shows the requested 2,500 psi wellhead pressure is equivalent to a bottom hole pressure of 2,300 psi at 78,000 BPD. Increasing the maximum daily volume from 35,000 BPD per well to 45,000 BPD per well will allow Hilcorp greater operational efficiencies during periods of peak disposal requirements. The 45,000 BPD per well coupled with a maximum wellhead injecting pressure of 2,500 psig will keep injection below the fracture pressure at the sandface, resulting in the confinement of injected fluids to the permitted interval. In support of the application to amend Rule 5, Hilcorp has proposed a three disposal well scenario and an associated per well maximum disposal volume. This new volume can be used to determine the well waste plume radii and includes a safety factor to accommodate a potential preferential elliptical plume spreading towards the Simpson Lagoon 32-14 well. Based on this new volume and radii calculation including the application of the safety factor, Hilcorp claims that a minimum separation distance of 1550' at disposal well #2 location (75,381,295 bbl) and 1590' at disposal well #I location (79,322,144 bbl) can be achieved. DIO 42.001 November 26, 2018 Page 2 of 3 In accordance with Rule 8 of DIO 42.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS Hilcorp's request for administrative approval to increase the maximum allowable injection rate from 35,000 to 45,000 BPD per well as long as the wellhead injection pressure stays below the established 2,500 psig, and reduce the well spacing restriction from 3,000' to 1,550' to account for the reduction of volumes per well based on a new three disposal well scenario. NOW THEREFORE IT IS ORDERED THAT: Rule 3 of DIO 42.000 is repealed and replaced by the following: RULE 3: Injection Rate and Pressure Injection rates and pressures must be maintained such that the injected fluids will not initiate or propagate fractures through the confining intervals or migrate out of the approved injection stratum. Disposal injection is authorized at rates that do not exceed 45,000 BPD per well and wellhead injection pressures that do not exceed 2,500 psig. Rule 5 of DIO 42.000 is repealed and replaced by the following: RULE 5: Well Inteeritv Failure and Confinement The Operator shall immediately shut in the well if continued operation would be unsafe or threaten contamination of freshwater, or if so directed by the AOGCC. If fluids are found to be fracturing through a confining interval or migrating out of the approved injection stratum, the operator must immediately shut in the well. Upon discovery of such an event, the operator must immediately notify the AOGCC, provide details of the operation, and propose actions to prevent recurrence. Injection may not be restarted unless approved by the AOGCC. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the AOGCC if the well indicates any well integrity failure or lack of injection zone isolation. The AOGCC may immediately suspend, revoke, or modify this authorization if injected fluids fail to be confined to the approved disposal interval. Based on a three disposal well scenario, no disposal well may be drilled within 1,550' of the Simpson Lagoon 32-14 until existing confinement and well integrity issues have been resolved for that well. To facilitate through -tubing access to the entire requested disposal zone, packers in the disposal wells may be located more than 200' MD above the top of the disposal zone; however, packers shall not be located above the confining zone. In cases where the packer distance is more than 200' above the disposal zone, the production casing cement volume should be sufficient to place cement a minimum of 300' MD above the planned packer depth. DIO 42.001 November 26, 2018 Page 3 of 3 DONE at Anchorage, Alaska and dated November 26, 2018. Hollis French Chair, Commissioner Daniel T. Seamount, Jr. Commissioner AND 04 Cath . Foerster Co issioner 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. THE STATE °fALASKA (10VERNOR BILL WALSFR Mr. Reid Edwards Reservoir Engineer Hilcorp Alaska, LLC. 3800 Centerpoint Drive Anchorage, AK 99503 Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL DISPOSAL INJECTION ORDER NO. 42.001 Re: Docket Number: DIO-18-003 333 West Seventh Avenue Anchorage. Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 oogcc.olaska.gov Request for administrative approval to amend Rule 3 and Rule 5 of Disposal Injection Order (DIO) 42. Milne Point Unit (MPU) Moose Pad Dear Mr. Edwards: By letter dated November 5, 2018, Hilcorp Alaska, Inc. (Hilcorp) requested administrative approval to amend Rule 3 to increase the maximum disposal volume from 35,000 to 45,000 barrels per day (BPD) per well based on a clarification of the Nodal Analysis Plot interpretation and amend Rule 5 based on a new three disposal well scenario. In support of the application to amend Rule 3, Hilcorp has referenced the Nodal Analysis Plot included in the DIO application and presented at the DIO hearing that shows the requested 2,500 psi wellhead pressure is equivalent to a bottom hole pressure of 2,300 psi at 78,000 BPD. Increasing the maximum daily volume from 35,000 BPD per well to 45,000 BPD per well will allow Hilcorp greater operational efficiencies during periods of peak disposal requirements. The 45,000 BPD per well coupled with a maximum wellhead injecting pressure of 2,500 psig will keep injection below the fracture pressure at the sandface, resulting in the confinement of injected fluids to the permitted interval. In support of the application to amend Rule 5, Hilcorp has proposed a three disposal well scenario and an associated per well maximum disposal volume. This new volume can be used to determine the well waste plume radii and includes a safety factor to accommodate a potential preferential elliptical plume spreading towards the Simpson Lagoon 32-14 well. Based on this new volume and radii calculation including the application of the safety factor, Hilcorp claims that a minimum separation distance of 1550' at disposal well #2 location (75,381,295 bbl) and 1590' at disposal well 41 location (79,322,144 bbl) can be achieved. D10 42.001 November 26, 2018 Page 2 of 3 In accordance with Rule 8 of DIO 42.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS Hilcorp's request for administrative approval to increase the maximum allowable injection rate from 35,000 to 45,000 BPD per well as long as the wellhead injection pressure stays below the established 2,500 psig, and reduce the well spacing restriction from 3,000' to 1,550' to account for the reduction of volumes per well based on a new three disposal well scenario. NOW THEREFORE IT IS ORDERED THAT: Rule 3 of DID 42.000 is repealed and replaced by the following: RULE 3: Infection Rate and Pressure Injection rates and pressures must be maintained such that the injected fluids will not initiate or propagate fractures through the confining intervals or migrate out of the approved injection stratum. Disposal injection is authorized at rates that do not exceed 45,000 BPD per well and wellhead injection pressures that do not exceed 2,500 psig. Rule 5 of DIO 42.000 is repealed and replaced by the following: RULE 5: Well Integrity Failure and Confinement The Operator shall immediately shut in the well if continued operation would be unsafe or threaten contamination of freshwater, or if so directed by the AOGCC. If fluids are found to be fracturing through a confining interval or migrating out of the approved injection stratum, the operator must immediately shut in the well. Upon discovery of such an event, the operator must immediately notify the AOGCC, provide details of the operation, and propose actions to prevent recurrence. Injection may not be restarted unless approved by the AOGCC. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the AOGCC if the well indicates any well integrity failure or lack of injection zone isolation. The AOGCC may immediately suspend, revoke, or modify this authorization if injected fluids fail to be confined to the approved disposal interval. Based on a three disposal well scenario, no disposal well may be drilled within 1,550' of the Simpson Lagoon 32-14 until existing confinement and well integrity issues have been resolved for that well. To facilitate through -tubing access to the entire requested disposal zone, packers in the disposal wells may be located more than 200' MD above the top of the disposal zone; however, packers shall not be located above the confining zone. In cases where the packer distance is more than 200' above the disposal zone, the production casing cement volume should be sufficient to place cement a minimum of 300' MD above the planned packer depth. D10 42.001 November 26, 2018 Page 3 of 3 DONE at Anchorage. Alaska and dated November 26, 2018. //signature on file// //signature on file// //signature on file// Hollis French Daniel T. Seamount, Jr. Cathy 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 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 ran is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Bernie Karl K&K Recycling Inc. Gordon Severson Penny Vadla 3201 Westmar Cir. 399 W. Riverview Ave. P.O. Box 58055 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Fairbanks, AK 99711 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 TI IE STATE "ALASKA Alaska Oil and Gas Conservation Commission GONT:RNOR MICHAEL I. DUNIYAV Y 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.olaska.gov ADMINISTRATIVE APPROVAL DISPOSAL INJECTION ORDER NO. 42.002 Ms. Amy Peloza Waste Environmental Specialist Mr. Wyatt Rivard Well Integrity Engineer Hilcorp Alaska, LLC. 3800 Centerpoint Drive Anchorage, AK 99503 Re: Docket Number: DIO-18-005 Request for administrative approval to amend Rule 2 of Disposal Injection Order (DIO) 42. Milne Point Unit (MPU) Moose Pad Dear Ms. Peloza and Mr. Rivard: By email dated October 29, 2018, Hilcorp Alaska, Inc. (Hilcorp) requested administrative approval to amend Rule 2 to include disposal of excess or unused Prince Creek Formation source water and well freeze protection fluids including from source water wells. In support of the application to amend Rule 2, Hilcorp has provided their revised well drilling schedule and implemented equipment changes to minimize the duration and volumes of source water routed for disposal. As enhanced oil recovery (EOR) injectors become operational, the source water will be allocated to the EOR wells and disposal of source water will be reduced and ultimately limited to periods of plant upsets and restarts. In accordance with Rule 8 of DIO 42.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS Hilcorp's request for administrative approval to include disposal of excess or unused Prince Creek Formation source water and well freeze protection fluids including from source water wells. DIO 42.002 January 14, 2019 Page 2 of 2 NOW THEREFORE IT IS ORDERED THAT: Rule 2 of DIO 42.000 is repealed and replaced by the following: RULE 2: Authorized Fluids This authorization is limited to Class II oil field waste fluids generated during drilling, production, workover, or abandonment operations, including: Drilling fluids; drill cuttings; well workover fluids; stimulation fluids and solids; produced water; rig wash water; formation materials; naturally occurring radioactive materials; scale; tracer materials; glycol dehydration; reserve pit fluids; chemicals used in the well or for production processing at the surface (in direct contact with produced fluids); excess or unused Prince Creek Formation source water; well freeze protection fluids including from source water wells; and precipitation accumulating in drilling and production impoundment areas. The eligibility of other fluids for Class II waste disposal injection will be considered by the AOGCC on a case-by-case basis upon application by the operator. AOGCC approval is required prior to initiating commercial Class II disposal injection. DONE at Anchorage, Alaska and dated January 14, 2019. //signature on file// Hollis French Chair, Commissioner //signature on file// Cathy P. Foerster Commissioner 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 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 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 ran is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL DISPOSAL INJECTION ORDER NO. 42.002 Ms. Amy Peloza Waste Environmental Specialist Mr. Wyatt Rivard Well Integrity Engineer Hilcorp Alaska, LLC. 3800 Centerpoint Drive Anchorage, AK 99503 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 w .aogcc.alaska.gov Re: Docket Number: DIO-18-005 Request for administrative approval to amend Rule 2 of Disposal Injection Order (DIO) 42. Milne Point Unit (MPU) Moose Pad Dear Ms. Peloza and Mr. Rivard: By email dated October 29, 2018, Hilcorp Alaska, Inc. (Hilcorp) requested administrative approval to amend Rule 2 to include disposal of excess or unused Prince Creek Formation source water and well freeze protection fluids including from source water wells. In support of the application to amend Rule 2, Hilcorp has provided their revised well drilling schedule and implemented equipment changes to minimize the duration and volumes of source water routed for disposal. As enhanced oil recovery (EOR) injectors become operational, the source water will be allocated to the EOR wells and disposal of source water will be reduced and ultimately limited to periods of plant upsets and restarts. In accordance with Rule 8 of DIO 42.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS Hilcorp's request for administrative approval to include disposal of excess or unused Prince Creek Formation source water and well freeze protection fluids including from source water wells. DIO 42.002 January 14, 2019 Page 2 of 2 NOW THEREFORE IT IS ORDERED THAT: Rule 2 of DIO 42.000 is repealed and replaced by the following: RULE 2: Authorized Fluids This authorization is limited to Class II oil field waste fluids generated during drilling, production, workover, or abandonment operations, including: Drilling fluids; drill cuttings; well workover fluids; stimulation fluids and solids; produced water; rig wash water; formation materials; naturally occurring radioactive materials; scale; tracer materials; glycol dehydration; reserve pit fluids; chemicals used in the well or for production processing at the surface (in direct contact with produced fluids); excess or unused Prince Creek Formation source water; well freeze protection fluids including from source water wells; and precipitation accumulating in drilling and production impoundment areas. The eligibility of other fluids for Class II waste disposal injection will be considered by the ACIGCC on a case-by-case basis upon application by the operator. ACIGCC approval is required prior to initiating commercial Class II disposal DONE at Anchorage, Alaska and dated January 14, 2019. �-_��� " - Hollis French Chair, Commissioner Cathy . Foerster Co issioner 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 maybe 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. 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 Wallace, Chris D (DOA) From: Amy Peloza <apeloza@hilcorp.com> Sent: Monday, December 17, 2018 2:56 PM To: Wallace, Chris D (DOA) Subject: RE: [EXTERNAL] RE: DIO-42 Authorized Fluids Chris— Thanks very much for the phone call with Wyatt and myself last week. The planned drilling schedule through approximately July 2019 is as follows: 1. Disposal well — December 2018 2. Production well — December 2018 3. Production well —January 2019 4. EOR well — February 2019 5. Water source well — March 2019 6. Production well — March 2019 7. EOR well —April 2019 8. Disposal well — May 2019 9. EOR well — May 2019 10. Production well —June 2019 11. EOR well —July 2019 As discussed, a recycle loop is planned to be installed in the Moose Pad source water system in conjunction with a downsized source water Electric Submersible Pump designed for 3,000 —12,000 bopd (formerly 15,000 — 35,000 bopd). The recycle loop will allow the surface EOR injection pump (minimum turndown rate of 13,000 bpd) to maintain its minimum rate without the source water well needing to produce at a significantly higher rate than what the initial EOR injection capacity will be. Downsizing the ESP and installing the recycle loop will minimize the excess water routed to disposal. From March —July 2019, Hilcorp expects to potentially dispose of up to 3,000 bbls of source water per day. As additional EOR wells are brought online from April to July, water will be used for EOR rather than routed for disposal. Once the fourth EOR well is online in July, Hilcorp expects to no longer use the disposal well for source water, with the exception of plant upset events. When plant upsets occur and the pad is re -started, it is possible for some source water to be disposed of. Please contact me with questions or additional information. Thank you, Amy Peloza Waste Environmental Specialist IIHilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 (907) 777-8348 - office (907) 317-0521 - cell Email: apeloza@hilcorp.com From: Amy Peloza Sent: Tuesday, November 27, 2018 11:15 AM To: 'chris.wallace@alaska.gov' <chris.wallace@alaska.gov> Subject: RE: [EXTERNAL] RE: DIO-42 Authorized Fluids Hi Chris - Hope you had a good holiday. I wanted to check on status of this request (#2 below)? Thanks, Amy Peloza Waste Environmental Specialist IlHilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 (907) 777-8348 - office (907) 317-0521 - cell Email: apelozaccbhilcorp.com From: Amy Peloza Sent: Friday, November 16, 2018 3:25 PM To: 'chris.wallace@alaska.gov' <chris.wallacePalaska.aov> Subject: RE: [EXTERNAL] RE: DIO-42 Authorized Fluids Hi Chris - I'm picking up this conversation to ensure that Hilcorp is consistent across its operations with regard to waste determinations. We've reviewed the current drilling and operations plans and your notes below, and offer some clarifications and/or interpretations. Your responses are in italics; and mine are in blue font. Of the four waste streams initially presented, Hilcorp just requests well freeze protection fluids, including those from source water wells, to be added to DIO 42. 1. Excess or unused Prince Creek Formation source water. If it was originally sourced for the E&P purpose (not produced with the sole intent for disposal which would be considered waste), and Hilcorp can show it was an unplanned event that would not be considered a normal/frequent occurrence, and assuming it would be comingled with produced water prior to disposal this would be acceptable. Or if it was produced for the sole purpose of treating an eligible Class Il fluid (i.e., thinning it or getting sufficient volume for pump charge) and assuming it would be comingled with produced water prior to disposal this would be acceptable. It would be better stored and used for EOR, or shut in the well. We would need to know volume and frequency and why this cannot go to the Class I disposal. When Hilcorp originally submitted the permit application, the Class II well was to be drilled after the source water well. Our interpretation was that the source water is neither a listed nor characteristic hazardous waste, and that the activity is intrinsic to exploration, development or production operations. However, Hilcorp will be sending produced water from F and L Pads, and the source water well will be drilled later. Source water and produced water will be commingled. Hilcorp doesn't expect excess or unused Prince Creek Formation source water as the sole injectant into the Class II well prior to drilling and production operations starting. Hilcorp no longer requests clarification or modification to Rule 2 with regard to excess or unused Prince Creek Formation source water. 2. Well freeze protection fluids including from source water wells. Acceptable once circulated down oil and gas wells. Well freeze protect fluids are eligible for EOR via AIO 108.011 and I would assume Hilcorp would want to save diesel for reuse or produce it. For water source wells, this freeze protect would not come into contact with any produced fluids and so would be Class 1. The source water well(s) to be drilled on Moose Pad, as well as associated piping to EOR and the Class II injection wells, will require freeze -protecting until they are ready to be used for production purposes. Freeze -protect fluids generally include diesel (new, unused product) or methanol (new, unused product ("neat" or "pure"); or 60/40 methanol/water or glycol blend). Hilcorp expects to primarily use 60/40 methanol; however, using diesel is an option as well. Note that produced water is often used to make the methanol blend. Once the source water well is ready to be brought on line, the freeze -protect fluids will be recovered for reuse or left within the well's injection stream as a freeze -protect buffer when injecting into disposal or EOR wells. See the attached PowerPoint for a visual description. In other words, as freeze protect fluids are pulled out of the source water well and directed to the Class II injection well, we would risk flash -freezing the piping in between if we were to pull out the fluids prior to injection. Continuing to direct fluids to the injection well protects the entire system. Hilcorp's interpretation is that given the freeze -protect fluids' purpose of protecting the wells and piping used for production, the activity is intrinsic to exploration, development or production activities and acceptable for injection into the Class II well(s) at Moose Pad, and request this waste stream with generating activity to be added to Rule 2 of DID 42. 3. Line heater condensation fluids. Boiler condensation was made eligible for EOR via AIO 10B.012. 100-200 bbl per day line heater condensation was mentioned in the A/O 10B application and it was said to be blended with the produced water and processed. What has changed? Either EOR or otherwise a Class I fluid. Condensate from the heaters at Moose Pad will be generated as part of normal operations; however, the flow design has been changed so that the condensate will now be routed to a sump, to separators and then through the Moose Pad separation process, and not got directly to the disposal well. Hilcorp no longer request clarification or modification to Rule 2 with regard to line heater condensation fluids. 4. Precipitation accumulating on pad (pad dewatering). Snowmelt or rainwater in contact with downhole fluids in reserve pits or well cellars is acceptable for Class 11 disposal. Rigwash or cleaning rig/downhole tools/vac truck cleanouts/sumps is acceptable for Class// disposal as long as it is in contact with downhole fluids. EOR via AIO 108.012 PART B 2. h) allows for EOR of non -hazardous water collected from MPU reserve pits well house cellars and standing ponds. Otherwise this snowmelt precipitation would be Class L We would need to know about potential contamination e.g., solids or mixing with ineligible truck fuel spills or pipeline pigging wastes. Assuming itis intrinsic to E&P, required for maintenance of the disposal well, or a beneficial reuse with no other options for disposal does not appear to be the case here. Hilcorp will manage pad dewatering fluids not in contact with downhole or production fluids via its Class I wells and removes this item from consideration. Thank you for your review and consideration. Look forward to hearing from you. Amy Peloza Waste Environmental Specialist HHilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 (907) 777-8348 — office (907) 317-0521 — cell Email: aoeloza(&hilcoro.com From: Wyatt Rivard Sent: Thursday, November 15, 2018 4:52 PM To: Amy Peloza <apeloza(c@hilcorp.com> Subject: FW: [EXTERNAL] RE: DIO-42 Authorized Fluids Wyatt Rivard I Well Integrity Engineer IHilcorp Alaska, LLC 0: (907) 777-8547 1 C: (509)670-80011 wrivard(a)hilcorp.com 3800 Centerpoint Drive, Suite 1400 1 Anchorage, AK 99503 From: Wallace, Chris D (DOA)[ma ilto:chris.waIlace @alaska.aov] Sent: Tuesday, October 30, 2018 12:17 PM To: Wyatt Rivard <wrivard@hilcorp.com> Subject: [EXTERNAL] RE: DIO-42 Authorized Fluids Wyatt, My answers below are based on the assumptions below. If my assumptions are wrong we would need to hear exactly how and where the waste is generated, what it was mixed with, how stored, and how injected. These fluids below, where generated, how processed, what blended with intentionally vs. unintentionally, etc. leads to confusion with the Class I vs. Class II (EOR vs. D) eligibility. We can discuss further as needed. Thanks and Regards, Chris Wallace, Sr. Petroleum Engineer, Alaska Oil and Gas Conservation Commission, 333 West 71h Avenue, Anchorage, AK 99501, (907) 793-1250 (phone), (907) 276-7542 (fax), chris.wallace(Walaska.¢ov 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 Chris Wallace at 907-793-1250 or chris.wallace@alaska.gov. From: Wyatt Rivard <wrivard@hilcorp.com> Sent: Monday, October 29, 2018 3:40 PM To: Wallace, Chris D (DOA) <chris.wallace@alaska.Rov> Subject: DIO-42 Authorized Fluids Chris, Our environmental team wanted to confirm that the following fluids which are not listed in DIO-42 Rule # 2 will be authorized for injection: 1. Excess or unused Prince Creek Formation source water. If it was originally sourced for the E&P purpose (not produced with the sole intent for disposal which would be considered waste), and Hilcorp can show it was an unplanned event that would not be considered a normal/frequent occurrence, and assuming it would be comingled with produced water prior to disposal this would be acceptable. Or if it was produced for the sole purpose of treating an eligble Class II fluid (ie thinning it or getting sufficient volume for pump charge) and assuming it would be comingled with produced water prior to disposal this would be acceptable. It would be better stored and used for EOR, or shut in the well. We would need to know volume and frequency and why this cannot go to the Class I disposal. 2. Well freeze protection fluids including from source water wells. Acceptable once circulated down oil and gas wells. Well freeze protect fluids are eligible for EOR via AIO 10B.012 and I would assume Hilcorp would want to save diesel for reuse or produce it. For water source wells, this freeze protect would not come into contact with any produced fluids and so would be Class I. 3. Line heater condensation fluids. Boiler condensation was made eligible for EOR via AIO 10B.012. 100-200 bbl per day line heater condensation was mentioned in the AIO 10B application and it was said to be blended with the produced water and processed. What has changed? Either EOR or otherwise a Class I fluid. 4. Precipitation accumulating on pad (pad dewatering). Snowmelt or rainwater in contact with downhole fluids in reserve pits or well cellars is acceptable for Class II disposal. Rigwash or cleaning rig/downhole tools/vac truck cleanouts/sumps is acceptable for Class II disposal as long as it is in contact with downhole fluids. EOR via AIO 10B.012 PART B 2. h) allows for EOR of non -hazardous water collected from MPU reserve pits well house cellars and standing ponds. Otherwise this snowmelt precipitation would be Class I. We would need to know about potential contamination eg solids or mixing with ineligible truck fuel spills or pipeline pigging wastes. Assuming it is intrinsic to E&P, required for maintenance of the disposal well, or a beneficial reuse with no other options for disposal does not appear to be the case here. Please let me know if you need any additional information. Thank You, Wyatt Rivard I Well Integrity Engineer (Hilcorp Alaska, LLC 0: (907) 777-8547 1 C: (509)670-8001 I wrivard@hilcorp.com 3800 Centerpoint Drive, Suite 1400 1 Anchorage, AK 99503 �d Hilcorp Alaska LLC John Barnes Asset Team Leader Post Office Box 244027 Anchorage, AK 99524-4027 3800 Centerpoint Drive November 5, 2018 suite 1400 Anchorage, AK 99503 Hollis S. French, Chair Phone: 907/777-8350 Fax: 907/777-8351 Alaska Oil and Gas Conservation Commission jbarnes@hncorp.com 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 RECEIVED Re: Application to Amend Disposal Injection Order 42 NOV Q 6/2018 Dear Commissioner French, A®GCC Hilcorp Alaska, LLC (HAK), Milne Point Unit Operator, files this application to amend Disposal Injection Order 42 (DIO-42) for the Milne Point Unit. DIC -42, issued October 24, 2018 authorizes underground disposal of Class II oilfield waste fluids at Moose Pad. HAK requests amendment to Rule 5 and Rule 6 of DIO-42 while providing the following additional information: Rule 5: Well Integrity Failure and Confinement — 3,000 ft Offset from Well 32-14 Request Rule 5 includes a restriction on drilling any disposal wells within 3,000' of the plugged and abandoned well Simpson Lagoon 32-14 (PTD# 1690520) at the disposal zone. Hilcorp requests to reduce the radius of the limit from 3,000 ft to 1,320 ft (1/4 mile) to enable existing well targets to be drilled with a wireline accessible build angle (<70 deg). Currently, the first three of four possible disposal well targets are within 3,000' of 32-14 and already planned with maximum build angles from Moose Pad. Background 32-14 was abandoned in 1969 and is not isolated with cement behind casing across the Ugnu and Schrader Bluff sands. The subsequent sidetrack, 32-14A (PTD 1690790), was properly cemented across the Ugnu and Schrader Bluff but greatly complicates any future attempts to access and remediate the original 32-14 motherbore. Additionally, as part of the well's surface abandonment in 1992, the wellhead was cutoff and the casing stubs were buried below pad level. Any attempts to access the abandoned 32-14 wellbore now to attempt to remediate the casing cement would be impractical. 32-14 does have good cement isolation above the Ugnu to prevent any upward movement of fluids. In the event that any disposal fluids were to move from the Ugnu to the Scharder Bluff, this would not result in damage to the Schrader Bluff as the disposal waste stream is predominantly produced water and effectively the same fluids approved under AIO 10-B that will be injected in the Schrader Bluff formation for enhanced oil recovery. Milne Point DIO 42 Amendment Page 2 of 4 The 3,000 ft restriction on drilling near the 32-14 well provides a highly conservative offset to prevent disposal fluids from reaching the 32-14 well and potential moving from the Ugnu to the Schrader. 3,000 ft represents a —1.6 factor of safety over the largest expected circular disposal plume of 1,880 ft to account for the possibility of an elliptical injection plume. 1,880 ft was, in turn, based on a worst case scenario of only 2 wells disposing of the maximum expected cumulative volume of 355,000,000 bbls. Proposal To utilize the existing disposal well targets located within 3,000 ft of 32-14, HAK proposes to utilize a three well scenario and apply the 1.6 safety factor at each target to determine the max allowable elliptical injection plume radii. These plots are shown in Figure 1: Elliptical Injection Plume Radii. Disposal Target 2 A Disposal Target 3 s� Disposal Target 1 f;cSsN N w�cow+unsw�uc (M-03) c= - Figure 1: Elliptical Injection Plume Radii From the elliptical radii, max cumulative disposal volumes for each well target can then be determined. These volumes are listed in Table 1: Max Cumulative Disposal Volumes. ,vve�i Max axis allowable Radii ft Min axis radii (Max/1.6) ft =�- acres MIN millil5lill! bbls Disposal 1 (M-03) 1590 994 114.0 79,322,144 Disposal 1550 969 108.3 75,381,295 Disposal 2785 1741 349.6 243,360,784 Total 398,064,222 Table 1: Max Cumulative Disposal Volumes. Milne Point DIO 42 Amendment Page 3 of 4 Injection volumes will be tracked annually for each well as part of the annual disposal surveillance report. In this way, injection to individual wells can then be adjusted and additional wells drilled to ensure injection plumes do not reach the 32-14 well. Rule 3: Injection Rate and Pressure -35,000 BPD Max Injection Rate Request Rule 3 includes a 35,000 BPD max injection rate limitation. HAK requests to increase the limit to 45,000 BPD. Background Under a steady state two -well scenario average injection rates were estimated at 27,000 bpd with 36,000 bpd as a max rate. However there will be times, when injection rates of up to 45,000 BPD may be needed to handle fluids during peak conditions such as between the commissioning of the 11t and 2nd disposal wells. As part of a supporting fracture study submitted with the DIO application, a 35,000 BPD injection model was referenced. However, at the DIO presentation updated Nodal Analysis results based on the M-01 type log were presented that showed an expected operating range of 25,000-40,000 bpd. Additionally the rate required to reach minimum facture pressure is estimated at 78,000 bpd. Increasing the maximum permitted injection rate from 35,000 BPD to 45,000 BPD will not result in exceedance of minimum fracture pressure. Nodal analysis plot is shown in Figure 2: NodalAnalysis Plot -Single Well i 78,000 bpd @ 2300 psi BHP (2500 psi FTP) Min f, Pressure — 2300 psi I \ I Figure 2.: Nodal Analysis Plot -Single Well Milne Point DIO 42 Amendment Page 4 of 4 If you have any additional questions, please contact myself at 777-8421 or by email at reedwards@hilcorp.com or Wyatt Rivard at 777-8547 or by email at wrivard@hilcorp.com. pe — Reservoir Engineer Hilcorp, Alaska LLC v AOGCC 9/5/2018 ITMO: APPLICATION OF HILCORP Docket No. DIO-18-001 ALASKA OIL AND GAS CONSERVATION COMMISSION In the Matter of the Application of Hilcorp ) Alaska, LLC for a Disposal Injection Order ) to Authorize Disposal of Approved Class II ) Oil and Gas Exploration and Production ) Wastes in up to Four Dedicated Wells in the ) Moose Pad Area, Milne Point Field, Milne ) Point Unit, North Slope, Alaska. ) Docket No.: DIO 18-001 PUBLIC HEARING September 5, 2018 10:00 o'clock a.m. Alaska OiL and Gas Conservation Hearing Room 333 W. 7th Avenue Anchorage, Alaska BEFORE COMMISSIONERS: Hollis French, Chair Cathy Foerster Daniel T. Seamount Commission Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Arch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 9/5/2018 ITMO: APPLICATION OF HILCORP Docket No. DIO-18-001 Page 3 1 P R O C E E D I N G S 2 (On record - 10:00 a.m.) 3 CHAIR FRENCH: We'll go ahead and -- I'll call 4 the meeting to order. It's 10:00 o'clock now this 5 morning on September 5th, 2018. We're at 333 West 6 Seventh Avenue, Anchorage, Alaska, the headquarters of 7 the Alaska Oil and Gas Conservation Commission. To my 8 right is Commissioner Cathy Foerster, to my left is 9 Commissioner Dan Seamount, I'm Hollis French, the Chair 10 of the Commission. 11 We're here today regarding docket number DIO 12 18-001, pertaining to the Ugnu formation, the Moose Pad 13 area, Milne Point field and the Milne Point unit on the 14 North Slope of Alaska. It's an application for a 15 disposal injection order. Hilcorp Alaska, LLC by 16 application dated July 13, 2018, has requested that the 17 Alaska Oil and Gas Conservation Commission issue a 18 disposal injection order to authorize disposal of 19 approved class II oil and gas exploration and 20 production wastes in up to four dedicated wells in the 21 Moose Pad area, Milne Point field, Milne Point unit, 22 North Slope, Alaska. 23 Computer Matrix will be recording the 24 proceedings. You can get a copy of the transcript from 25 Computer Matrix Reporting. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Arch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 9/5/2018 ITMO: APPLICATION OF HILCORP Docket No. DIO-18-001 Page 5 1 allowed relevant to testimony. First all testimony 2 must be relevant to the purposes of the hearing that I 3 outlined a few minutes ago and to the statutory 4 authority of the AOGCC. During the hearing we will be 5 asking the questions and we prefer not to have any 6 disrespectful or inappropriate testimony which we're 7 not anticipating any of today. 8 Commissioner Foerster and Seamount, do you have 9 anything to add? 10 COMMISSIONER SEAMOUNT: No. 11 COMMISSIONER FOERSTER: No. 12 CHAIR FRENCH: Now if the witnesses who intend 13 to testify would come forward I'll swear you in all 14 together and then we'll go one at a time into your 15 testimony. 16 Good morning, gentlemen. If you'd raise your 17 right hands, please. 18 (Oath administered) 19 IN UNISON: I do. 20 CHAIR FRENCH: Okay. Now I see -- I guess I 21 just had -- oh, no, I missed a couple yeses in my 22 perusal of the witness list. So we'll just go one at a 23 time. Whoever wants to go first, go first. Tell me 24 your name of course and in your introductory remarks 25 let us know if you want to be recognized as an expert Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 9/5/2018 ITMO: APPLICATION OF HILCORP Docket No. DIO-18-001 Page 7 1 guess we'll do that one at a time as they testify. 2 You provided a good overview of Milne Point, 3 it's -- Milne Point unit is on state lands on the North 4 Slope, Alaska. Hilcorp Alaska is the operator of the 5 leases that are jointly owned between Hilcorp and BP. 6 There's 24 state leases comprising the Milne Point 7 unit. The application before the Commission and 8 proposed disposal order is to inject produced water and 9 certain class II approved fluids into the Milne Point 10 unit disposal injection area. All of the area in which 11 the disposal injection area encompasses is within the 12 Milne Point unit and as well as it -- within the 13 existing aquifer exemption order which this Commission 14 issued in 1987. There are no confidentiality issues 15 that we're requesting. Our application is publicly 16 available and we did not indicate any confidential 17 information in our application nor will there be any in 18 the testimony you're about to hear this morning. 19 We've provided a hard copy of our application 20 to the Department of Natural Resources which is the 21 adjacent landowner and surface owner in the Milne Point 22 unit. In addition we provided a courtesy copy of this 23 application to ConocoPhillips which is the operator of 24 the adjacent Kuparuk River unit just to the west of the 25 Milne Point unit. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email sahile@gci.net AOGCC 9/5/2018 ITMO: APPLICATION OF HILCORP Docket No. DIO-18-001 Page 9 1 CHAIR FRENCH: Further questions? 2 COMMISSIONER FOERSTER: I have none, I have no 3 problems accepting Mr. Edwards as an expert witness. 4 COMMISSIONER SEAMOUNT: I have no problems. 5 CHAIR FRENCH: You're now an expert in 6 reservoir engineering according to the AOGCC. 7 MR. EDWARDS: Thank you. 8 STAN PORHOLA 9 previously sworn, called as a witness on behalf of 10 Hilcorp Alaska, LLC, testified as follows on: 11 DIRECT EXAMINATION 12 MR. PORHOLA: Stan Porhola, operations engineer 13 for Hilcorp. I've been working for Hilcorp for the 14 last five years. Master's degree in petroleum 15 engineering from University of Alaska Fairbanks and a 16 master's in Arctic engineering from University of 17 Alaska Anchorage. I've been in the oil industry the 18 last 15 years, first started out with the Bureau of 19 Land Management as a petroleum engineer working 20 reservoir issues on the North Slope, NPR -A and the Cook 21 Inlet. And I was working for Chevron as a drilling 22 completion engineer for five years, North Slope and 23 Cook Inlet as well. then for Linc Energy for less than 24 two years doing North Slope exploration projects. And 25 for Hilcorp the last five years both Cook Inlet and Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Arch. AK 99501 Fax: 907-243-1473 Email: sahile(dgci.net AOGCC 9/5/2018 ITMO: APPLICATION OF HILCORP Docket No. DIO-18-001 Page 11 1 accepting Mr. Porhola as a downhole expert. 2 CHAIR FRENCH: You are now an expert. Good 3 morning. 4 AMY PELOZA 5 previously sworn, called as a witness on behalf of 6 Hilcorp Alaska, LLC testified as follows on: 7 DIRECT EXAMINATION 8 MS. PELOZA: My name is Amy Peloza, I am a 9 waste specialist for Hilcorp Alaska. I hold a 10 bachelor's degree from Alaska Pacific University in 11 environmental science. I've supported oil and gas 12 operations, the environmental aspect, for the last 20 13 years, Spring, North Slope, Cook Inlet and Kenai 14 operations. 15 CHAIR FRENCH: And for which companies, ma'am? 16 MS. PELOZA: For BP and for Hilcorp. 17 CHAIR FRENCH: And all in the same area, in 18 waste disposal? 19 MS. PELOZA: Waste disposal and general 20 environmental compliance..... 21 CHAIR FRENCH: Okay. Are you..... 22 MS. PELOZA: .....all media. 23 CHAIR FRENCH: .....seeking to be an expert 24 today? 25 MS. PELOZA: In waste, the waste streams and types. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 9/5/2018 ITMO: APPLICATION OF HILCORP Docket No. DIO-18-001 Page 13 1 to be seen as an expert today? 2 MR. EASTHAM: Yes, I am. 3 CHAIR FRENCH: In which field? 4 MR. EASTHAM: Geology. 5 CHAIR FRENCH: Geology. We'll turn to our 6 geologist then and ask him if he has any questions? 7 COMMISSIONER SEAMOUNT: I have no questions, no 8 objections. 9 CHAIR FRENCH: Commissioner Foerster. 10 COMMISSIONER FOERSTER: Nor do I. 11 CHAIR FRENCH: Excellent. You shall be deemed 12 an expert. 13 I'll just ask the four of you as you testify 14 just to perhaps for the ease of following along for 15 someone reading this later on just remind of us your 16 name when you begin, this is so and so and lead in. If 17 it's the same testimony of course you don't have to do 18 that, but as you change speakers just remind us or 19 remind the -- remind the person reading the hearing 20 transcript who you are. 21 Thanks so much. Go ahead. Whoever wants to 22 lead off, please do so. 23 COMMISSIONER FOERSTER: And as you're talking 24 also to make it easy for people reading the transcript 25 later, as you change to a new slide introduce the slide Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 9/5/2018 ITMO: APPLICATION OF HILCORP Docket No. DIO-18-001 Page 15 1 disposed there as well. And then just to note the 2 existing disposal that we have at Milne Point, it's all 3 produced fluid from the main processing facility, the 4 central processing facility, and also disposed in the 5 Ugnu formation as well. And those are all class I 6 disposal wells labeled there, B-50, B-34 and B-24. 7 CHAIR FRENCH: And just a quick question. 8 Where are the Prince Creek water source wells, where 9 are they located physically? 10 MR. EDWARDS: So they will be located on this 11 pad as well near them. 12 CHAIR FRENCH: I see. So you're -- okay. 13 MR. EDWARDS: Yeah. 14 CHAIR FRENCH: You're going to drill them to 15 get source water and then..... 16 MR. EDWARDS: Correct. 17 CHAIR FRENCH: .....and then inject most of it 18 right back there? 19 MR. EDWARDS: Yeah. 20 CHAIR FRENCH: Got it. Okay. Thanks. 21 MR. EDWARDS: And then this is just a -- so 22 slide four, a disposal profile over time. So what we 23 have -- so the plot is just disposal rate versus time 24 and we're drilling our first disposal well here in 25 October and then we will -- we're planning on drilling Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 9/5/2018 ITMO: APPLICATION OF HILCORP Docket No. D10-18-001 Page 17 1 zone. So it will essentially give this area an 2 injection over time. So here we're showing -- we're 3 showing four different wells, we will most likely only 4 do two and the radiuses represent 1,880 feet. So we're 5 trying to show the extent of the injection and that we 6 will not be, you know, injecting into the Kuparuk lease 7 or beyond the aquifer exemption line which is labeled 8 here in blue. 9 And then..... 10 CHAIR FRENCH: And, Mr. Edwards, if you go with 11 the two well design which of these two -- is there any 12 way just to sort of guess or predict which two of these 13 four well circles you have indicated there would be the 14 actual ones you'd use? 15 MR. EDWARDS: I think most likely the targets 16 will be this target one, if I'm reading that correctly, 17 and also they'd probably target four. Just, you know, 18 we want to try to stay away from the lease lines. 19 CHAIR FRENCH: It wouldn't over -- and yet the 20 two circles wouldn't overlap, you'd be as far away from 21 each other as sort of logically possible? 22 MR. EDWARDS: Correct. Yeah, that would be the 23 plan. 24 CHAIR FRENCH: Sure. Thank you. 25 MR. EDWARDS: Yeah. And then I'll hand it over Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 9/5/2018 ITMO: APPLICATION OF HILCORP Docket No. DIO-18-001 Page 19 1 The next slide, the proposed disposal zone 2 criteria. So on the right side of the slide you'll see 3 four different sets of well logs. Those are the 4 Central Lagoon 32-14 and the M-1 and M -1A wells and the 5 Liviano which are basically the wells in the disposal 6 area that we're talking about. So really for our 7 criteria we're looking for several things for a 8 disposal zone. we're looking for laterally continuous, 9 high porosity, high permeability wet sands. We're 10 looking for good and finding intervals above and below 11 the proposed disposal zone. We want to be below the 12 source water zone in Prince Creek, at Moose Pad and we 13 want to be above the presence of heavy oil in the Ugnu 14 which occurs in the lower part. So we're really 15 shooting for the middle part of the Ugnu here for the 16 disposal zones. And then also a known disposal zone 17 salinity which we'll talk about a little bit later. So 18 on each of these logs the yellow that you see in the 19 depth track is highlighting the proposed disposal 20 zones. 21 CHAIR FRENCH: This is probably a question only 22 an amateur could ask, but I'll it. Do you expect that 23 the injection of all that water into the zone above the 24 Ugnu will move that oil around at all or no? 25 MR. EASTHAM: Well, there's not any oil in 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 9/5/2018 ITMO: APPLICATION OF HILCORP Docket No. DIO-18-001 Page 21 1 interval so we want to focus on what's above the 2 disposal zone and then what's below the disposal zone. 3 So we have the M-1 type log on the right here. So at 4 the very bottom of the log is the top of the proposed 5 disposal zone so we're looking at basically the 300 6 feet tvd above the disposal zone. We see in that -- in 7 that 300 feet we see about 90 feet of tvd of non - 8 reservoir that we would consider confining intervals. 9 They're highlighted in gray on the log. Especially 10 with the coals, you'll see three different coals there 11 highlighted in black on the third frac on the right in 12 the prosse (ph) logs and really we see in core and a 13 lot of places you see really fine grained shale type 14 confining layers that happen -- that occur beneath the 15 coals. So we feel good about our upper confining 16 interval here above the proposed disposal zone. Next 17 slide. 18 Now we're going to take a look at the lower 19 confining interval. Once again highlighted in yellow 20 on the log on the right is the disposal zone and the 21 red formation top is the base of the proposed disposal 22 interval, the top of the lower confining interval. So 23 between our proposed disposal unit and the Ugnu heavy 24 oil is our lower confining interval which is almost a 25 hundred feet tvd thick. We see in M-1 that we have 40 Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email sahile@gci.net AOGCC 9/5/2018 ITMO: APPLICATION OF HILCORP Docket No. DIO-18-001 Page 23 1 well for us on J Pad about four miles from where we're 2 talking about on Moose Pad to the southeast. And that 3 -- you can tell that that's structurally similar as 4 well as stratigraphically similar to where we're -- the 5 proposed disposal interval in Moose Pad. And we have 6 water samples and salinity. We know that it's about 7 5,000 parts per million tds for the -- in J Pad. And 8 given it's structural and its stratigraphic similarity 9 to Moose Pad we expect the salinity of the disposal 10 zone to be in that 5,000 tds range. 11 We wanted to make sure we addressed K-34. The 12 reason that's on there is it's 10 miles to the 13 southeast, it's on the other side of the field. It's a 14 bit unique from a source water perspective, it's not 15 Prince Creek, it produces out of the wet, lowest part 16 of the Ugnu. And it's totally different 17 stratigraphically. So if you see on the lower right 18 part of the slide there's a blue star on that log 19 showing where at the very lowest part of the Ugnu is 20 where the K-34 source water comes from and its tds is 21 more on the order of 37,000. So it's quite a bit 22 different, bit it's also -- sits right on top of the 23 Schrader Bluff which is more of a marine sequence and 24 has a lot higher salinities. So we would expect that. 25 It's very different stratigraphically and structurally Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 9/5/2018 ITMO: APPLICATION OF HILCORP Docket No. D10- 18-001 Page 25 1 the upper and lower confining zones are estimated to be 2 2,700 psi, to fracture those zones. So what we have 3 here is the well -- in order -- I guess in order to get 4 to that 2,300 psi bottom hole pressure we would have to 5 inject roughly 78,000 barrels a day of water into the 6 well which we're not expecting to do so. Our expected 7 operating range will be the 27,000 to 36,000 barrels a 8 day of water. So we're just trying to show that we'll 9 be well below any structuring within the reservoir in 10 what we're expected to operate. And that's -- and this 11 represents what we had specified in the application was 12 2,500 psi surface pressure. 13 MS. PELOZA: Amy Peloza, we're on slide 13, 14 waste types and sources. We propose in the application 15 to inject exploration production exempt fluids eligible 16 for class II injection. We listed produced water with 17 spent polymer, excess or unused formation source water, 18 freeze protect fluids, line heater condensation fluids, 19 pad and secondary containment dewatering fluids, bleed 20 trailer fluids and other fluids as needed. All of the 21 fluids are within the proposed aquifer exemption order 22 number 2. The waste streams are similar to what we 23 dispose of already at our class I wells M-50 and B-24 24 and B-34. Freeze protect fluids, things like diesel, 25 methanol/glycol mixtures, methanal/water mixtures 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 9/5/2018 ITMO: APPLICATION OF HILCORP Docket No. DIO-18-001 Page 27 1 MS. PELOZA: No, I don't think so. No, it's 2 just fluids. Drill cuttings would go to the B-34 and 3 B-24. 4 COMMISSIONER SEAMOUNT: So I have a question 5 that I should probably know the answer to. 355 million 6 barrels is a lot of water. How come -- I've heard that 7 there's a source water problem on the North Slope that 8 they don't have enough water for secondary recovery. 9 How come you can't use this for secondary recovery, is 10 it an economic thing? 11 MR. EDWARDS: I mean, I guess I can't -- I 12 don't know if I've heard that statement. I think 13 there's plenty of source water that we can use for 14 injection which we do, we use -- we pull from the 15 Prince Creek. So we drill water source wells because 16 it's fresh and it's low salinity and that helps 17 increase the oil recovery that we get. And then, you 18 know, we can dispose of that, the produced water, 19 because we would rather use the fresher, low salinity 20 water. So I don't think there's any -- there's no 21 shortage of water in the..... 22 COMMISSIONER SEAMOUNT: Okay. 23 MR. EDWARDS: .....ground to use. It might 24 depend on operators and maybe cost. So..... 25 COMMISSIONER SEAMOUNT: I heard that more than Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 9/5/2018 ITMO: APPLICATION OF HILCORP Docket No. DIO-18-001 Page 29 1 half inch production tubing. The reason for that is 2 that currently right now there are no current packers 3 available that are seven and five-eighths by five and a 4 half so you have to have it necked down -- a production 5 packer down to the four and a half tubing, but that 6 shouldn't be too big a limiting factor, it's just a 7 tangible item that is not a typical packer out there to 8 be on the market. Plan is to set the packer at least a 9 hundred feet above the top of the proposed disposal 10 interval, it'll be planned to start at perforating the 11 bottom of the interval, but we'll be asking for a 12 variance to set the packer higher knowing that the 13 potential disposal interval will be potentially 14 available to us in the future. And hopefully we don't 15 have to move the completion anytime in the life of the 16 well. Current plan is actually just drill past the 17 current disposal well interval and drill actually down 18 to the Schrader Bluff to get some additional log 19 information from the Schrader Bluff. So we'll be -- 20 the plan will be to run casing to the bottom and 21 isolate the Schrader with the primary cement job and 22 then follow it up with a stage tool just below the 23 disposal injection interval to do a secondary cement 24 job to make sure we have isolation there. And we'll 25 obviously follow-up that up with some spent bond logs Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Arch. AK99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 9/5/2018 ITMO: APPLICATION OF HILCORP Docket No. DIO-18-001 Page 31 1 through the Sag, down to about 10,050 feet measured 2 depth. One thing that happened here back in the late 3 160s, the Schrader Bluff was not as -- you know, known 4 be a prolific and producing formation at the time so 5 they made the decision they do not put any cement 6 across the Schrader Bluff formation in this well. You 7 can see the Schrader Bluff in the darker brown color 8 there, about 3,745 feet measured depth. And only 9 partial cement across the upper Ugnu disposal zone that 10 we're looking at. So the way Chevron left this well, 11 they cemented off their target interval at the bottom 12 of the well and then bonded the nine and five-eighths 13 casing, an estimated cement top at 71,100 feet measured 14 depth and that's based off 25 percent open hole excess. 15 There was no cement bond log ran on this well so all 16 those depths are estimations based off of the thousand 17 sacks of class III cement they pumped. But after that 18 -- they did that job they went promptly to sidetrack 19 the well and to the 32-14A location there listed the 20 permit to drill 169079. And to do that they cut -- 21 they cut and recovered the nine and five-eighths 22 casing, you can see there the casing was cut there at 23 about 2,900 feet and then they promptly set some open 24 hole plugs and cement plug up into the 13 and three - 25 eighths shoe. Doing the calculations because there was Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC. 9/5/2018 ITMO: APPLICATION OF HILCORP Docket No. DIO-18-001 Page 33 1 MR. PORHOLA: Slide 17, offset well analysis. 2 So the other well that's in close proximity to our 3 proposed disposal unit was the Milne Point unit M-01, 4 drilled by Conoco in 1983 into 1984. So they drill 5 this well just through the Schrader, down to the 6 Kuparuk interval. This is a time when the Schrader was 7 actually known to be productive and they did set some 8 open hole plugs. They drilled an eight and a half inch 9 hole down to 9,000 feet and they plugged back the well 10 with an open hole plug across the Kuparuk. One cement 11 plug there from 4,350 to 4,800, you know, actually 12 isolating the entire Schrader Bluff interval. They set 13 another open hole cement plug above that at 3,800 feet 14 to 4,226 that covered up the base of the Ugnu sands and 15 then they sent a shoe plug across the nine and five - 16 eighths casing shoe with a base at 2,966. 17 And on this well you can see the upper Ugnu 18 sands we're proposing to dispose of. The top was at 19 3,215 so part of those sands are open and not isolated, 20 but they are isolated from above and below with open 21 hole cement plugs. However those plugs were never 22 tagged or tested so they are based off of the cement 23 lines that were pumped in those well by Conoco at that 24 time back in 1983, 1984. But right now the Schrader 25 should be isolated from the disposal injection area. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 9/5/2018 ITMO: APPLICATION OF HILCORP Docket No. DIO-18-001 Page 35 1 prevented by weather emergencies of course. And then 2 shutting the well of -- and notification to the AOGCC 3 within 24 hours of any indication of any pressure 4 anomalies or leakages or lack of injection into the 5 zone, isolation and then follow-up with a four year 6 basis on MITs per guidance bulletin 10-02A. All that 7 will be done during the well construction and then 8 after the well construction. 9 CHAIR FRENCH: Speaking of staffing, will this 10 be staffed from Milne Point, that is will folks be 11 driving back and forth from Milne Point, is that the 12 nearest camp? 13 MR. PORHOLA: Correct. They'll be operators 14 that will be working just Moose Pad separately and 15 they'll be on location. And then..... 16 CHAIR FRENCH: Sleeping there? 17 MR. PORHOLA: No, they have a (indiscernible) 18 office on location..... 19 CHAIR FRENCH: Okay. 20 MR. PORHOLA: .....they'll be working out of 21 and then there's a 24 hour coverage. 22 CHAIR FRENCH: Okay. Thank you. Looks like 23 the end of the slide deck. Any wrap up comments? 24 COMMISSIONER FOERSTER: I have questions. 25 CHAIR FRENCH: Sure. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahileCgci.net AOGCC 9/5/2018 ITMO: APPLICATION OF HILCORP Docket No. DIO-18-001 Page 371 1 MR. REID: Oh. 2 COMMISSIONER FOERSTER: In the lower 48 they're 3 injecting in one or two locations at such high volumes, 4 not necessarily pressures, that they're causing local 5 -- localized along fault planes. So really the 6 question I'm asking is is your injection volume in line 7 with other injection volumes in other wells on the 8 North Slope which have not caused such problems. And 9 you see where I'm going, the public is always concerned 10 that oh, gosh, we're going to have the problem that 11 they have in the lower 48. But what I want to get on 12 record is your assessment of where we are relative to 13 that. 14 MR. EDWARDS: Yeah. So we have -- so the B-50 15 well that we've referenced, somebody can correct me if 16 I'm wrong, but I believe we put 150 roughly million 17 barrels into that well and have not seen any issues 18 over time so I think we feel pretty confident that 19 there's no issue there. 20 COMMISSIONER FOERSTER: Okay. Thank you. 21 CHAIR FRENCH: So you don't anticipate any 22 induced seismicity? 23 MR. EDWARDS: No. 24 CHAIR FRENCH: Further comments. Commissioner 25 Seamount, do you need a break to consult with staff or Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 9/5/2018 ITMO: APPLICATION OF HILCORP Docket No. DIO-18-001 Page 391 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.: DIO 18-001 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 15th 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. AK99501 Fax: 907-243-1473 Email: sahile@gci.net STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Docket Number: DIO-18-001 Ugnu Formation, Moose Pad Area, Milne Point Field Milne Point Unit, North Slope, Alaska Application for Disposal Injection Order September 5, 2018 at 10:00 am NAME AFFILIATION Testify (Yes or no) b,11 VA , r K tt- lV d� 9/5/2018 Introductions • Jim Shine, Landman, Hilcorp Alaska, LLC • Kevin Eastham, Senior Geologist, Hilcorp Alaska, LLC • Reid Edwards, Reservoir Engineer, Hilcorp Alaska, LLC • Wyatt Rivard, Well Integrity Engineer, Hilcorp Alaska, LLC • Amy Peloza, Waste Environmental Specialist, Hilcorp Alaska, LLC • Deborah Heebner, Field Environmental Specialist, Hilcorp Alaska, LLC • Stan Porhola, Operations Engineer, Hilcorp Alaska, LLC Overview • Confidentiality Issues: None • Request to recognize Mr. Eastham, Mr. Edwards, Mr. Rivard, Ms. Peloza, Ms. Heebner and Mr. Porhola as Experts • Land & Ownership Review: Moose Pad Area, Milne Point Unit, North Slope Alaska • Technical Presentation 2 9/s/2018 N Moose Pad • Newly constructed drill pad with fluid processing facilities Drill up to 56 wells (-28 producing) Injection sourced from Prince Creek water source wells Dispose of produced fluids on pad • Produced water (99%) • Class II production waste (1%) Target Ugnu formation • Reroute MPU F and L pad produced fluids from CPF to Moose Pad to process and dispose Existing MPU Disposal • Produced fluid from CPF • Disposal into Ugnu formation • Current Class I disposal wells at MPU B Pad • B-50 • B-34 • B-24 9/5/2018 Schedule • 1$1 disposal well - 10/18 • 2"d disposal well — 4/19 • Up to 2 additional wells as needed Rate and Volume • Initial rate - 27,000 bwpd Final rate - 72,000 bwpd (12/2036) • Cumulative Injection —355MMBBL Moose Pad Project Total Water Injection Disposal (tate (bpd) ii 'e M. Initial rate— -- - 27,000 bwpd Exhibit 15 "e= ams„ az'zS 5,51Saa'a� as Finalrate- 72000bwpd 0 9/5/2018 W Two well scenario • Cumulative Injection per well — 177 MMBW Net sand — 300' • Porosity — 30% • Calculated injection radius — 1880' • Expected maximum areal extent (less with additional wells) • Will not extend beyond MPU lease or aquifer exemption boundaries MPU /KRU Aquifer Exemption Boundary sing apr kv 9/5/2018 5 .. ' ,m • , A LeOu,a 5 9/5/2018 9/5/2018 9/5/2018 w 9/5/2018 M-01 TYPE LOG • 95' TVD Thick interval in PROPOSED M_01 DISPOSAL INTERVAL, • .40' T -VD oon Fteservoii. TOP LOWER CONFINING • Interval between base of INTERVAL MP proposed disposal interval and top of Ugnu Heavy Oil in Moose Pad area m BASE LOWER CONFINING INTERVAL m 9/5/2018 10 9/5/2018 NW water Pin al similar Structural elevation and stratigraphic M-01 UG LMsource MP 1'IP MP MP LIVIANO 4 miles J-02 01 PROPOSED MOOSE PAD DISPOSAL INTERVAL 6 miles J-02 SOU RCE ATER INTERVA wc�+mt m° xzc _°'° -aaz° .,wo -.ziza n• -mv SE K-34 — interval to Moose MP UG M Pad proposed MPU Disposal=a 7tfi MP SB Expect similar° Moose Disposal 41 Zone salinity (J-02 — 5,000 mg/L o- TDS) roa -as,o Rq P K-34 Source a ic:a water from --°"° different stratigraphic m° � interval and M U MP_ UG structural—amc K-34 SOURCE elevation. (K-34: as'o ATER INTERVA 37,000 mg/L TDS) = STRUCTURAL CROSS SECTION -- _CM 11 Input Parameters • Net Pay Thickness — 300' • Average Net Pay Porosity- 33.4% • Calculated Permeability— 350 and • Mid point depth — 2950' SSTVD Reservoir Pressure— 1298 psi (0.44 psi/ft) 5 Yz " tubing Surface pressure — 2500 psi Containment evaluation • Log evaluation estimates minimum fracture pressure is 2300 psi at 2800' SSTVD (0.82 psi/ft) • Upper and lower confining layers (Ugnu Coal 1 / Ugnu LD) estimated fracture pressure of 2700 psi each Nodal Analysis • Single well • Expected operating range • 25k — 40k bwpd • 1600 — 1800 psi BHP • Rate to reach min frac pressure calculated at 78k bwpd 9/5/2018 Nodal Analvsis Plot — Single Well 12 12 Exploration and Production (E&P) Exempt Fluids Eligible for Class II Injection (including, but not limited to): • Produced water with spent polymer • Excess or unused Prince Creek Formation source water • Freeze -protect fluids • Line heater condensation fluids • Pad and secondary containments dewatering fluids • E&P -exempt fluids from bleed trailers • Other fluids, as needed, to support operations and drilling, determined to meet the E&P exemption 9/5/2018 13 Anticipated Waste Volumes over Project Life: • Well freeze -protect fluid • Well workover fluids and flush • Produced water and excess source water • Heater condensate 1,000,000 bbls 1,000,000 bbls 352,000,000 bbls 1,000,000 bbls 9/5/2018 14 PROPOSED M-03 DISPOSAL WELL 7-5/8" Production Casing (Tested to 2,500 psi). 5-1/2" x 4-1/2" Production Tubing (Tested to 2,500 psi). Packer set 1 00'above the top of the upper disposal interval. Drill past disposal zone to log Schrader Interval Run casing to bottom, isolate Schrader with primary cement job. Utilizing stage tool to isolate the disposal interval with secondary cement job. Top and bottom of interval displayed, actual perforated interval and method to be determined. m-s¢Yrpq/m.4maRrDi 4B(D•4915'p91/m•4�MA 9/5/2018 15 SIMPSON LAGOON 32-14 (Chevron PTD 169-052) Drilled through the Schrader/Kuparuk/Sag River. No cement across Schrader Bluff zone. Partial cement across upper Ugnu disposal zone. Sidetracked as 32-14A (PTD 169-079) with 7" casing set and cemented across Ugnu and Schrader. Drilled directionally to the west/northwest, KOP @ 2,900' MD s�iamnao 9/5/2018 16 MILNE POINT UNIT M-01 (Conoco PTD 183-182) Drilled through the Schrader/Kuparuk. Openhole cement plugs isolating the Schrader. Openhole cement plugs above/below Ugnu disposal zone. Sidetracked as M -01A (PTD 184-033) with 7" casing set and squeeze perfs cemented below the Schrader and the Ugnu. Drilled directionally to the south/southeast, KOP @ 600' MD 9/5/2018 17 9/5/2018 • Initial MIT -IA to 2500 psi to confirm tubing, packer and production casing integrity. • Initial temperature log and step rate test to establish baseline temp profile and injection pressures/rates prior to regular injection. • Follow-up temperature log performed within one month of stabilized injection to delineate receiving zones of injected fluids. • Daily monitoring of casing pressures unless prevented by weather or emergency. • Shut-in of the well and notification of AOGCC within 24hrs of any indication of pressure communication, leakage or lack of injection zone isolation. • Follow-up MIT -IA's on 4 year basis as per Guidance Bulletin 10-02A IN N Notice of Public Hearing STATE OF ALASKA /:111:I.Y.I�lll\►`f_Zl7:E.YKI]��E.�',��L1t11[17�C�Z/71 I\ fE.�.`I[I]�I Re: Docket Numbers: DIO-18-001 Ugnu Formation, Moose Pad Area, Milne Point Field Milne Point Unit, North Slope, Alaska Application for Disposal Injection Order Hilcorp Alaska, LLC (Hilcorp), by application dated July 13, 2018, requests the Alaska Oil and Gas Conservation Commission (AOGCC) issue an Disposal Injection Order to authorize disposal of approved Class II oil and gas exploration and production wastes in up to four (4) dedicated wells in the Moose Pad Area, Milne Point Field, Milne Point Unit, North Slope, Alaska. The AOGCC has scheduled a public hearing on the application for September 5, 2018, at 10:00 a.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 7 t Avenue, Anchorage, Alaska 99501. Comments must be received no later than the conclusion of the September 5, 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: DIO-18-001 Ugnu Formation, Moose Pad Area, Milne Point Field Milne Point Unit, North Slope, Alaska Application for Disposal Injection Order Hilcorp Alaska, LLC (Hilcorp), by application dated July 13, 2018, requests the Alaska Oil and Gas Conservation Commission (AOGCC) issue an Disposal Injection Order to authorize disposal of approved Class II oil and gas exploration and production wastes in up to four (4) dedicated wells in the Moose Pad Area, Milne Point Field, Milne Point Unit, North Slope, Alaska. The AOGCC has scheduled a public hearing on the application for September 5, 2018, at 10:00 a.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 71h Avenue, Anchorage, Alaska 99501. Comments must be received no later than the conclusion of the September 5, 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 STATE OF ALASKA ADVERTISING ORDER NOTICE TO PUBLISHER SUBMIT INVOICE SHOWING AD VF.RTISPSG ORDER NO., CERTIFIED AFFIDAVIT OF PUBLICATION WITH ATTACHED COPY OFADVERTISNIENF. ADVERTISING ORDER NUMBER AO -I9-003 FROM: AGENCY CONTACT: Jody Colombie/Samantha Carlisle Alaska Oil and Gas Conservation Commission DATE OF A.O. AGENCY PHONE: 333 West 7th Avenue 7/24/2018 (907) 279-1433 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 .c iV LEGAL:. DISPLAY § CLASSIFIED ,; OTHER (Specify below) DESCRIPTION PRICE D I O-1 R-001 Initials of who prepared AO: Alaska Non -Taxable 92-606185 SUBMIT INVOICE 9nOWIN6ADVERTISIN1,: ORDERNO., CRRi1FIED AFFIDAVIT DE : : PUBLICATION WITH ATTACIIT]1 COPY OF: ADWERi76MENT:Zi): AOGCC 333 West 7th Avenue Anchorage, Alaska 99501 Free I of 1 Total of All Pa es S REF Type Number Armunl Data Com mems I PVN VCO21795 2 Ao AO -19-003 3 4 FIN AD4OUNT SY Act. Template I PGM LGR Object FY DIST LIQ I 1 19 A14100 3046 19 5 Purchasi gu rif an le: Purchasing Authority's Signature 'Pelephone Mai1. 0. receiving agency risks Burstairme. on all invoices and documents relating to this purchase. 2. he state is registered for tax free transactions under Chapter 32. IRS code. Registration number 92-73-0006 K. Items are for the exclusive use of the state and not for real 1)1 TRiBUTION: -Division Fiscal/Original-AO : Copies: Publisher (faxed), Division Fiscal, Receiviing Form: 02-901 Revised: 7/24/2018 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Tuesday, July 24, 2018 10:20 AM To: Bell, Abby E (DOA); Bixby, Brian D (DOA); Boyer, David L (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody 1 (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; AKDCWeIIIntegrityCoordinator; Alan Bailey; Alex Demarban; Alicia Showalter; Allen Huckabay; Andrew VanderJack; 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 (jim4thgn@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 1 (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 Hearing Notice - DIO - Hilcorp - MPU Attachments: DIO-18-001 Public Hearing Notice.pdf Please see attached. Jody J. Colombie AoyCC special .;Assistant Alaska oil and(Jas Co) ISe YVal loll Commission 34 1Sost 7"T Avenue Anchorage, Alaska 9y5o1 Office: (907) 79 1221 .')"ax: (907) 27 6-754 2 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jody Colombie at 907.793.1221 or iody.colombie@alaska.aov. Bernie Karl Gordon Severson Penny Vadla K&K Recycling Inc. 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 oX% AFFIDAVIT OF PUBLICATION Account#: 270227 ST OF AK/AK OILAND GAS Order# CONSERVATION COMMISSION Cost 333 WEST 7TH AVE STE 100 AAirWnOArC AK 60SM1910 STATE OF ALASKA THIRD JUDICIAL DISTRICT Sarah Jennett being first duly sworn on oath deposes and says that he/she is a representative of the Anchorage Daily News, a daily newspaper. That said newspaper has been approved by the Third Judicial Court, Anchorage, Alaska, and it now and has been published in the English language continually as a daily newspaper in Anchorage, Alaska, and it is now and during all said time was printed in an office maintained at the aforesaid place of publication of said newspaper. That the annexed is a copy of an advertisement as it was published in regular issues (and not in supplemental form) of said newspaper on July 25, 2018 and that such newspaper was regularly distributed to its subscribers during all of said period. That the full amount of the fee charged for the foregoing publication is not in excess of the rate ajar private individuals. Signed rah Subscr ed and sworn to before me this 25 day of July, 2018 Notary Pubic and for The State 6rAlaska. Third Division Anchorage, Alaska MY COMMISSION EXPRES Notary Public BRITNEY L. TIiOMPSCN State of Alaska u My Commission Expires Feb 23, 2013 0001425172 Product ANC -Anchorage Daily News $164.36 Placement 0300 Position 0301 In Hilcorp Alaska, LLC Application for an Area Disposal Injection Order North Slope, Alaska Milne Point Unit Moose Pad Area Prepared By: Hilcorp Alaska, LLC July, 2018 July 13, 2018 Hilcorp Alaska, LLC Hollis S. French, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 John Barnes Asset Team Leader Post Office Box 244027 Anchorage, AK 99524- 4027 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 Phone: 907/777-8350 Fax: 907/777-8351 jbarnes@hilcorp.com EKED JUL 2 0 2018 RE: Application for a Milne Point Unit Area Disposal Injection Order - Hilcorp Alaska, LLC Dear Commissioner French: Hilcorp Alaska, LLC (Hilcorp) operator of the Milne Point Unit (MPU), hereby applies for an Area Disposal Injection Order (DIO) to inject produced water and other approved miscellaneous Class II eligible fluids into the Ugnu formation in the MPU. Up to four dedicated Class II disposal wells will be drilled per AOGCC regulations in the approved DIO area. This application is for approval of a single DIO area for the four wells. Each Class II disposal well will be permitted separately in accordance with AOGCC regulations. Hilcorp has recently constructed the Moose Pad in the northwest portion of the MPU. Production, enhanced recovery, water source and Class II disposal wells will be drilled from the Moose Pad commencing later this year. Produced water from wells on the Moose pad, as well as produced water from other pads in the northwest portion of the MPU, will be the primary fluid injected into the disposal wells. Included with this letter are the justification and supporting materials addressing the requirements of 20 AAC 25.252 for the application for a DIO. This application does not contain any confidential information. Page 2 Application for a DIO If there are questions or if any additional information is desired, please contact me or Wyatt Rivard. My contact information is shown on the letterhead. Wyatt can be reached at 907-777- 8547 or at wrivard@hilcorp.com Sincerely, a`— ILCORP ALASKA, LLC John Barnes Asset Team Leader Enclosures cc: Wyatt Rivard Hilcorp Alaska, LLC Application for an Area Disposal Infection Order North Slope, Alaska Milne Point Unit Moose Pad Area Prepared By: Hilcorp Alaska, LLC July, 2018 Table of Contents 1. Introduction and Project Overview.......................................................................................1 2. Disposal Injection Order Regulatory Criteria as Listed in 20 AAC 25.252 Part C .................3 2.1 20 AAC 25.252 (c)(1) Well Locations....................................................................................... 3 2.2 20 AAC 25.252 (c)(2) and (c)(3) Surface Owners and Operators; Notice ................................ 4 2.3 20 AAC 25.252 (c)(4) Geologic Details: Injection and Confining Zones .................................... 2.4 20 AAC 25.252 (c)(5) Well Logs............................................................................................... 9 2.5 20 AAC 25.252 (c)(6) Well Construction and Mechanical Integrity .......................................... 9 2.6 20 AAC 25.252 (c)(7) Waste Sources, Types and Volumes; Compatibility ........................... 10 2.7 20 AAC 25.252 (c)(7) (continued) Compatibility of Fluids and Formation .............................. 12 2.8 20 AAC 25.252 (c)(8) Average and Maximum Injection Pressure .......................................... 12 2.9 20 AAC 25.252 (c)(9) Waste Confinement and Fracture Studies .......................................... 12 2.10 20 AAC 25.252 (c)(10) and (c)(11) Formation Water Salinity and Aquifer Exemption........... 14 2.11 20 AAC 25.252 (c)(12) Mechanical Integrity of Wells within the Area of Review ................... 15 2.12 20 AAC 25.252 (d) and (e) Mechanical Integrity of Injection Well, Reporting ........................ 15 2.13 Request for Administrative Approval Authority...........................................................15 3. Summary and Conclusions.............................................................................. 16 Hilcorp Alaska, LLC: Area DIO Application: MPU Moose Pad Page iv Table of Exhibits and Appendices Exhibit 1 North Slope Region Map Exhibit 2 North Slope Unit Map Exhibit 2A Milne Point Unit Area Map Exhibit 3 Milne Point Unit Moose Pad, Disposal Well Locations and Disposal Injection Order Area Exhibit 4 Disposal Order Area and All Well Locations Exhibit 5 Reserved Exhibit 6 Milne Point Area Moose Pad Facilities Map 1 Exhibit 6A Milne Point Area Moose Pad Facilities Map 2 Exhibit 7 Milne Point Area Satellite Image Exhibit 8 Reserved Exhibit 9 Moose Pad Area Well Bore Courses with Disposal Wells Exhibit 10 Disposal Well Final Injectate Plume Area—Four Well Depiction Exhibit IOA Disposal Well Final Injectate Plume Area—Two Well Scenario #I Exhibit IOB Disposal Well Final Injectate Plume Area—Two Well Scenario #2 Exhibit IOC Disposal Well Final Injectate Plume Area—Two Well Scenario #3 Exhibit IOD Final Injectate Plume Based on Well Bottom Hole Location Exhibit 11 Disposal Well Type Log Exhibit 11-A Disposal Well Type Log—Upper Confining Interval Exhibit 11-B Disposal Well Type Log—Disposal Interval Exhibit- IIC Disposal Well Type Log—Lower Confining Interval Exhibit I1 -D Moose Pad Area --Geologic Cross Section Exhibit I 1-D 1 Only Lower Half of Geologic Cross Section Exhibit 11 D 2 Only Upper Half of Geologic Cross Section Exhibit I 1-E Moose Pad Area—Seismic Sections Location Map Exhibit I l E 1 Seismic Section Strike Line Exhibit Il E 2 Seismic Section Dip Line Exhibit IIF North Slope Stratigraphic Display Exhibit I IG Moose Pad Area Structure Map Exhibit 12 Disposal Well—Model Well Construction Plan Exhibit 13 Water Sample Analysis #I-Ugnu Formation Exhibit 13A Water Sample Analysis #2-Ugnu Formation Exhibit 14 Area Injection Order #2 Map Exhibit 15 Project Injection Rate for Water Disposal Exhibit 16 Project Cumulative Injection for Water Disposal Exhibit 17 Produced Water Sample Appendix A Affidavit of Delivery Appendix B Fracture Study Well B-50 Appendix C Fracture Study Well B-34 Appendix D Area Injection Order #2 and Map Appendix E Ugnu Fresh Water Cost Study Hilcorp Alaska, LLC: Area DIO Application: MPU Moose Pad Page v This page left blank Hilcorp Alaska, LLC: Area DIO Application: MPU Moose Pad Page vi 1. Introduction and Project Overview The Milne Point Unit (MPU) oil field is located on the North Slope of Alaska as shown on Exhibit 1. It is adjacent to the Prudhoe Bay and Kuparuk River Units as shown on Exhibit 2. Exhibit 2A is a map showing the MPU leases and the MPU Participating Areas. The Unit includes development well and service well drilling pads connected to a central production facility by roads and pipelines. The common flowlines carry a mixture of oil/gas/water to the central processing facility for separation. The oil is shipped to the Trans -Alaska Pipeline. The wells in the field currently produce approximately 21,000 barrels of oil per day. A successful oil recovery mechanism has been instituted at Milne Point that utilizes injection of lower -salinity source water in some enhanced recovery water injection wells, rather than higher salinity produced water. Injecting lower salinity source water, sourced from the Prince Creek Formation, requires diverting a portion of the produced water for injection into disposal wells completed in the Ugnu Formation. The proposed Class II disposal wells are being drilled principally to enable low -salinity injection at the newly constructed Moose Pad, as well as handling fluids from the preexisting F and L pad areas of the field. Injection of the Milne Point produced water stream into the proposed Class II disposal wells will allow for more Prince Creek source water to be injected for enhanced oil recovery operations. The Prince Creek water source is low salinity (3000 ppm) compared to the Milne Point produced water (approx. 15,000 ppm). Milne Point field performance data, core studies, and a single well tracer test in the Borealis development all show approximately 5% incremental oil recovery associated with the injection of Low Salinity water into the Kuparuk Formation. The disposal wells will be sited on the recently -constructed Moose Pad in an area where all aquifers below the 1,955 -foot thick permafrost have been granted an aquifer exemption (AEO #2) by the Alaska Oil and Gas Conservation Commission (AOGCC). The subsurface geology is very compatible with the proposed Class II disposal operations. The sandstone intervals, or receiving zones, are extensive and interbedded with thick mudstones/shales that make for intermediate confining intervals lying below the main upper confining zone. Similar injectate has been successfully disposed of into this formation for many years at other North Slope Class I and Class II UIC program sites, including at Milne Point at B Pad. These UIC programs are approved, supervised and monitored by either the EPA or the AOGCC. Deep well injection remains the most environmentally sound and cost-effective method for permanent disposal of oil field waste, and one that meets the Hilcorp goal of zero surface discharge and minimal storage. In addition, Hilcorp has demonstrated the corporate commitment and financial resources necessary to implement successful Class I and Class II injection programs at Milne Point, including proper future well abandonment and final closure. The Milne Point Class II disposal wells will receive fluids with very low solids content and with a very low relative viscosity. It is not anticipated that these wells will be used to inject "Grind and Inject' type fluids. This low -viscosity, low -solids -content fluid composition in itself reduces the likelihood of significant fracturing of the proposed injection interval given its unconsolidated nature. Hilcorp Alaska, LLC: Area DIO Application: MPU Moose Pad Pagel of 27 Produced water and excess source water will comprise about 99% of the injected waste stream. The remaining 1% of the waste stream will consist of various combinations of well bore freeze protect fluid (such as diesel, crude oil and methanol/glycol mix), line heater boiler condensation fluids, well flow -back fluids and other miscellaneous Class I1 -eligible production waste. Exhibit 3 shows the proposed DIO area and the proposed bottom hole locations of the requested four (4) Class II disposal wells. At this time it is anticipated that only two disposal wells will be drilled initially. Additional disposal wells will be drilled as needed. Listed below is the legal description of the proposed Disposal Injection Order Area and the identification of the disposal interval and the upper and lower confining intervals as indicated on the type log, Milne Point Unit M-01 well (MPM-01) (Exhibit 11). Legal Description for the Moose Pad Disposal Injection Order Area T13N,R9E Section 12 S % S''/z, NE'/4 SE 1/4 Section 13 all Section 14 all Section 23 N %2 Section 24 N T 13N, R 10E Section 7 SW %4 Section 18 W '/z Section 19 NW '/4 Identification of the upper and lower confining intervals and the disposal interval is noted on the disposal well type log MPM-01 (Exhibits I IA, I IB and 11 C). The disposal interval is generally defined as the upper Ugnu interval Measured TVDSS Exhibits 11-A, 11-B and 11-C are taken from the type log and separately show the upper confining interval, the disposal interval and the lower confining interval. Hilcorp Alaska, LLC: Area DIO Application: MPU Moose Pad Page 2 of 27 Depth Base permafrost 1956 -1773 Top source water interval 1994 -1806 [Prince Creek Formation] Base source water interval 2854 -2413 [Prince Creek Formation] Top upper confining interval 2854 -2413 [Upper Ugnu Formation] Base upper confining interval 3282 -2714 " Top disposal interval 3282 -2714 " Base disposal interval 3912 -3187 " Top lower confining interval 3912 -3187 " Base lower confining interval 4033 -3280 [Upper Ugnu Formation] Exhibits 11-A, 11-B and 11-C are taken from the type log and separately show the upper confining interval, the disposal interval and the lower confining interval. Hilcorp Alaska, LLC: Area DIO Application: MPU Moose Pad Page 2 of 27 The DIO area is wholly contained within the MPU area and wholly contained within the existing Milne Point Unit Aquifer Exemption Order (AEO) Area. 2. Disposal Injection Order Regulatory Criteria as Listed in 20 AAC 25.252 Part C 2.1 20 AAC 25.252 (c)(1)Well Locations Exhibit 1 is a regional map showing the general location of the Milne Point Unit (MPU) located on the North Slope of Alaska. Exhibits 2 and 2A show the specific MPU area and the specific Moose Pad area. Exhibit 2A also shows the MPU oil and gas leases. Hilcorp and BP Exploration (Alaska), Inc. (BPXA) are the joint owners of the MPU leases. Exhibit 3 shows the proposed bottom hole locations for the four proposed Class II disposal wells that will be drilled from the Moose Pad as well as the proposed DIO area. There are no known drinking water wells in the proposed DIO area. There are several plugged and abandoned exploratory wells in the DIO area. In addition, there are several wells completed in the deeper Kuparuk formation that are directionally drilled from L pad and that have bottom hole locations in the DIO area. These deeper Kuparuk formation wells are located well below the proposed Ugnu disposal interval. Exhibit 4 shows all the wells in the DIO area, including the plugged and abandoned exploratory wells and the wells directionally drilled to the deeper Kuparuk formation, are located under the proposed DIO area. The well files and logs for the plugged and abandoned exploratory wells, as well as the L and F Pads' deep Kuparuk wells, are on file with the AOGCC and are not included with this application. Exhibit 5 is reserved. Exhibits 6 and 6A are the Moose Pad facilities maps showing the roads and pipelines. Exhibit 7 is a satellite image covering the Moose Pad area and proposed DIO area. Exhibit 8 is reserved. Exhibit 9 shows the proposed well courses for the proposed disposal wells. The bottom hole locations for the disposal wells are limited to a horizontal distance of 4660 feet from the surface location on the Moose Pad in order to assure efficient drilling, completion and workover operations. The bottom hole location is measured at the base (bottom) of the proposed disposal interval. Based on the proposed well bore trajectory drilling design the disposal wells need to drill into the top of the proposed disposal interval no further than 3400 feet from the surface location. These directional reach arcs to both the top and the bottom of the disposal interval are shown on Exhibit 9. The %4 mile area of review (for the injection interval) indicates that currently there are no active wells in the review area of the proposed injection wells. New production and injection wells will be drilled from Moose pad in the future to produce oil from the Schrader Bluff (and possibly the Kuparuk and Sag River) formation. Four plugged and abandoned wells are within the DIO area. Only the Simpson Lagoon 32-14 well is within '/4 mile of a proposed well (Location 1) in the disposal interval. Hilcorp Alaska, LLC: Area DIO Application: MPU Moose Pad Page 3 of 27 All disposal wells will be located at least 1880 feet from the MPU unit boundary and at least 1880 feet from the boundary of the existing Aquifer Exemption Order area. The 1,880 foot offset distance is based on the calculated radius of the final injectate plume in the disposal wells based on a two -well project. The final radius of the injectate plume would be less than 1,880 feet for a three -well disposal program (approximately 1,530 foot radius plume) and even less for a four - well disposal program (approximately 1,320 foot radius plume). Exhibits 10A, lOB and 10C show the plume area of the injectate after 17 years of injection based on different two -well disposal well scenarios (355 million barrels equally divided and injected into the two wells). Exhibit 10 shows the final injectate plume radius for all four wells even though the final plume radius on this exhibit is based on just a two -well program in order to show the overlap or lack of overlap of the final plumes. 2.2 20 AAC 25.252 (c)(2) and (c)(3) Surface Owners and Operators; Notice Hilcorp is the only operator in the proposed DIO area. The State of Alaska is the surface owner in the proposed DIO area. A copy of this application was transmitted to the Alaska Department of Natural Resources (ADNR) and a copy of an affidavit is attached (Appendix A) affirming that the ADNR was provided a copy of the application. 2.3 20 AAC 25.252 (c)(4) Geologic Details: Injection Zone and Upper/Lower Confining Zones The type log for the DIO area (Exhibit 11) is the Milne Point M-01 (MPM-01) well. Exhibits I IA, I IB and I IC show expanded views of the upper confining interval, disposal interval and the lower confining interval, respectively using the type log. MPM-01 was chosen as the type log because of its relatively complete logging coverage, and its proximity to the proposed development area and disposal well site. 2.3.1 Geology Deposition/Lithology/Stratigraphy A series of markers have been correlated across the Milne Point Field. These geological markers have been defined from wireline log data and core samples. These markers are shown on the generalized cross-section (Exhibit 11 D), and on the type log MPM-01 (Exhibit 11). The continuity of the stratigraphic units is demonstrated on the generalized cross-section (Exhibit 11 D), and the seismic cross sections (Exhibits 11 E-1 and l l E-2). Exhibit 11 E shows the location of the two seismic lines. Formation Names Age Marker(s) Formation Depositional environment and lithology Pleistocene Gubik Fm. Fluvial gravels, sands, silts, and shales. Eocene-Mio SV1 ne-Mi Sagavanirktok Fm. Deltaic and shoreline sand, silt and shale packages. Palaeocene UG4 Top Ugnu Fm. Fluvial sands, silts and shales. Palaeocene UG3 Ugnu Fm. Fluvial/deltaic, silts, and shales. Low W.G. Palaeocene LA3 Ugnu Fm. Fluvial sands, silts and shales. Very sandy. Palaeocene LD Ugnu Fm. Fluvial sands, silts and shales. Hilcorp Alaska, LLC: Area DID Application: MPU Moose Pad Page 4 of 27 Palaeocene MB Ugnu Fm. Fluvial sands, silts and shales. Very sandy. Maastrich. NA - OBA Schrader Bluff (W.Sak) Shallow marine sands, silts, and shales. Tur.-Maast. I Top Colville Seabee/Colville muds Slope muds and silts. The proposed disposal well locations have been specifically sited to maximize the offset from minor faults in the area. The confining and injection zones at the MPU are composed of sedimentary strata of Tertiary age. These strata are assigned to the Prince Creek and Ugnu formations (in ascending order) based on lithologic sequence correlations. Ugnu strata comprise the final regressive marine sequence in the Middle Brookian section of Late Cretaceous to Early Tertiary time. The overlying Sagavanirktok strata comprise at least two cycles of marine transgression -regression in the Upper Brookian section of Tertiary time (Upper Eocene to Miocene). The general stratigraphic scheme is illustrated in Exhibit 11 F. The Middle Brookian sequence is capped by alluvial and deltaic, fine to coarse grained, sandstone (Ugnu/Prince Creek Formation). The sands throughout the Schrader Bluff to Ugnu interval are moderately to poorly consolidated and contain a large component of ductile lithic sand grains. The sandstone porosity is more susceptible to degradation by compaction, rather than cementation. The Upper Brookian sequences (Sagavanirktok Formation) begin with a shale unit that is the result of a depositional transgression that created a subsiding muddy shelf. This shale is overlain by a series of coarsening up sequences of shales, silt and fine to very coarse sands. These coarsening upward sequences were deposited in a deltaic to shoreline environment. Another transgression resulted in shelf mud deposition creating a shale unit that is overlain by approximately 1,500 feet of largely coarse sand and gravel that resulted from the final regressive phase of the Sagavanirktok Formation. Some interpreters refer to the gravels in the shallow west part of the section as the Gubik Formation. The transition into permafrost is wholly contained within the Sagavanirktok and Gubik intervals in the Milne Point area. The proposed waste injection and confining zones do not outcrop in the local area. The permafrost (generally +/-1800 feet thick in the onshore areas) is considered a barrier to recharge. The permafrost becomes shallower and less consistent offshore, eventually pinching out beyond the barrier islands. There is still significant permafrost present at Milne Point, and the base of the permafrost is projected to be 1800-1900 feet in depth. 2.3.2 Injection and Confining Zones The proposed injection and upper/lower confining zones at the Milne Point Moose Pad are within the Ugnu formation. The upper confining zone consists primarily of silts and shales, capped by a thick and laterally extensive shale interval. The upper confining zone is below the Prince Creek, Sagavanirktok and Gubik sands and gravels that extend upward into the permafrost. Hilcorp Alaska, LLC: Area DIO Application: MPU Moose Pad Page 5 of 27 Lower Confining Zone The lower confining zone is approximately 93 feet thick. It includes three separate thick shale intervals. The base of the lower confining interval is the top of the Ugnu heavy oil zone. See Exhibit 11 C. The top of the lower confining interval is defined as the MP LD marker and the base of the interval is defined as the MP UG MB marker. Injection Zone: The transition from shales of the Colville Muds to deltaic and fluvial sands in the Schrader Bluff and Ugnu is part of a large regression in the Middle Brookian. The base of the injection interval is defined as the MP LD marker (Exhibit I IB). There are approximately 342 feet of net good sands within the proposed 472 foot gross injection zone. These sands are primarily fluvial in origin. The top of the injection zone is picked near the Ugnu Coal 1 at the base of a laterally continuous shale interval within the upper Ugnu. The Ugnu sands are poorly consolidated. They retain significant original porosity and permeability (average of 30-32% porosity, an average permeability of 1000 millidarcies, with a range of 10-2000 millidarcies. The overlying silt and shale barrier provides confinement immediately above. These sands are used very successfully for waste disposal in the Prudhoe Bay area and other parts of the Milne Point field. Upper Confining Zone: The upper confining zone is characterized by about 210 feet of silt and shale between the Ugnu Coal 1 and MP UG3 markers. This shale rich zone marks deposition on a mud dominated shelf during the maximum transgression within the Upper Brookian, and immediately precedes the regressive sequence of the Sagavanirktok that makes up most of the overburden in this area. The shale is consistent and represents a competent barrier to vertical fluid movement. 2.3.3 Structure Sub -regional dip of the beds is quite consistent and is down to the northeast. The dips are gentle (< 2 degrees). Exhibit 11 E shows the location of both a strike and a dip example seismic line for the area. Exhibit 11 E-1 is a strike seismic line and Exhibit 11 E-2 is a dip seismic line. The seismic lines show both structural dip and faulting. A structure map for the Ugnu Coal 1 horizon, top of the injection interval, is included as Exhibit 11 G. This map was constructed by mapping of 3D seismic data. The seismic interpretation was depth converted using surrounding well penetrations. The Ugnu Coal 1 horizon is one of the most seismically mapable events within the Ugnu Formation. The Milne Point area has been subjected to several episodes of faulting. The proposed disposal wells area is partially bound both to the east and west by faults in the Ugnu and Schrader Bluff intervals. The displacement of these faults is far less than the thickness of the injection interval. There will be sand -to -sand juxtaposition within the injection interval across these faults. Hydraulic isolation or restriction could occur in the sands due to shale smear along the fault plane. Hilcorp Alaska, LLC: Area DIO Application: MPU Moose Pad Page 6 of 27 Drilling and production data from the Milne Point field show that pressures are not transmitted vertically along fault planes to shallower strata. Faults frequently cause hydraulic boundaries in the Schrader Bluff oil development in the Milne Point and Kuparuk River fields. The volume of the injection zone in the proposed DIO area is considered to be more than adequate for the volume of waste proposed. The permafrost is approximately 1800 feet thick onshore, thinning and becoming less consistent offshore. Base -permafrost picks are based on resistivity and sonic log measurements. There is still significant regionally extensive permafrost across the unit. This permafrost forms an additional barrier to upward fluid migration. 2.3.4 Reservoir Properties Average rock and reservoir properties for the injection interval are discussed below. The sands in the upper Ugnu interval contain more fine-grained sand and silt intervals relative to the lower Ugnu and Schrader Bluff intervals; however, their properties are still very acceptable for waste disposal purposes. Porosity is 30% to 32%. Permeability ranges from 10 mD to 2000 mD and averages about 1000 mD. Trace amounts of hydrocarbons, primarily methane, are found within the entire stratigraphic column at Milne Point. This methane is not significant, appears to be dissolved in water, and bears no economic value. Although the possibility exists for gas hydrates to be trapped at the permafrost base, there is no indication of this in the Moose Pad area of Milne Point. There is an accumulation of Ugnu Heavy Oil below the base of the lower confining interval. See Exhibit 11 C. This helps confirms the adequacy of the lower seal of the lower confining interval. Injection pressure Minor plugging from entrained solids that could accumulate around the wellbore and could, on occasion, push the maximum injection pressure to 2500 psi; where upon well stimulation would be initiated. Hilcorp recommends an injection pressure limit of 2500 psi in the Milne Point permit. Fluid compatibility A fluid sensitivity and mineralogy analysis was performed on Tertiary core samples from Prudhoe well GC -213. The laboratory study was done in 1977 by Dowell Schlumberger, Inc. Results are summarized below. Rock Mineralogy Analysis from X-ray diffraction showed the Ugnu sands contain predominantly silica in the form of quartz (chemically a very stable mineral), with low percentages (1-15%) of feldspar, halite, pyrite, and muscovite. The clay minerals illite, chlorite, kaolinite, and montmorillinite also occurred in low percentages. No calcium carbonate is present to react with acidic fluids. Hilcorp Alaska, LLC: Area DIO Application: MPU Moose Pad Page 7 of 27 Fluid Sensitivity Laboratory testing determined that fluid movement through the formation will cause some fine particle migration, and thus a permeability reduction. Tests on the Ugnu sand also showed a sensitivity to fresh water caused primarily by unstable clay minerals, reducing the permeability. However, tests using brine solutions showed no formation sensitivity, and an enhancement of permeability was seen following treatment with stimulation fluids such as mud acid. Because the injection fluids will consist primarily of produced water and fresh waters, as shown in the Dowell study, it can be concluded that the wastes will be non-reactive with the injection zone, with the exception of potentially causing fines migration. Further evidence can be derived from existing North Slope disposal wells that have been injecting these types of wastes for over 25 years, and have not experienced downhole compatibility issues, either with formation waters or rock matrix. The confining shales and siltstones may contain significant amounts of smectite clay, which depending upon the water salinity, could swell upon contact with injected waters. This reaction would only serve to enhance the confining characteristics of the zone, without affecting the structural integrity of the formation faults. Fault Leakage The disposal area is partially bounded on two sides by faulting as shown in Exhibit 11 G. Faulting should not be an issue with waste confinement. Injection and Confining Zones Identification of the upper and lower confining intervals and the disposal interval as noted on the type log MPM-Ol (Exhibits 11, 11A, 11B and 11C)— Measured TVDSS Hilcorp Alaska, LLC: Area DIO Application: MPU Moose Pad Page 8 of 27 Depth Base permafrost 1956 -1773 Top source water interval 1994 -1806 [Prince Creek Formation] Base source water interval 2854 -2413 [Prince Creek Formation] Top upper confining interval 2854 -2413 [Upper Ugnu Formation] Base upper confining interval 3282 -2714 " Top disposal interval 3282 -2714 " Base disposal interval 3912 -3187 " Top lower confining interval 3912 -3187 " Base lower confining interval 4033 -3280 [Upper Ugnu Formation] Hilcorp Alaska, LLC: Area DIO Application: MPU Moose Pad Page 8 of 27 2.40 20 AAC 25.252 (c)(5)Well Logs Well logs from the existing wells in the proposed MPU DIO area previously have been provided to the AOGCC. Additional copies will be provided upon request. The MPM-0I type log for the DIO area is provided as Exhibit 11, 11A, IIB, and I IC. The MPM-01 well is located in the DIO area and had a complete set of logs. 2.5 20 AAC 25.252 (c)(6)Well Construction and Mechanical Integrity Description of the proposed method for demonstrating the mechanical integrity of the casing and tubing under 20 AAC 25.412 and for demonstrating that fluids will not move behind casing beyond the approved disposal or storage zone, and a description of the following: (A) Casing of the disposal or storage wells, if the wells are existing; or (B) Proposed casing program, if the disposal or storage wells are new; The Moose Pad Class II disposal wells will be constructed in accordance with AOGCC regulations. Each well will be permitted separately. A proposed model well construction plan is described below; exact casing depths, cement tops and test pressures subject to change. 10-3/4 inch surface casing will be set to ±2,100' TVD and cemented to surface. Surface casing will be tested to at least 2,500 psi. The cement shoe will be drilled out and formation fit tested (FIT) to ±12.5 ppg. Following drilling of the production hole, 7-5/8 inch production casing will be set to ±3,300' TVD. Production casing will be cemented up to ±2,100' TVD with freeze protect circulated down the 7-5/8 inch by 10-3/4 inch Outer Annulus (OA) leaving an open OA shoe. 7-5/8 inch cement top will be confirmed by a cement bond log. Analysis of the cement bond log will confirm adequate cement behind casing to prevent vertical migration of disposal fluids per 20 AAC 25.412.d. Once cemented, the production casing will be tested to at least 2500 psi to confirm integrity, A 5-1/2 inch upper completion will then be run down to ±2,700' TVD. A 5-'/2 inch by 7-5/8 inch packer will be set at ±2,650' TVD to isolate the tubing by casing Inner Annulus (IA) at the bottom of the confining layer / top of injection zone. The IA will be tested to at least 2500 psi to confirm integrity of the tubing, packer and production casing. IA pressures will be monitored daily unless prevented by weather or emergency and results will be reported on the Monthly Injection Report. Waiver Request A waiver request to 20 AAC 25.412(b) requirement to allow more than 200 feet between the packer and the bottom perforations in the initial injection zone will be submitted .. This will allow through -tubing access to the entire requested disposal zone. Initially the disposal wells will Hilcorp Alaska, LLC: Area DIO Application: MPU Moose Pad Page 9 of 27 be perforated only in the lower portion of the disposal interval. It is requested that the packer in the injection well be allowed to be set at the base of the upper confining interval. The proposed model well configuration is shown in Exhibit 12. 2.6 20 AAC 25.252 (c)(7)Waste Sources, Types and Volumes; Compatibility Fluids that will be injected into the Class II disposal wells are produced water, excess source water and source water not used for enhanced recovery, and 'other associated waste." Other associated wastes are defined as those wastes that are not one of the listed exempt wastes under the RCRA Regulatory Determination, or not listed as hazardous or exhibiting one of the hazardous characteristics under 40 CFR 261. It also includes those waste materials intrinsically derived from primary field operations associated with the exploration, development, or production of crude oil and natural gas (not generated as part of transportation or manufacturing process). With respect to crude oil, primary field operations include activities occurring at or near the wellhead and before the point where the oil is transferred from an individual field facility or a centrally located facility to a carrier for the transport to a refinery or a refiner. It also includes the primary, secondary and tertiary production operations. Crude oil processing, such as water separation, de -emulsifying, degassing, and storage at tank batteries associated with a specific well or wells, are examples of primary field operations. Injected fluids (to include, but not limited to): 1. Produced water including spent polymer 2. Excess or unused Prince Creek Formation Source Water 3. Freeze protect fluids including diesel, crude oil and methanol/glycol mix from Moose Pad Infrastructure, e.g., production, source water, enhanced oil recovery and Class II wells; associated piping and appurtenances 4. Other Associated Wastes a. Line heater condensation fluids b. Fluids from dewatering (pad water, exploration and production (E&P) exempt secondary containment) c. E&P -exempt bleed trailer fluids A list of exempt oil and gas wastes are included in EPA publication EPA530-K-01-004 (October 2002),"Exemption of Oil and Gas Exploration and Production Wastes from Federal Hazardous Waste Regulations." The exemption includes drill cuttings, mud, produced fluids, reserve pit waste, rig wash, formation materials, completion fluids, workover fluids, stimulation fluids and solids, tracer materials, glycol dehydration wastes, naturally occurring radioactive material scale slurries, precipitation accumulating within production impoundment areas, tank bottoms, production chemicals used in wells, and other fluids brought to surface and generated in connection with oil and gas development activities. Hilcorp Alaska, LLC: Area DIO Application: MPU Moose Pad Page 10 of 27 Maximum Anticipated Disposal Volume by Major category: Well freeze protect fluids less than 1% (1,000,000 bbl) Well workover fluids and flush less than 1% (1,000,000 bbl) Produced water and Excess Source water at least 99% (352,000,000 bbl) Heater condensate less than 1% (1,000,000 bbl) Total Volume (est. 17 year project life) +/- 355,000,000 bbl Injection Rate and Volume: The average daily injection rate is estimated to be 27,000 b/d per well for the two well case. Maximum injection rate per well for the two -well case is expected to be 36,000 b/d. If the two wells remain active in this manner for 17 years this would generate a cumulative disposal volume of 177,500,000 barrels per well. This would generate a radial plume in the injection zone around each well of +/-1,880 feet assuming radial flow, 300 -feet of vertical net sand in the injection zone, full vertical zone fill up and 100% full pore space displacement by the injectate. Exhibits 10A, 10B and IOC show the radius of the injectate plume after 17 years of injection for several possible two well cases assuming four possible well locations to choose from. The center of the plume is located where the proposed disposal well penetrates the top of the disposal interval. Exhibit IOD shows the final injectate plume radius based on the location of where the bottoms of the proposed injection wells are located. The injection zone was assumed to have 300 feet of net sand when calculating the area of the injectate plume. The type log shows about 342 vertical feet of net sand in the disposal zone. In the MPU for disposal well B-50, total fluid injected for disposal is in excess of 120 million barrels over the last 13 years. For disposal well B-24, total fluid injected for disposal is in excess of 6.5 million barrels over the last 2 years. For disposal well B-34, total fluid injected for disposal is in excess of 250 thousand barrels over the last year. There have been no well mechanical integrity issues or receiving formation problems with the three existing MPU disposal wells. The Milne Point Class 1I wells will receive liquids with very low solids content and with a relatively low viscosity. It is not anticipated that these wells will be used to inject "Grind and Inject' type fluids. This low -viscosity, low -solids fluid composition in itself reduces the likelihood of any significant fracturing of the proposed injection interval, when compared to disposal wells that receive more viscous "Grind and Inject' type fluids. Produced water and excess source water will comprise about 99% of the waste stream. The remaining 1% of the waste stream will consist of various combinations of well bore freeze protect fluid (such as diesel, crude oil and methanol/glycol mix), line heater condensation fluids, well flow -backs, reserve pit dewatering, and miscellaneous production waste. Exhibits 15 and 16 show the estimated injection rate and cumulative injected volume for the project over time. Hilcorp Alaska, LLC: Area DIO Application: MPU Moose Pad Page 11 of 27 2.7 20 AAC 25.252 (c)(7) (continued) Compatibility of Fluids and Formation Hilcorp does not have a water sample from the proposed DIO interval in the immediate Moose pad area. However, Hilcorp is conducting disposal operation in the B-24, B-34 and B-50 Class I disposal wells at B pad in the MPU. Disposal fluids are injected into the Ugnu formation at B pad. Log and cuttings data from the existing wells in the Moose Pad area show that the geology in the Moose Pad area is comparable to the B pad area with respect to the Ugnu formation properties, other than depth. The lithology of the injection zone is typical of the nearby existing injection wells. The proposed injection zone is typical for injection wells within the area that have operated without incident over the last 12 years at the MPU and even longer in other North Slope fields. All the Long term existing evidence suggests that the injectate will be compatible with the fluids and the formation properties of the injection interval. Exhibit 17 is a MPU produced water sample analysis. There is nothing to indicate that produced water cannot be successfully injected into the Ugnu formation at Moose Pad. 2.8 20 AAC 25.252 (c)(8)Average and Maximum Injection Pressure At the anticipated injection rate of 27,000 b/d per well (2 -well case), injection pressure is estimated to average between 2,000 — 2,300 psi. If temporary blockage of the well tubulars or perforations should occur then injection pressures of up to 2500 psi may be required to clean up the perforations and restore normal injection operations. Therefore, a maximum injection pressure of 2500 psi is requested. The combined pump pressure and hydrostatic head at the bottom of the wellbore are generally above the theoretical fracture gradient. However, as discussed in Section 2.3, due to the unconsolidated nature of the formation in the disposal interval, very minimal fracturing of the disposal interval is expected. In addition, fracturing studies were conducted for the B-50 and 13- 34 wells on B Pad in the MPU showed that the confining intervals would not be fractured by injection into the disposal interval even in the case where a small +/-100 foot vertical fracture was initiated in the disposal interval under a very high injection rate scenario. These fracture studies are included as Appendices B and C. A maximum surface injection pressure of 2,500 psi is requested. 2.9 20 AAC 25.252 (c)(9)Waste Confinement and Fracture Studies Injection of fluids in the disposal interval, as planned, is not expected to cause significant fractures in the disposal interval given the unconsolidated nature of the interval. No fracture growth into the upper or lower confining intervals is expected at all over the life of the project. As a part of the work performed in connection with the permitting of MPU Class I disposal wells (wells B-50 and B-34), fracture modeling studies were undertaken at MPU B Pad to help quantify the behavior of injecting fluids into the Ugnu formation. A three-dimensional hydraulic Hilcorp Alaska, LLC: Area DIO Application: MPU Moose Pad Page 12 of 27 fracturing simulator was used to predict fracture growth during injection. Schlumberger conducted analyses that were reviewed and are included as Appendix B. Rock properties used in the model were based on well data and calculated from well logs. The fracture gradient was itself then calibrated to break -down data obtained from those wells. The fracture report in Appendix B details the model input data. The sand members that constitute the modeled injection zone are shown on the type log in the study. For the Moose Pad project, the lower part of the injection interval is planned to be utilized first with additional perforations being added above the initial perforations within the injection interval as the need arises. Injection of fluids will generally be on a continuous basis since produced water will be the primary injected fluid. Injection rates are planned to be 27,000 b/d per well. In all cases in the fracture study, injection at up to 35,000 b/d of water does not initiate fractures that penetrate the upper confining zone or breach the lower confining shale or intersect the closest wellbores. Below is an excerpt of the text from the Schlumberger Fracture Study enclosed as Appendix B. Note: scenario modeled at injection rate of 35,000 b/d of water. [References to sections and exhibits in the text/quote below refer to the Schlumberger study] [Begin quote] "Fracturing of the Upper Confining Zone: A fracture modeling study was undertaken to understand and quantify the injectivity of the proposed injection interval, assess zone containment, and determine the area of influence resulting from long-term injection. The fracture modeling indicates that the confining zone will not be penetrated by hydraulic fracturing. An industry available three-dimensional fracturing simulator was used to predict fracture growth from the anticipated produced water/wastewater injection operation. Average rock and fluid properties for the primary injection interval were calculated from open hole wireline log data from the nearby MPB-02 well. Rock strength data was also determined from log calculations. Exhibit 6-2 discusses and details the result of fracture modeling using the most adverse reservoir properties, fluid properties, and maximum injection conditions. At the most extreme conditions, using the hard rock, single planer simulator, this would generate a fracture with the most extreme dimensions. The fracture developed with a height of 101 feet and a horizontal length of 336 feet. With the disposal well completed in the lower part of the injection zone, the top of the modeled fracture would be approximately 350 vertical feet below the base of the confining zone. While the hard rock simulator predicts a single planer fracture, it is known that in soft formations multiple fractures occur over time when the fracture gradient is exceeded. As pointed out in Exhibit 6-2 the predicted dimension should never be reached. This conclusion is further supported by the long-term performance at other North Slope disposal sites, in which large produced water volumes have been placed in the soft rock, Ugnu formation, with minimal fracturing. The other North Slope disposal Hilcorp Alaska, LLC: Area DIO Application: MPU Moose Pad Page 13 of 27 operations are summarized in the following Section 6.2.2. Based on the results of the conservative modeling study and historical operating experience, it is extremely unlikely that the confining zone could be penetrated from hydraulic fracturing." [End of quote] A fracture study was also conducted for the B-34 disposal well at MPU B Pad. A copy of this study is enclosed as Appendix C. That study, performed by Hilcorp, focused primarily on the injection of drill cuttings slung, not produced water. The study showed that the injection of viscous slurry (34 cp) at relatively high daily rates (11,000 b/d) would not initiate fractures into the confining layers due to the receptive nature of the disposal interval. Reservoir Faulting: The geological and geophysical mapping previously discussed support the understanding that there are no known transmissive faults in or near the areas near the wellbore sections in the disposal wells that will be receiving injected fluids. The bottom hole locations of the disposal wells will be located such to avoid the mapped faults in the DIO area. In addition„ transmissive faults in the injection zones in other MPU waste disposal well projects have not been observed. Faulting and leakage of fluids across faults should not be an issue with regard to waste confinement in the proposed DIO area. Nearby Un -cemented Wellbores: Within the '/4 mile area of review, as well as within the entire DIO area, there are no improperly cased or cemented wells. The existing wells in the DIO area that penetrate the Ugnu formation are listed below: Well M-01 (PTD 183-182) Well M-0IA (PTD 184-033) Well Simpson Lagoon 32-14 (PTD 69-52) Well Simpson Lagoon 32-14A (PTD 69-79) As previously noted, there are deep Kuparuk formation wells directionally drilled from nearby pads. Conclusion: Wastes are expected to be fully confined within the injection zone. 2.10 20 AAC 25.252 (c)(10) and (c)(11) Formation Water Salinity and Aquifer Exemption Hilcorp does not have a water sample from the proposed Ugnu DIO interval in the immediate Moose Pad area. Two Ugnu water samples from the K Pad area are included as Exhibit 13 (average 39,386 ppm TDS). An Ugnu water sample from the J Pad area is included as Exhibit 13A (5121 ppm TDS). MPU AEO #2 is included as Appendix D. This order includes the proposed disposal interval and covers the entire proposed DIO area. Exhibit 14 is a map of a portion of the AEO 2 exempted area in the Moose Pad area. Hilcorp updated a study that analyzes the cost of using subsurface aquifers as a source of drinking water. This study is attached as Appendix E. Given the results of this study, and the Hilcorp Alaska, LLC: Area DIO Application: MPU Moose Pad Page 14 of 27 availability of abundant fresh water from surface sources, it is very unlikely that subsurface aquifers in the proposed DIO area would ever be used as a source of fresh water. 2.11 20 AAC 25.252 (c)(12) Mechanical Integrity of Wells within the Area of Review At the proposed bottom hole locations for the four proposed disposal wells there is a single plugged and abandoned well (Simpson Lagoon 32-14) in the '/< mile area of review at the injection interval. This well is properly cemented and abandoned with downhole and surface cement plugs placed in accordance with 20 AAC 25.112. The well's surface casing is fully cemented and production casing is cemented up to 610'. Additionally a 2000' cement plug was placed in the well's production casing across the surface casing shoe, ensuring no upward fluid movement from the Ugnu. Two existing plugged and abandoned wells in the proposed DIO area outside the '/4 mile area of review but completed into the disposal interval (MPU M-01 and M-OIA) are properly cemented and abandoned. The Kuparuk formation wells drilled from L Pad underneath the proposed DIO area are completed well below the Ugnu formation and do not affect the '/< mile area of review for the proposed well locations. The future to -be -drilled production and injection wells from Moose Pad will be completed in accordance with AOGCC regulations. 2.12 20 AAC 25.252 (d) and (e) Mechanical Integrity of Injection Well; Reporting Wellbore Integrity Hilcorp will apply for the required permits from the AOGCC prior to drilling each of the proposed disposal wells. Mechanical integrity of the tubing, packer and casing will be demonstrated prior to injection with a pressure test of the wells' IA as per 20 AAC 5.412.c). An AOGCC witnessed mechanical integrity test (MIT) will be performed once the wells are on stable injection. Subsequent MIT- IAs will be performed at least once every 4 years after the date of the first AOGCC witnessed test in accordance with AOGCC Guidance Bulletin No. 10-02A "Mechanical Integrity Testing" Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by injection rate, pressure observation, survey, test, log or any other evidence, the well will be shut-in and the AOGCC will be notified within 24 hours. Reports will include injection pressure and rate and the pressure in the casing -tubing annulus on the Monthly Injection Report as per 20 AAC 25.432. Formation Testing and Integrity A baseline temperature log will be run and a baseline step rate test will be conducted prior to initial injection. A subsequent temperature log will be run within one month of stabilized injection to delineate the receiving zones of the injected fluids. Breakdown and injection pressures and shut in pressures following injection will be obtained. Upon establishing a Hilcorp Alaska, LLC: Area DIO Application: MPU Moose Pad Page 15 of 27 baseline, subsequent monitoring, testing and reporting will meet and/or exceed AOGCC requirements. 2.13 Request for Administrative Approval Authority Hilcorp requests that the following paragraph be included in the Area DIO: Upon proper application, or on its own motion, and unless notice and public hearing are otherwise required, the Commission may administratively waive the requirements of any rule stated herein or administratively amend this order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles and will not result in an increased risk of fluid movement into freshwater. 3. Summary and Conclusions This application, along with its accompanying exhibits and appendices, meet the requirements under 20 AAC 25.252 for an Area Disposal Injection Order for the Moose Pad area in the MPU. Up to four Class II disposal wells will be separately permitted in the approved DIO area. Hilcorp respectfully requests approval of the application, the request for Administrative Approval Authority, and one request for a Waiver. END Hilcorp Alaska, LLC: Area DIO Application: MPU Moose Pad Page 16 of 27 Utqiagvik (Barrow) a°ae tram River tAeade R`ver IllknrP AIn.Ln.l.l.l'. Map We, 4/232018 Arctic Ocean Beaufort Sea µRNel Kn P Nuigsut >r/ ce Rive _. North Slope Borough Milne Point Unit Moose Pad Location Vicinity J9ia9vik iBn„owl rrnjca Location Alaska Nme (�ncgotege Jun n Legend • MPU Moose Pad Project Location Exhibit 1 Alaska Albers Equal Area NAD 1983 0 10 20 30 40 50 N Miles Prujcct Location Kaktovik vr $ u �, a LL • Deadhorse a O r or n A o } I r {�9y \ p A 1 Village Name Distanceto Pro'ect Miles ' Fromm ='� 'Fm Nui sut 34.9 38.] Deadhorse z \ Kaktovik 14].3 ? Barrow 172.7 m ay_ Bete Map Laye,I Credi Esn. DeLmme. GEBCO, NOM Legend • MPU Moose Pad Project Location Exhibit 1 Alaska Albers Equal Area NAD 1983 0 10 20 30 40 50 N Miles Beaufort Sea -- Utgiagvik Ani (Barrow) oro ta11 Alaska Nome- Fairbanks Canada Anchorage CGy4f�X�fJ'Juneau. NIKAITCHUO ISI UNIT. NOR THSTAR �— UNIT �MIL`NE�, POINT UNIS BEECHEY DEWLINE POINT UNIT ONIII TS ;�' 'x•--+^-""'"""'� " 1 DUCK ISLAND O UNIT 3 Y PRUDHOE BAY UNIT � LIBERTY _� UNIT KUPARUK s RIVER. UNIT v t"" w GUITAR UNIT w b 7 c n Legend - e Pipelines " North Slope Unit Map E Oil and Gas Units (Hilcorp) Exhibit 2 Moil and Gas Units (Other Companies) 0 2 4 6 8 10 Miles E 8 0 l Iilcorp Alaska, LLC Milne Point Unit and F ticipating Areas Exhibit 2A Map Date: 4123/2018 9 10 11 Beaufort Sea ,B� 1J 14 1e - .. j - ,6 'ib 'I4 18 15 '� c� 14 - o ° r' 19 21 p, 21 18 .-. c. <2 23 24 1S -0 . C', �, r4 �. n 22 ADL355021 ADL355016 23 4 _ 25 26 29 20 25 25 29 26 2" 16 15 2 ADL355017 ADL355018 n A L'388235 ' 1r p 3 2 - s ° 22 I�\\!� 12 \ s MPU MOOSE PAD gor�oz �! L392 T3 �_ ADL04�7434 H_ A • 43` O Moose Pad Location _ `\ �\ �9�� " i3 State Leases Unit Tracts 11 4A 4 � \5 12 ♦ 14 24 „N�6 �n�e,8 `nD� ULOa7,, ACCO\38 23 State Leases ® Schrader Bluff PA .� ___, �..____ A1111-O.255N'a; kLO- 5 2s\� _ ,; - \� I ADL0I8232 26 25 Sag River PA --- - - 13 14 i�UparUk PA {33 34 35 1 31 32 33 31 35 35 27 - q 5 A L 8 ALB 231 `k 3s v3 , 2 1 ° 4 25 26 e State Pune zone4 NAD 1983 (feet)10 U012NO10E 9 .11 23 24 N\ 1 � �� \s 1, 12 i ADL375 32 9 u0?i 009r — 12 z a . 1 n DLSOa 09 A 4340 1.0 � WY'2M1!012_ 0 7 2 3 Miles 13 18 13 19 17 7�133 'I 24 19 20 21 22 2.; Map Date: 4123/2018 Simpson Lagoo •'600 ;-� Sec. 10 l 76 p�0 tof � f MPU MOOSE 12 Disposal Target #4 Sec7� I Sec.8 5 `rp l s2 1a �O� �e \ i� \Sec. Disposal �d'lwl�Ou»Sea.14___t#1'2O O,A ` I Disposasi 15 Disposal I- Target#3 13 �. Sec. 18 ?f s I arget 92 ��-- -� -(630) Sec. 17 7 KUPARUK eofr e \ \ RIVER UNIT I > 's1 MILNE U013NO09E \ + smo rif POINT U013N010E m z UNIT a n 2S2 \ a \ °12Legend Disposal Well w'i-'� 1 ? / y Bottom Hole Location (BHL) • p� \\�\ / mo sp It It , ' pF t tOther Surface Holes (SHL) $ 22 r'y \ M 011 iaJ,.cSec. 23 1($eC. 24 Sec. 1 3- Other Bottom Holes (BHL) g (633) 32-14A 1 - - - Other Well Paths om \ N 1 Subsurface Fauns \ '}`• SubsuraContoun:- M -01A _ U9nu Cash O \ + \ O Oil and Gas UnR Boundary fi \ xp0 �\\ 2° ® Pad Footprint AOUD25018 �3 O O \ 2 sO _ Disposal Inlsction OrtlerArea (DIO)AOLOM20 AUJJ 5574Aquifer EPA Aquifer Exemption Area Exemption as '\ so N Sec 27 �+ . _ c's Sec. 25 \ SBC. ID: 10_119 ID. 10 119 \ o o 1 �+ Sea 26 (636/ Milne Point Unit Alaska State Plane Zone 4 NAD 1927 Moose Pad proposed Disposal Well Locations N n, P » ••tom Exhibit 3 0 1,000 2,000 3,000 Map Date: 6/28/2018 Disposal Wells Feet lye 1ST ?''sod,' a' F 82 ,' /'\ \ .•F-99 L 02A -L ou l 01 Simpson Lagoo f ?so -Sec. 10 ?$ r/ F -Bt SeC 7 , / / 3R-20 ?$. sec..11 Sec. 12 r / \ , , ;a , / / Sec. 8 ry #' \ \R%r (628) 3R-21 ?1$ \L' \ ,'1 'i 1Fto6 I ADL355023$ /rF107 9L!4aPBi'}Ani 19969 A s Dis ADL025513 ADL025514 7 R `� Targets#4 �' " I , ADL 25515 �\.9'0' 1 �( / l� NF -108 I L -48P82 I Sy \ g \ 30-05 Tr0 30-0325-14 ' I '7 ?dr Op ' IPESAD01 i 00 ft �i y3' ✓\ 1 I so�+ Disposal \\\ } 1S5�, "->� PESAOoiAd (\ Tal # 1 - L 339v.7 2S O, /� / 1 /^yyF-110, \ F-109 i L-48PB3 S h> Sec: 14- / , # #� ,\ + �,� y ♦ �. Disposal 11 n + Sec. 15 •_ -;P16, � fo Disposal �\� �. �J Target #3 I �, �i 1 Sec 18 \ \ I \ / lal get#2 11 ♦ 1f'f. s �G. I ' '� 630 I Sec. 17 ?$ ,U013NO09E ' KUPARUK' - 30-0] �I RIVER UNIT i�.' 1'o4I MILNE ' ' i U013N010E ♦ ♦ a. o POINT - / '-32 n� T'#?S 32L -37A I'D- 11SS -/ # ` _ _ — U, Js M Legend �z 1 l e c ? I %. o 0 Nisar f o Q ( % , \2S Disposal Well _ \ / , LIVIAN01 I I I \\\I I Bottom Hole Location (BHL) }_ —30;12 30-09 \ 1S �' \� LIVIAN01Ak+j_\ I L-52 I 1 I 53 /^�,� — — — _ — — — *` / �L-20 \ 1S�p i \ , / L ,� ' / I Other Surface Holes (SHL) ?9? 1_ II )l L-37 .\del I * 54 + Other Bottom Holes (BHL) 1 HSBC. 22 x .� II M-011 ,,. Jl L-51 — _ — Other Well Paths tSec. 23 4Sec: 24 * Sec.) Injective Plume F214A 7A I (633) x(1880 ft Radius) * ? 1S Subsurface Faults 3014 iN pS0 / Subsurake Contours - 1 130-13 1 * \\ �A %f. / U9ne Coall 1 + 1 ` L-361_1 //L 3� 1QS I Iv1-01A � O Oil and Gas Unit Boundary t L-36PB1 O 'L -35A -;k' L-35APB1 ` 24A \1 \ SSO ' , L, L-35APB2 t L-3§ \ J-241_1-24LJP-E Patl Footprint ADLOM43 \� '�' �, ADL :5514 2s�O�rf. \ �` #- J -2a � • Disposal Injection OrderArea (DID) ADLO L. o rn ` �� ADL025519 � s Aquifer s 3400' Radius from SHL f N r /fe N N f N Exemption is o o J -z] sec. 3a Sec. 27 N N is Sec. 25 N N — =IN Sec. from SHL 30-18 0 0 �\ ID• 10_119' o o ,_ 636 *`p 0,_30-20 *Sec. 26 �` 0 JQ ( ) EPA Aquifer Exemption Area 130-1] Q a 1\771 IR MID: 10_119 Milne Point Unit ALL Wells in Proposed DIO Area Alaska State Plane Zone 4 NAD 1927 Moose Pad Exhibit 4 0 1,000 2,000 3,000 H,lmrpAbW,LIB Map Dale: 612812018 Disposal Wells Feet w w Soc 31 v e Sec. 32 Sec 33 Sec 34 Sec 35 U014NO09E > > U014NO10E Utgiagvlk Beaufort S e a Bartow) U013N009E U013N010E cation Kaktovik _ See. 3 Sec Sec l Set. 5 Sec. 4 Sec. 3 - 7 '.De dho se J,%MPUF Nu 9s t MPUL Sec.9 Moose Pad Flowline w w Sec 10 Sec. t4Sec. 12 Sec.7 Sec. B Tie-in Location Sec. 10 Sec. N Sea 12 o o Sec 7 Sec. 8 Moose Pad Moose Pad MPU C PZo z Location Moose Pad Electrical 0 0 \ Flowlines Tie -In Location / o \ MPUj c. 8 \` SeCSec. 15 Sec. 1M1Sml3 Moose Pad Sec. 15 VSm SecSec. 18< MM� Sec. 17 �° Ca Access Road MPU B C) 7a MPUA c b Sea 22 Sec, 23 Sec. 2, 4 j p Sec 19 Sec. 20 Sec. 21 Sec. 22 Sec. 23 Sec. 24 Sec. 19 Sec.2t MINE—� MPU CFP MILNE POINT UNIT slrE E TRACK14 MPU EQUIPMENT 'KUPARUK / INTERSECTION - MINE PAD MPU E SITE RIVER UNIT Sea V Sec. 27 Sec. 26 Sec. 25 Sec. 30 Sec. 29 t1 MPU J g Sec. 26 Sec. 25 Sec. 30 Sec. 29 S c.28 `] e POPo MPU G ;J S & K FiEC _. RLECEIVER Sec 341 Sec. 35 Sec. 36 S'ec. 31 Sec. 32 MPU H - T� a ` Sec.33 Sea 34 Sec.35 Sec. 36 Sec Se 11 DS3K MPUI North Slope Borough — Moose Pad Pipeline Alignment (MBI 11/10/2017) Milne Point Unit a Moose Pad Access Road Alaska StatePlane Zone 4 NAD 1983 (Feet) N Moose Pad Location Ililrn.p Alueka, LLf. Project Area Moose Pad Location 0 2,500 5,000 7,500 10,000 Map Date: 4/2 312 01 8 Feet Exhibit 6 Q Oil and Gas Unit Boundaries Sec. 2 MPU F (BairtowJ Beaufort See 1 w) y IBa e5c. se's Sec.1 .d 'Z. rrov e n =_eatlh orse Kaktovik Nuiq sut oc ,ac? r ob i C. 11 Be �,`�. = e Sgc. 12 J Sec. 7 8 ° Sec. �� .4 Qo�a`�s�Da ° r 0 MILNE oo ,- o �' w Access Road POINT T �V D W F VA 3 �S �} n r- o o -UNIT a a > j a�� `� 1 I'` -,z„ —POINT Do i Pipeline ieInPad r D Moose Pad;, J a 9 Elects teal Tie -[n Pad Loefon •, u o �„/8 ��� � h Moose Pad Flowl�inea �; -.sec. 14- r a a al �., e 1 • " ^, Dose ee °eesse. �, Sec 8 i� `4�� ,� Sec 17 Sec. 9& o G. Moose Pad _ U uravik River Access Road 113 ��-- , .-si. o'� of 3• ii o Y P�- North Slope Borough �� Moose Pad Pipeline Alignment (MBI 11 /1 012 0 1 7) Milne Point Unit Alaska StatePlane Zone 4 NAD 1983 (Feel) N Moose Pad Location a Moose Pad Access Road "^"°••_ AK W'° Project Area MPU Moose Pad Location 0 1,000 2,000 3,000 4,000 Feet Map Date: 4/23/2018 Exhibit 6A O Oil and Gas Unit Boundaries °:asp, Sec�7 i a , yt tl V. -'y! Si ^': � � . i"v � 1'_R `I;�: t � ..y! tid`✓ a� 4��h&:., '... , t w 3 t ZE'"a tk t r access Rotd 'd w �''� h� ,��': .�t� ^re r F a z : I giclme -t. > >? . ''. .c *:y 'a ''�"Q�Fs:a 5a" ^ I le In Pad ry Moose Pad 1 lectrical Location Pad q� s ate',;'#., Moose Pad _ MILNE M1 w } Flowlines z o M l POINT / }T o o UNIT T Sec. 13' ., Moose Pad - - ., Access Road ut is ��k Beaufort Sea z Q '�;, ti(, n •. Gamow) K kt vik i Nylgsut Tjy . r kill, �� I, a North Slope Borough — Moose Pad Pipeline Alignment (MBI 11/10/2017) Milne Point Unit 4 NAD 1 Pl t Alaska Staeane Zone 983 Feet Moose Pad Access Road (Feet) `17V1 Moose Pad Location 1 M =.•��� Project Area MPU Moose Pad Location 0 1,000 2,000 3,000 Map Date: 412MOIS Exhibit 7 O Oil and Gas Unit Boundaries Feet Simpson ^Lagoon 2s w e spy ec 7 Sec. 10 Pso01 Sec..11 Sec 12 S(628)' Sec. 8 n MPU MOOSE PAD \ , ~•f � � `!+ �M\ o ry ADL355023 a 2S2S f7-.ADL35502 ?i \`?y ADL025509 ADL025513 ^ADL025514 . , h Disposal p �p ADL025515 Target #4 �;� ably, 2�s �ti�sfi 1 % ...r 2 ��BSo 32 1 ' ♦ ` e1�\\ ,... � 1,.�-. ♦ � � �0Disposal !S E Sec. 15 al �,: Target lt3 � � \ \ S. Disposal Sec. 14/ Disposal \\\ Sec. 18 target #2 /' 1ared41 M �-._,_Sec1131"�`-"`� �� (6 O) Sec 17 3 KUPARUK� + \ e RIVER UNIT ~"/� `� ek MILNE U01 N009Ee POINT U013NO10E ♦o ♦ 2 ♦' �m� ��s UNITo v \� MRaw n vrini Legend • J J / _ 1S _r J J Disposal Well Ca Bottom Hole Location (BHL) Other surface Holes (SHL) •f / .,\IQs f',\ �, 11t -{- Other Bottom Holes (BHL) I� Other Well Paths Sec. 22` \ t M -01I x m Proposed Wellbore Trajeclories --Sec. 23 ''[Sec. 24 Sec. 19 n \w. 633 ijI ective Plume 32-14A F t ( / (1880 ft Radius) au+�'k �� \ subsurface Faults J I Subsurafce Contours - U9nu Coati s "Sp \ -0\ O Oil and Gas Unit Boundary 1 \� Pad Footprint e? ADL025513 '2r,,� \' Q�p '( ?i0�� Disposal Injection Order Afea(DID) ADL026620 sf Aquifer Sia F o rn A 3400' Radius frpn SHL Exemption 1%, \`\ N� Sec. 27 '"1 ID: 10 119 ` , Sec. 25 \ `•... o c Sec. 30 _ +4680' RatlWS Gom SHL Sec. 26 — �' \ \\ JQ QJ (636) EPA Aquifer Exemption Area Q Q QID: 10_119 o` Milne Point Unit Proposed Wellbore Trajectories Alaska State Plane zone 4 NAD 192 Moose Pad Exhibit 9 0 1,000 2,000 3,000 IlikvY AIVYv. LLC Map Date: 6/ 28/2018 Disposal Wells Feet 29S sus l Simpson tagoo� 2sso 2p Sec. 10 2oI, 11MPU MOOSE PADIt Sec. 12 Disposal "( Sec.8 target nv 1 �Qso; 32-14 +`�'•'s2 j sO'f 'F ! t aN s iNiJ ?p? 24��„f %, r Disposal 28p° ♦`�F` ►f*t I Sec>14 �� lar�ct#I r2�s, ?! , A r �`. ..I ♦ 4 ° Disposal `Sec. 15 1 'ZA Disposal • It ITarget#3 Target2 11 "' Sa (630 Sec. 17 KUPARUK 2S�Sh Aw ►s0o.� RIVER UNIT I'e s1 ��� \MILNE U013N009E / ? aJo 7 POINT I U013NO10E �4'm UNIT a r, / �IWW13;�1t NN �S SOF I —� �- Legend \ ; ° I ¢ ¢ JDisposal Well _ / O \ Bottom Hole Location (BHL) �i-` / \ may) I t1 '- �` 1 s t \ • Other Surface Holes (SHL) aOaeT \ // �pSO t ,xel 'f- Other Bottom Holes (BHL) Sec. .222 1 \ I M -o It ` t - - - Other Well Paths Sec: 23 I '�Sec�24 Sec.19Injective Plume +F \ (633)) 32-14A t / (1880 ft Radius) Subsurtace Faults t d Subsurefee U9nu Coalloal1 M -01A °• O Oil and Gas Unit Boundary EDPad Footprint Disposal Injection Order Ama(010) �3rsseo sA13ta 1 s 3 f ry rn `•� Aquifer may. \ a, At 3400' Radius from SHL \ lw. `Exemption as0 art Sec. 27 �. \\ ` ID• 10 119 `'s Sea 25 �., o o Sec.30+4660'RadiusfromSHL +W'* -7 Sec. 26, — �% OO (636) EPA Aquifer Exemption Area a Q Q QID: 10_119 o Disposal Well Injectate Final Plume Area Milne Point Unit Alaska State Plane Zone 4 NAD 1927 Moose Pad Showing All Four Wells N Hllrv,Ah,", Even Though Only Two Wells Proposed. 0 1,000 2,000 3,000 Map Date: 612812018 Disposal Wells Exhibit 10 Feet Simpson Lagooll Sec. 10 Sec 11 Sec. 12 Sec. 8 MPU MOOSE PAD ADL355023 AQL36 60 6'w AD1,025609 ADL025513 -A—DL6-255'14 dp P st 4* Sec,14 P \ I —i % I Disposal Sec. 15 Disposal Target #3 Sec. 18 I arPet 42 1, *P (630) 'ec 17 Sec, 1 ��:600 �r'o KUPARUK X RIVER UNIT U013 '009E MILNE' POINT U013NO10E UNIT $6r. f Legend ;zpj, < Disposal Well ;a A Bottom Hole Location (BHQ a Other Surface Holes BHQ t Other Bottom Holes (BHL) Sec. 22 - - - other wall Paths M,01 Sec. -23 — — — — — ..Sec�2 --Sec. 19 injective Plume 32-14A (633) M (1880 It Radius) + subsurface Faults Subsuraf� contours Ugnu Coall M -01A Oil and Gas Unit Boundary Pad Footpnnt ADLO 5 14 Disposal Ingection OrderArea (DIO) AVIL025M ADLO26519 Aquifer 34001 Radiu.from SHL e;�in io Sec. 27 X 10 19 Sec. 30 4660' Radius from SHL D Sec. 2 19 c, 26 (636) = EPA Aquifer Exemption Area -E1 ID: 10 119 r C= - Milne Point Unit Disposal Well InjeCtate Final Plume Area - Alaska State Plane Zone 4 NAD 1927 Moose Pad Two Well Scenario #1 0 1,000 2,000 3,000 Map Date, 612812018 Disposal Wells Exhibit 10A Feet sf rS Simpson L a g o o ?0s0 F� >rr ya �Q Sec. 10 ?6pl Sec. 11 Sec. 12 Sec..7 Sec. 8 (628)' r. MPU MOOSE PAD ADL355023 `SSS �i ADL3-'-- �—Vk ADLO25509 \ ADL025513 — ADL02561A' -•�� �9�, Dis�X4 T=p- ���+ AUL02MI5 Tar et {? S Sec. 14 _ _ ��� + ��S �2l E .`_..'� , Sec. 15\\-_,e 1t 'e� Disposal \ See. 1 gnur mk 'Ve Sec. 18 2� Target N2 ♦ - (630) Seo. 17 � ` ` , KUPARUK o�I o , \. RIVER UNIT ? sy MILNE U013N009.� a� sso �I POINT U013N010E UNIT vin �-=---- Legend s s I o0 ¢ _ Disposal Well Bottom Hole Location (BHL) �r O / jQ9 I Ir \ \ • Other Surface Holes (SHL) S� 'M- Other Bottom Holes (BHL) o \\ S ` Sec. 22' M-011 --- Other Well Paths a�Secr23'iSec. 24 Sec. 19 ID S�. I (633) lective Plume 32-14A t / (1880 It Radius) f a Subsurface Faults 1 _ SubsuralUgnucoall contours Ugnu Coali M -01A + I Q Oil and Gas Unit Boundary a f 5 ''\ Pad Footprint Atiltl2;'t3 ?S� vo— AOL 55514 At Disposal InlectonOrderNea(DID) 1 Aquifer ADL025519 SSS lFVAI O/ * 3400' Ratlius from SHL s N N Exemption `oS �� N N19 u Sec. 27 N N \ �S $Be. 26 N N Sec. 30 +4860'Ratlius from SHL o o I13 10 119 0 0 J J Sec. 26 - J J (636) EPAAquifer Exemption Area E ao \ co QID,10_119 Milne Point Unit Disposal Well In]ectate Final Plume Area - Alaska State Plane Zone 4 NAD 1927 Moose Pad Two Well Scenario #2 0 1,000 2,000 3,000 �1^J Ma Datee61282018 Disposal Wells Exhibit 10B Feet Simpson Lago oil sSec. 10 ?bpi .� Sec..11 "-�� Sec. 12 Sec. 7 Sec. 8 o �r .. (628) 2550 I MPU MOOSE PAD (' r� ADL356023 25?S ff ADL35502 �'1�� � � 2y ADL025509 ADL025513 J, 'ADL025514` R+O� Disposal p8 OOf ADL025515 �% I'amet#4 25.E I IOSO. 'F I', �p'r19, 32-14 S � ,24 � -- f' Disposal T s'f t� '��---�• Target#1 r��SO :ilj) ��� ( e ` Sec. 15 + —� / \ f ` Sec. 14 � .Sec. 13 U90ulavlk�,`e Sec. 18 v(630) Sec. 17 v\ ♦ '25i5 �� / �t4V KUPARUK RIVER UNIT " " a m MILNE �U013NO09E cs �I POINT I U013NO10E UNIT o v> 0 0 s2s Legend a a Disposal Well ASO O I 44f \\\\\\ � Bottom Hole Location (BHy a % \\ / �s \ \ • Other surface, Holes (SHL) o'W Other Bottom Holes (BHL) Sec. 22' e2 \ t M-011 �� — — — Other Well Paths o '� 2�sgSec: 23 1 '-Seo. 24>�`.1-, - Iv.. - _ - lIliviiIIIIIiS c.9 Infective Plume 63 32.14A �� \ 1 ` I ( ) I (1880 It Radius) E aW�` \ \ Subsurface Faults \\ S 1 Subsurffce Contours - 2��\M-01A Q Oil and Gas Unit Boundary s 1 1I Pad Footprint A,D(a12I'[$ 7 v0 ADL025514 ?O Al® \% O �.` Disposal Injection Order Area(DID) AtlLaS \ A uifer ADL025519 s� �F AI Q 3400' Ratlius tram SHL Exemption � N'fl N S Sec. 25 Sec. 30 +4660' Radius from SHL imme Sec. 27 `� po Seo. 26 ID: 10p119 S`�� \ `,.� (636) EPA AquiferExemption Area E 4 ¢ Q QID:10 ns E Milne Point Unit Disposal Well Injectate Final Plume Area - Alaska State Plane zone 4 NAD 1927 y'`� Moose Pad Two Well Scenario #3IM 0 1,00o z,000 3,000 Map Date: 61282018 Disposal Wells Exhibit 10C Feet g zgpp f id }-'1 Wt J Simpson Lagood `11ss r pQ Sec. 10 ?ppl ph - Sec. 11 \' Sec 12 Sec.7 Sec.B mo (628), I so,,rl - MPU MOOSE PAD L35>>s� _ ADL355023 2S - AD502 ?�._ ADL025509 ADL025513 ADL025514' :rp•17. Disposal ilil, ADL025515 "I'arect#4 •?5p0 ft +2-140 4F \ Sec. 15 t \ .I Sec�)14 ?S ��Seoy13 e Sec. 18 7 S� ♦ Disosal hf�i '�� '`, - (630) Sec. 17 II S•fr. TargetNl DIsg s#3 7p IG KUPARUK 2ss0p00 ( �p >S RIVER UNIT err /l UO 3N 09E 1 j zp 7pS spy 'F i i I'� ( U013NO10E ` " s Disposal �� II`I POINT UNIT pig Tar get#2 41; Exhibit 11 --Moose Pad Type Log (Adapted from the MPU M-01 well log) Confining Intervals; Disposal Interval Exhibit 11A Upper Confining Interval I f WKE WGil11 `C• e(IFAVY'AY'b m 1 I ( iLLiTb `II - I _— t i 1 f I i .t t i $. { t i 1 I i � uEuwu aeww 1. iv 4 GIs s Exhibit 11A Upper Confining Interval Exhibit 11 B DISPOSAL INTERVAL A i F8g� ,r� a 1 .F •Z OP PROPOPfO ISPOSAL � _1 � ITERVM:RW'Yfl f 16MIS5 {s t i q f f N f y 1 t Ir { 8 ' FI Q_g I 1 1 �Y l I\ 0010 D `1 ERM MWfO f I � TELIOWIX DEPTN -Cl 01M WT sm � •a ' EWPOSAL ( ASF PR(IPos[o WAD PVAL: J a YolNYT9 8' HWTVOFS �n r_y d I R 1 f � A ,r� Ira _1 t f y 1 FI Q_g �Y l I\ f $^ -Cl � •a � ( ASF PR(IPos[o L flVM:fl1YYD 8' HWTVOFS �n Exhibit 11 C LOWER CONFINING INTERVAL P 1 �y i i BASE PROPOSED DISPOSAL INTERVAL: 3912' MD -3187 TVDSS MM � ) iI APJE { t , r o� N Mrn � M ` i l s TOP HEAVY OIL UGNU MP UM. MB2 r' Exhibit 11 C LOWER CONFINING INTERVAL Exhibit 11 D Cross Section Through Disposal Area Exhibit 11 D-1 Lower Half of Cross Section Exhibit 11D Exhibit 11 D-2 Upper Half of Cross Section Exhibit 11D Exhibit 11 E Structure Map Showing Seismic Line Locations on Exhibits 11 E-1 and 11 E-2 Exhibit 11 E 1: Seismic Section -Strike Line rw�mso zao ra so z�e..o m:o ie..o zwa aeia .� "-3a-o zee o, •'€r�a"''' o��-'am w." x®a aizo a rtl4. rMO. >we _ aaooa .xrwoo.o awo. w. o mane awe mo"e am wooo Jwo.o •aao. ..«ewwya�y - iw.o w". .1 w 'or.a uc wuewwr rrao Exhibit 11 E-2: Seismic Section -Dip Line .1. 1. �'o 010 ,e.�- nm iao Sao i«.o 0 Exhibit 11 F —Stratigraphic Column for Northern Alaska. Source: DO&G, modified from Ken Bird and David Housenecht (US Geological Survey), personal communication, 2002. Age me S Rock Column NOil & Gas I Petroleums Petroleum Plays S E zi 1 r jGybikFrji. f Accumulations* i _I Systems Mostly Mostly � < 1 CenozoicS0 irtttok Fm - (source rocks) Sti6li r hic Structural , E .. irrai Ph - c N 0 0 PnnteCreekfm. shrader sljCanningF ' 10 � mNanushuk _E `Cretaceous T ° - Peb le _- TorokaleZ_ (oil source) too Kingak G Shalecu�apaa+.rl oNLL Kingak- 'Q.UJurJurassic c .l Blankenship 3FL M ? Shublik Fm. ( . _ a sem. (oil source) m L J r iU m III Z zos ..•mr , Shublik - Otuk � Sag River L t; Q Triassic Sadierochl (oil source) 203 Group "9 K.. c Sadlero&.4 9 gPermian Z _ .© Ecnopka ::1E 320 (1)Penn. Lisburne jUsburne(Kuna), m LSCume Q J Group - E.y,,Oe (oil source) ® IL: Ji Z J Mississippian, Endicott w Erdwtt (Kekiktuk) Y — 380- - f (on source) Z F Pre - •o+,ro«*,m Mississippian Basement"' Column [JNonmarine Marine slope & basin MCarbonates Rock NGranite Legend [�]MarineShelf IJ Condensed marine shale 99 Metasedimentary ❑ Hiatus Or erosion IAWraE M1dr. Nen&b W DaM Hw�vecMN.s. GetloeG S•^'eYz pertarW rnmuM2Wit 3W2 Exhibit 11 F —Stratigraphic Column for Northern Alaska. Source: DO&G, modified from Ken Bird and David Housenecht (US Geological Survey), personal communication, 2002. vS s 2Sr � �Lego 87mpson o ,l{II esye >o Sec. 10. 9 'dcp�l� Sec 11 ��� \\ \. See. 12 626) Sec 8 vim\ _ ADL03T 2ys � L550 a , UWa� AOU20 1ADL025513 coy ;Vi f% 4F[`I] M'.� Sec. 15 fff ., T «3UW1 � 31 ! \\(1)6 :I Sec. 17 �.., -_.., 8 '�!' oe� �'_ ♦20° �..'� KUPARUK RIVER UNR ,� •• `. '0' MILNE U013N009y0,, ., U013NO10E .•\\\:a �o3e �!, S s� > POINT 40 UNIT 1•, \ Legend �, 1 �\ \ � �� Yj� � ,1 \ \\ l � � • Oex, A«akabx l9XLl �J \�. \ \ Y� �\ \ I ♦ Oee. B�uomxokslBKl iLi� Sec 22. rpyvSec.•23 :�.� �\ 0-as.+5ec14 _ Sec19 . �633) oav ft mb pb y •� \ \ � � SuewrWaa Co-pwn. Q^{0.iva Gw Vnl Bavgazy �\ SAD "liz, ADL025513 2,T $ „N, AlOoswwlm�o:awan.lOot ADL0255W J� '. \ Aqulte! �, ..Px6mP?IOn ow7wra Famµmbw Sec z] ..ri .. .. 2y �`., `� g91 ` ID; 10 119 Set.25 ,a3 Sec. T6, — i \\\ la,a ne See '3)0 (636)�SwdPaJus«wn4A Milne Point Unit Ugnu Coal 91 Structure Map (25 It C.1.) Ae5ka Shue Pl m Zane4 NAD 1927 Moose Pad Approximate Top of Disposal Interval 0 1.000 2.00D 3.000 a w naao,e Disposal Wells Exhibit# oFftt 1J='IRXNX4�lr1a1AL'jYG rvL-rmws)!ros-3py1VTy NbFutl '9] Exhibit 12 MILL Milnev Pa Unh 6N11 SCHEMATIC TBD URCm kC d -TSD uw.wnu.L.. uu KD: TmP�re4'TBD KD: TBD ni Jri.l¢'/4LtlN-3!C *vfe4wEWEnP 1J='IRXNX4�lr1a1AL'jYG rvL-rmws)!ros-3py1VTy NbFutl '9] Exhibit 12 MILL WEN FIXEfC EWp AIL 6N11 1 TBD �'IiAv mtangYpiRu 2 -2,63D ND 5-1 %Nip, 10-4562- Ea�mYbY14t -^-,550'ND 7-5/8'x5-1/2^Packer 4 YN' 5.1/YXNipJG-4562" 5 -2,680'7VD TUOxuWGSIW DFML 6 ^ ,7WD D Sx TypC N(/GK'e(4m MR0 TW M i9O CwN® T6'J)}Pi P'] X/A Su -S=e -3J?'l9 LLMC SVY¢ iL11 L;n/P_] Aery' Subce -23Wn'J T -UT O.Mwaa� 1151' Soba nnavraosmb« 13 -zroo'n 1 MILL W6MA MAIL RW i8P NN[NNlAf��6 GP]ITM fl] 6N11 1 TBD Tub- H er 2 -2,63D ND 5-1 %Nip, 10-4562- 3 -^-,550'ND 7-5/8'x5-1/2^Packer 4 -2,57O MM 5.1/YXNipJG-4562" 5 -2,680'7VD 5112"XN Nip, 10-4455- 6 ^ ,7WD D I WUG M?V Tg p AT L SnC TW 2N01 MtMpF TW, ) Cen iwPl ? 0.m 50uc Y TEL T6] •f IW ^1,1W' 'bP RO ...amxNuwnM BERA'■ HUON" Hilcorp Ak ska LLC Milne Point Lease Water Analys s Summary Water Suppli Water - Water Analysis Exhibit 13 Date Sampled WNI Formation APIA Lift Type Surf.¢ Pressure PAG Surface Temp.'F Downhole Pressure PSIG Downhole Temp.'F Average Wel(Test Wea Test Datellange Magnesium Strontium barium Iron Manganese Date CNbdde ll7) SuNate (SOa'7 (Siozl (Na} Potassiu 09/08/16 K-34 WSW UGNU 50 -029 -22712 -OD -00 ESP 2,072 as 1,934 133 1OWTA 09/29116 10/08/16 11/05/16 K-34 WSW UGNU 50-029-22712-00-00 ESP 2656 95 1925.7 91.62 90-WTA 09/12/16 12/12/16 I Cahvlate SPedfic awarboru DissoM Date dMS Gravity te(NCOa} CO. Sampled Well Oas MiCF Dag mg/L I (g/C-1) pM I mg/l. mg/L WSW K-34 100.0 Dissolved Dr PPB K-34 a0A1 & VA ANIONS' CATIONS' Sifra Sodium Magnesium Strontium barium Iron Manganese Date CNbdde ll7) SuNate (SOa'7 (Siozl (Na} Potassiu IM¢=•1 Calcium (Sr,'I (6aa} Oe°} (Mn'} Total Sampled Well mg/L RIA OWL rrgf, m(K') mg/L (Cat)mg/L mg/L -WIL mg/L M/L Hardness K-34 a0A1 & VA PAP Coast Area La scratory BAKER 3901 Fansoclo W, EE HUGHES Shafle6 Caldoms, 93263 COMPLETE WATER ANALYSIS REPORT 551str.2010 CUSTOMER: HRCORP ALASKA, LLC DISTMCT; ALASKA AREA2LEASE: MILNE POINT SAMPLE POINT NAME WELL 1-02 WSW SITE TYPE: WELL SITES SAMPLE POINT DESCRIPTION: WELLHEAD Exhibit 13A ACCOUNT REP: SAMPLE ID: SAMPLE DATE ANALYSIS DATE: ANALYST: Upstream Chemicals HILCORP ALASKA, LLC, MILNE POINT, WELL J-02 WSW FRED DATA Initial Temperature ('N: flml Temperature ('F): moral Pressure(Pri): Trial Pressure (may, PH: PH at time or sampling: NWMfarsPMPPt mg/L meyL Bicarbonate oICO.- P. 150.0 Carbonate(CO"P. ND Hydroxide (ON): NO aqueour Cor (pass: ayueord Has (ppm): aqueous 02 Limb): Calculated TDS (mg/D: Demay/Swinc Gravity (91.`1; Measured SPecitic Gravity Cooductimy(mmhos): Resistivity: MCF/D: BOPO: BWPD: REPORT DATE: 11/30/2016 CLYDE WIDE 2016pfipM699 1115(2016 11/21/2016 DULL 2.5 OAGANICAUpy 10.0 Formic And NO Acetic Acid: NO PropioNc Acid: Buy0c Acid: 5121 Valenc Acid: 1.0006 NO 8.] ND No Data No Data NO Data Amon/Cation patio: Alummu. (Al"): NO Chromium (Crs'Y ANIONS: m9/L meq/L • CATIONS m me 62 Chloride (Cf): 2775.799 ]8.3 5odlmn (Na'). 983.5 42 a2.e 70 Ideate ISO,', 11 0.0 Potassium (K'): 970.2 20.8 1150 Borate 01,1100): NO Magnesmm (Mg" 1: 16.9 1.2 2100 fiuoride(il: NO Calcium (C,"): 192.9 9.9 Bromide 030: ND Strontium(Sra7: 1.8 0.0 N.Wte (NO,): NO Bamm (Ba°'); L3 Do 7.3 Nitrate (NO, V NO Jr. Ne"): a.T OS Phosphate (POar'1: ND Manganese Mnr'): Its 0.0 Sdiia (5100): 193 Lead Mb'"], NO Zinc 05na'): 0.6 0.0 2.5 OAGANICAUpy 10.0 Formic And NO Acetic Acid: NO PropioNc Acid: Buy0c Acid: 5121 Valenc Acid: 1.0006 NO 8.] ND No Data No Data NO Data Amon/Cation patio: 1.02 ND = Not Determined Alummu. (Al"): NO Chromium (Crs'Y NO Cown(C."). ND m9/t mega Copper (C."): ND ND Moybdenum (Mos'): ND NO Nickel 01h; ND NO To (S."): No ND Titam.(T2'): NO ND Varradium w"): ND Znconium a",): ND Total Hardness: 559 N/A 1.02 ND = Not Determined Simpson Cagoo ?660t ays Sec. 10 7601 Sec. I / MPU MOOSE R Sec. 15 KUPARUK RIVER UNIT Sec. ADL025520 Sec. 27 11 Hile AW.M. LLC Map Date: 6/2B2018 \ Sec. 12 13 MILNE`. POINT UNIT \Sec. \26 ID: 10 119 ' `s Sec. 25 — Milne Point Unit Existing Milne Point Unit Moose Pad Aquifer Exemption Area Disposal Wells Exhibit 14 Sec 7 Sec.8 (628)1 1 18 U013NO10E Sec. Sec. 19 I8 Sec. 20 (633) Legend Subsurface Faults Subsurafce Contours- - Ugnu coall QOil and Gas Unit Boundary Pad Footprint EPAAquifer Exemption Area Sec. 29 QID: 10 119 Alaska State Plane Zone 4 NAD 1927 0 1,000 2,000 3,000 N Feet Simpson Lagoo 9 I?" Sec. 10 �s°I Sec.,11 s Sec. 12 Sec.7 See. B O (628) O �® 2s S6' MPU MOOSE PAD ADL355023 11S* ADL3551)2 7oS Saf, ADL025509 ADL025513 '\ ADL025514 I�a8 0 ADL025515 32-14 y I E e� Sec. 15ve Sec. 14 i Sec. 11\U9our vik Sec. 18 m ,\ ,\ '•� _. . _ 7� .�.�__.-�"`���. ..(630) Sec. 17 26, KUPARUK �\ ' �000�Y 7y s zj °P RIVER UNIT y a �s MILNE' , U013N009E rs� F POINT U013NO10E M a \2s2s�s�r UNIT u h N s R O O d as � 1 so 1 p p .". See. 22 r: l 1 M-811 o i ay Sec. 23 1 Sec. 24 Sec. 19 Sec. 20 Bz-i4A sf 1� (633) Nw Legend I M-01q subsurface Faults a° s SSS �a + Subsuraft �p Ugnu Coalloali AOL02MOM� � ADL025514 Oil and Gas Unit Boundary 3 D A - A 6 ?v2?S quifer ADL025519 Sh' � A Pad Footprint Exemption 7S �\ n n EPAAgWfer Exemption Area ESea 27 Sec. 26 ID: 10_119 `>s� Seo. 25 0 0 010: 10_119 Sec 29 ¢ ¢ o° Milne Point Unit Existing Milne Point Unit Alaska State Plane Zone 4 NAD 1927 L.k, u Moose Pad Aquifer Exemption Area o 1,000 z,000 3,000 Map Date: 8128/2018 Disposal Wells Exhibit 14 Feet 80,000 70,000 m 60,000 0 Cuv Q m 50,000 c Moose Pad Project Total Water Injection Disposal Rate (bpd) C 30,000 CL 0 T 20,000 10,000 0 01 01 O N N N M M C 111 111 w N N W T m O N N N M M Itt 111 M 10 N N N N N N N N M M M M M M M M M M O O O O O O O O O O O O O O O O O O O O O O O O O O O N N N N N N N N N N N N N N N N N N N N N N N N N N N \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ N N N N N N N N N N N N N N N N N N N N N H N N N N N N O\1 1!\1 N M 1\A N M 1\A N m 1!\1 N O\1 1\A N M Lm N O\1 11\1 N T 1\A '\-I m V\1 Moose Pad Project-- Cumulative Injected Disposal Volume 400,000,000 350,000,000 r 300,000,000 L m E 250,000,000 3 y 200,000,000 U V N j 150,000,000 R 3 � 100,000,000 U 50,000,000 U N N N N N N N N N N N N N N N M M M M M M M M M O O O O O O O O O O O O O O O O O O O O O O O O N N N N N N N N N N N N N N N N N N N N N N N N ti ti ti N ti ti Exhibit 17 Mpu Produced Water Chemical and Physical Properties 8au1uM 1s eAG>t BICARBONATE t 4422 MGL CALCIUM 65 MG2 CARBONATE 0 MGA. CHLORIDE IRON „5561 ?.�T. MGtLL M&L MAGNESIUM 17 MI. POTASSIUM 26 MG'L SQOIUM 7307 MILL STRONTIUM 3 MGR SULFATE �- _ 8 MG4 SPECIFlCRAVRY l060 j DEGREES F CONDUCTIVITY 17500 MICA04,010SICM . PH T.7 TOTAL DISSOLVED SOUDS.. 11314 _ I _ MGA. AFFIDAVIT OF DELIVERY STATE OF ALASKA ) SS. THIRD JUDICIAL DISTRICT Lee IC -,N , A , �\ being first duly sworn upon oath, deposes and says as follows: I am employed by Hilcorp Alaska, LLC and state that a true copy of the Application for an Area Disposal Injection Order on Milne Point Unit Moose Pad was sent, via U S Mail, to each of the following parties: Department of Natural Resources Office of the Commissioner 555 West 7th Avenue, Suite 1400 Anchorage, AK 99501 G�- Name lam' Title: VJOA 141EJ/ Er71�ropr- Date: THIS C RTIFIES that on the ( day of July, 2018, before me appeared et Z ` _, known to me to be the person named who executed this affidavit and acknowledged voluntarily signing it. SE472 OF Notary Public: R /(r MTV— /2 My Commission expires: 0 1-�Z0 L 2 Appendix B: Fracture Study Well B-50 Hilcorp Alaska, LLC DIO Application: MPU Moose Pad Appendix B 6.0 Performance Standards and Compliance 6.1 Formation Testing and Monitoring Initial formation testing will involve a pump -in formation breakdown test, followed by a pressure falloff test (PFO) when the well is completed. Subsequent PFOB will be obtained as needed to maintain an understanding of injection zone behavior. The regulations require defining physical, chemical, and radiological characteristics of the receiving formation. Toward this end, log data and nearby rock and fluid samples are the basis for the descriptions included in Section 3.0 and 4.0. Open hole and cased hole logs will be run on MPB-50, as detailed in Section 7.1. Therefore no additional core samples or fluid tests are proposed since this data is readily available. Accordingly, it is requested that the existing data, as well as the extensive historical data compiled from the Prudhoe Bay Unit, and other areas, be used to satisfy the formation testing requirements specified in 40 CFR 146.12 (e), and 40 CFR 146.14 (a). A waiver request from additional sampling and testing is included in Section 3.2.5. 6.2 Confining Zone Integrity and Waste Confinement The following discussion addresses the environmental and safety risks associated with deep well injection of production and domestic wastes. The purpose is to identify the risks and to quantify the likelihood that a problem could occur. 6.2.1 Risk Discussion and Analysis • Waste plume Placement and Migration : Exhibit 6-1 shows the area) extent of the waste plume after 15 years of injection. The boundary was calculated using average reservoir properties and thickness for the primary injection interval only, and the primary and secondary intervals combined (see type log Exhibit 3-2). Since there is not a horizontal pressure gradient in the Ugnu formation, and the injected fluids are the same density as the original reservoir fluid, the plume should not migrate once disposal operations cease. 6-1 • Fracturing of the Upper Confining Zone: A fracture modeling study was undertaken to understand and quantify the injectivity of the proposed injection interval, assess zone containment, and determine the area of influence resulting from long-term injection. The fracture modeling indicates that the confining zone will not be penetrated by hydraulic fracturing. An industry available three-dimensional fracturing simulator was used to predict fracture growth from the anticipated produced water/wastewater injection operation. Average rock and fluid properties for the primary injection interval were calculated from open hole wireline log data from the nearby MPB-02 well. Rock strength data was also determined from log calculations. Exhibit 6-2 discusses and details the result of fracture modeling using the most adverse reservoir properties, fluid properties, and maximum injection conditions. At the most extreme conditions, using the hard rock, single planer simulator, this would generate a fracture with the most extreme dimensions. The fracture developed with a height of 101 feet and a horizontal length of 336 feet. With the disposal well completed in the lower part of the injection zone, the top of the modeled fracture would be approximately 350 vertical feet below the base of the confining zone. While the hard rock simulator predicts a single planer fracture, it is known that in soft formations multiple fractures occur over time when the fracture gradient is exceeded. As pointed out in Exhibit 6-2 the predicted dimension should never be reached. This conclusion is further supported by the long term performance at other North Slope disposal sites, in which large produced water volumes have been placed in the soft rock, Ugnu formation, with minimal fracturing. The other North Slope disposal operations are summarized in the following Section 6.2.2. Based on the results of the conservative modeling study and historical operating experience, it is extremely unlikely that the confining zone could be penetrated from hydraulic fracturing. • Uncemented Wellbores : There are no existing wellbores within �/z mile of the injection well at the Ugnu depth. The only well in the area is MPB-24, an older high angle well that has been abandoned according to the State AOGCC requirements. Since the Ugnu formation oil/water contact lies more than a mile to the southwest, outside the bounding faults in that direction, no B - Pad development wells will be drilled in the disposal area. Therefore, no leakage points will exist through the confining zone clue to drilling operations. • Fault Leakage: SIV The disposal area is bounded on two sides by faulting as shown in Exhibit 3-5. A 200 psi increase in the injection interval is predicted by using a standard industry calculation. Drilling and production data from the Milne Point development area shows that similar faulting confines vertical pressure differences of 200 psi. Faulting should not be an issue with waste confinement. 6.2.2 Comparison With Similar Disposal Projects On the North Slope there are many disposal operations that primarily inject produced water and other minor liquids. These can be use as analogies to the well proposed for Milne Point. Their relevance is as follows: Cumulative Injection Disposal Well Count (Million Barrels) Formation 2 wells 175 +/- Ugnu 7 wells 150 +/- Ugnu 17 wells (Active and Inactive) 140 +/- Ugnu \✓ Total produced fluids injected in these wells, through May, 2004, is 1.75 Billion barrels. Aoe During the approximate 25 years of active disposal operations on the North Slope, only Prudhoe Bay well PWDW 1-2 had a confinement problem. This occurred when the well was initially drilled and injection started suddenly and at a high rate and pressure. The well was immediately shut-in, repaired, and 157 MMB has been successfully disposed of to date. 6,2.3 Summary/Conclusions • Confinement risk is primarily influenced by the lateral separation between the disposal point and offset wellbores and faults. Therefore, the risk of having to deal with a fluid confinement issue can be significantly reduced by selecting the proper disposal well location relative to other wells at the injection depth. This has been done. Confinement problems will not occur due to hydraulic fracturing of the confining zone based on fracture modeling and disposal well performance in other North Slope fields. 6-3 VA,Vl • Planned monitoring of injection operations will provide an indication of the level of risk that might develop as the disposal process proceeds. • Confinement risk, by necessity, involves subjective judgments and some uncertainty. However the factual data, fracture modeling, and relevant comparisons with similar projects underpin these judgments. It has been determined that with proper planning and monitoring, the environmental and safety risks are extremely low and can be effectively managed. This assessment substantiates the BPXA position that deep well injection is an environmentally sound method of permanent waste disposal. It is felt that the risk of environmental damage should be viewed as minimal and the likelihood remote. 6.3 Ambient Monitoring of Overlying Strata The existing Class if aquifer exemption for Milne Point Unit encompasses the disposal area and a Class I exemption has been requested from the EPA. There are no improperly sealed, completed, or abandoned wellbores within the AOR, and Section 3.0 data show that the geological formations are continuous and the faulting is not likely to transmit fluid above the confining zone. While fracturing will occur to a minor extent at the injection well, it will be confined to the lower injection zone. No penetration of the confining zones will occur. BPXA therefore proposes not to conduct ambient monitoring in the saline aquifers overlying the confining zone. Waiver Request: Based on the above facts, a waiver is requested from 40 CFR 146.13(b) requiring ambient monitoring of overlying strata or at any external location in the injection zone. This request is consistent with 40 CFR 144.16 which allows the Director to waive monitoring requirements when there are no under ground sources of drinking water to protect. 6-4 0 Exhibit 6-1: Waste water plume for 170mm barrels of fluid 4+ea - lrBe J��Q I42ap - t S SeBB is 180 acre plume 256 acre plume b Primary and secondary An Primary injection _..... ___. _.—t_. zone only injection zones MPIa-Bi Mro- XrC I � F �� JSP N, B -Zi -02 N 4 -w0-oz B-1 ___ _4224-__ ..–___ ._—_... ._ C-14 t4 PL -18 4 -1150 MPO- 4 N 4 a� 1 -te nrB-1 Ir -91 a a -16 -419 MP -14 r _as -4174 f. -2 .f., M P O -Z _ — C.I. = 100' V 19 LM a: Oilfield Services, Alaska Schlumberger Technology Corporation, by and through its Dowell Division 2525 Gambell SI.. Suite 900 Anchorage, AK 99503 Tel (907) 273.1700 August 10, 2004 Exhibit 6-2 Dennis Urban MPU Geophysicist Milne Point Unit, BP Alaska Re: Injection Modeling Results for MPU Ugnu Disposal Well Mr. Urban: Schlumberger As per your request, I have performed hydraulic fracture modeling for the well designated MPB Disposal #3. The purpose of the modeling was to determine if a fracture would stay contained in this well under constant injection at relatively high rates. Injection was modeled for both water and mud, with the mud injection rates and volumes being much lower than that of the water. The results of the modeling indicate that constant water injection of 24 barrels per minute for 1,000,000 barrels would achieve a maximum height of 101 feet. This is well contained in the Ugnu sequence. Also, a 10,000 barrel volume of mud injected at 2 barrels per minute would achieve a maximum fracture height of 73 feet. This is well contained in the Ugnu. The fracture modeling was performed using our FracCADE hydraulic fracture simulator. FracCADE has been used for both hydraulic fracture treatment design and injection modeling extensively in Alaska. The model can be run in a 20 (fixed fracture height) or P3D (fracture height calculated by computer) mode, based on the quality of formation property input data available. For this modeling, I was able to use the P3D mode of the simulator as we had good data available for the needed rock properties. The mechanical rock properties used for modeling are contained in Table 1 below. Table 1 — Formation Mechanical Properties Zone Name Frac Gradient silo(psi) Young's Modulus Poisson's Ratio TUZC 0.65 350,000 0.38 MA 0.65 350,000 0.38 M81 0.65 350,000 0.38 MB2 0.65 350,000 0.38 MC 0.65 350,000 0.38 NA 0.65 350,000 0.38 The formation mechanical properties determine in large measure how a fracture will initiate and propagate. In most formations, we need large stress contrasts to keep a fracture confined. This formation, however, is considered extremely soft with a Young's Modulus of well under 500,000 psi. In soft rocks, it is often easier for the frac to gain width rather than excessive height. The other key formation properties that govern hydraulic fracture propation are the transmissibility properties. As we pump fluid into a fracture, some of the fluid will cause the fracture dimensions to change (height, length, width) and some of the fluid will leakoff or be lost to the formation. The leakoff rate will be affected by the injected fluid properties as well as the formation transmissibility properties. The transmissibility properties used for this simulation are shown in Table 2 below. Table 2 — Formation Tra smissibilty Properties Zone Permeab Poros Pore Pressure Name ilily ity Gradient and %(Psi/ft) TUZC 100 31 1 0.43 O4rield Services. Alaska Schlumberger Technology Corporation, by and through its Dowell Division 2525 Gambell Sl., Suite 400 Anchorage, AK 99503 Tel (907) 273-1700 MA 10 25 0.43 MBI 2000 34 0.43 MB2 1070 31 0.43 MC 10 31 0.43 NA 10 22 0.43 Schlumberger The combination of soft rock, high permeability and low injected fluid viscosity will make it difficult to attain any significant fracture geometry. To force the model to initiate a fracture, I had to confine the perforation to a single 188' MD interval. From this, the model propagates a single (two wing) hydraulic fracture. 1 ran this scenario to the limits of the program, which is 1 million barrels of injection for water. The results obtained for increasing injection volumes are shown below in Table 3. The results for mud are in Table 4. Table 3 — Fracture Modeling Results for Water Injected Volume bbls Injection Rate b m Fracture Height (ft) 10000 24 75 35000 24 84 100000 24 84 500000 24 94 1000000 24 101 Table 4 — Fracture M deling Results for Mud Injected Injection Fracture Volume Rate Height bbls (bpm) I 10000 2 72 I believe these results to be very conservative in terms of confinement prediction. In my judgement, the fracture will stay more confined due to a couple of factors that are too random in nature for a fracture simulation model to accurately predict. We know from fracture stimulating hundreds of high angle to horizontal wells that you will nearly always initiate and propagate multiple fractures unless a very small interval (5 feel or less) is perforated. Given that we will have a gross injection zone of around 600 feel, there would be virtually no way to keep multiple fractures from forming. Anytime you have multiple fractures, the fracture dimensions for each propagating fracture are smaller than that of a single fracture. With this, we will end up with less fracture height than the model predicts. The other factor that will lend itself to better confinement than the model predicts is the extremely high leakoff. As fractures propagate in these soft, high permeabilty formations, increasing amounts of formation rock are exposed. As this new rock is exposed, the leak off rate will increase until you reach an equilibrium where the leakoff rate is equal to the pump rale. When we're pumping water, a non -wall building fluid, the fluid viscosity is the only fluid property to impede leakoff and it doesn't change during the course of injection. This will ultimately result in a situation where your injection will be a combination of fractured and radial injection, where the model simply predicts fracture growth. Obviously, there will be no further fracture growth when the fluid is leaking off radially as fast as we are injecting. What we will most likely end up with under injection, is multiple fractures at the wellbore that quickly blend into radial injection. if the worst case were to occur, a single fracture, we would still be adequately confined as predicted by the model. Let me know if you need anymore information on this subject. Regards A✓ Oilfield Services. Alaska j� Schlumberger Technology Corporation, by and through its Dowell Division S V hlumberger 2525 Gambell Sl., Suite 400 Anchorage, AK 99503 Tel (907) 273170 Brad Musgrove Technical Engineer- Schlumberger VAW r Schlumberger a FracCADE Injection Modeling with Water - 1,000,000 bbls continuous injection Operator : BP Well : MPB Disposal #3 Field : Milne Point Formation : Well Location: County North Slope State Alaska Country United States "11111111111" Prepared for Dennis Urban Service Point Proposal No. Business Phone Date Prepared 07-21-2004 FAX No. Prepared by Brad Musgrove Phone (907)564-5097 E -Mail Address musgrove@slb.com Mark of SehWmOelger Prudhoe Bay, Alaska (907)659-2434 D edaimm Notice They mlpmafian is presented in good tenth. but he warranty, is gven by and Dowell assumes no liability Icy aMAce made concerning results to be obla.nell from the use or any product w service The results given are estimates based on Caletialions produced by a compeer model tncN6ng venous as5uay4ana en Ins well, rare affect hi ahem. The reaolla depand M input data pounded by the OperNp find estimates as b unlvpwn data and can be no mo a accutato than the model, the aeaumphoM and such ,nPet dale. The information presented Is DbMelys best estimate of the actual reaulls that may be achleved and should be Used I. f.Nnpal,ien Wrpat raR,et men absClule Wlues. The quality d i,., data, end baifca nbsW5, may W .proved 1NWgli Ilte use of Csn en teals and procedures winch Dewefi can asset In selecting The OPe ts. has supenor kmere edge at the wstt. the neservoir, The hard and conditions aeectlrg them. If the Creseur es awa,a of any candi6ens .Hereby is neighboring wait or wells might be affected ty the uaetment prepoaad herein it is the OpNalor s raepprnabNity to molly the center Or o cries d the was a wells accprdingly. Prices quoted are estimates only and are good for 30 days horn In. arta of issue Actual charges may vary deperwing upon time. Equipment and material '.. ultimately required to Wer. these Mo.$ I, Of Dowell or others If real 10 be,Merreed All The following are definitions of terms used in this proposal. FRACTURE HALF-LENGTH refers to the length of one fracture wing from the wellbore to the fracture tip. FLUID LENGTH refers to the fracture half-length occupied by fluid and may include length without proppant which does not contribute to production. EFFECTIVE or APPARENT LENGTH refers to the fracture half-length through which formation fluid can be produced and which may be expected to contribute to well productivity improvement. 'oa,V W, Client Well BP MPS Disposal #3 Schluu�hergcr Formation: District Prudhoe Bay, Alaska Country United States Lie Loadcase : Water Section 1: Definitions The following are definitions of terms used in this proposal. FRACTURE HALF-LENGTH refers to the length of one fracture wing from the wellbore to the fracture tip. FLUID LENGTH refers to the fracture half-length occupied by fluid and may include length without proppant which does not contribute to production. EFFECTIVE or APPARENT LENGTH refers to the fracture half-length through which formation fluid can be produced and which may be expected to contribute to well productivity improvement. 'oa,V W, Bottom Hole Temperature 100 degF Deviated Hole YES Treat Down TUBING Flush Volume to 9019.5 ft 365.4 bbi Tubing Data Client : BP Weight Ib/ft ID in Well MPB Disposal }!3 Schinh qu 26.0 Formation: 8500.0 MD District Prudhoe Bay, Alaska MD TVD Country United Slates TUZC 7696.6 Loadcase : Water ft ft Section 2: Wellbore Configuration shoUfl Bottom Hole Temperature 100 degF Deviated Hole YES Treat Down TUBING Flush Volume to 9019.5 ft 365.4 bbi Tubing Data OD in Weight Ib/ft ID in Depth ft 7.000 26.0 6.276 8500.0 Casing Data OD n Weight Ib/ft ID in Depth ft 7.000 26.0 6.276 10874.0 Perforation Data Formation Transmissibility Pro ernes Top Top Bottom Bottom Shot Number Diameter MD TVD MD TVD Density TUZC 7696.6 ft ft ft ft shoUfl 5000 in 9019.5 1 4515.0 9208.4 4570.0 4.00 756 0.35 %W Section 3: Zone Data E2 Formation Transmissibility Pro ernes Formation Mechanical Properties Zone Name Zone Name Top MD (ft) Zone Height ft Frac Grad. (psi/ft)(psi)(psi) Insitu Stress Young's Modulus Poisson' s Ratio Toughness (psi.in0.5) TUZC 7696.6 375.0 0.650 2806 3.500E+05 0.38 5000 MA 8985.1 10.0 0.650 2931 3.500E+05 0.38 5000 MB1 9019.5 65.0 0.650 2956 3.500E+05 0.38 5000 M62 9242.8 130.0 0.650 3019 3.500E+05 0.38 5000 MC 9689.5 30.0 0.650 3071 3.500E+05 0.38 5000 NA 9792.5 300.0 0.650 3178 3.500E+OS 0.38 5000 Formation Transmissibility Pro ernes Zone Name Net Height R Perm (md) Porosity N Res. Pressure sl Gas Sat. % Oil Sat. % Water Sat. TUZC 0.0 100 31.0 1876 10.0 0.0 90.0 MA 19792.5 0.0 10 25.0 1960 10.0 0.0 90.0 MB1 0.0 2000 34.0 2057 10.0 0.0 90.0 MB2 0.0 1070 31.0 2164 10.0 0.0 90.0 MC 0-0 10 31.0 2211 10.0 0.0 90.0 NA 0.0 10 2-2-0---r 2289 1 10.0 1 0.0 90.0 zn P, Section 4: Injection Pump Schedule Job Description Client BP Pump Fluid Name well MPS Disposal #3 Sch itopger Name Formation Cum. Fluid Conc. Type and Mesh District Prudhoe Bay, Alaska (bbl/min) Prop Country United States (PPA) Time Loadcase : Water bbl Volume Volume Injection 24.0 zn P, Section 4: Injection Pump Schedule Job Description Stage Stage Pump Fluid Name Stage Gel Prop. Prop. Name Rate Cum. Fluid Conc. Type and Mesh Conc. Slurry (bbl/min) Prop Volume (lb/mgal) (PPA) Time Volume bbl Volume Volume Injection 24.0 Produced Wat ' 10000D0 1 0.0 0.0 Flush 24.0 Produced Wat 365 0.0 0.0 Fluid Totals 1000365 bbl of Produced Wat Job Execution Stage Stage Cum. Fluid Stage Cum. Stage Cum. Avg. Stage Cum. Name Fluid Volume Slurry Slurry Prop Prop. Surface Time Time Volume (gal) Volume Volume (lb) (lb) Pressure (min) (min) bbl bbl bbl(psi) Injection 1000000 41999992 1000000. 1000000. 0 0 1265 41666 41666.7 1 1 7 Flush 365 42015340 365.4 1000365. 0 0 1288 15.2 41681.9 4 Section 5: Fracture Simulation Results The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Initial Fracture Top TVD ..................... 4515.0 ft Initial Fracture Bottom TVD 4580.0 ft ............... Hyd Fracture Half -Length .................. 336.6 ft EOJ Hyd Height at Well,,,,,,,,,,, ,,,,,,,,, 101.5 ft Net Pressure„....................................122 psi Max Surface Pressure .....................,..1288 psi Section 6: Treatment Fluid Data Client : BP SM111Mergcr Well : MPS Oisposat#$ Formation: District Prudhoe Bay, Alaska Country United Stales Loadcase : Water LFluid data is given at 2000 and Fluid Name Produced Water Friction Rate Low bbl/min 16.0 Pressure Low si/1000ft 10.0 Rate Pivot bbl/min 60.0 Pressure Pivot si/1000f1 100.0 Rate High bbl/min 100.0 Pressure High psi/1000ft 260.0 Fluid Loss Cw fl/min0.5 1.0E+0 S urt aUt00ft2 9.0 C, ft/min0.5 9.5E-2 Rheology Temperature de F 100 Time hr 0.0 Behavior Index N' 1.00 Consist. Index K' Ibf.s^n/ft2 1.67E-5 Viscosity Shear Rate (cP) 0.800 Shear Rate 1/s 170 Section 7: Graphics Client Well BP MPB Disposal #3 SchlumhergBr Formation: District Prudhoe Bay, Alaska Country United States Loaticase : Water rv.m.p.rea.�+ 0 �a ..mw w.r-u.am M Client 8P Well MPS Disposal 43 Formation: District Prudhoe Bay, Alaska Country United States Loadcase : Water Fwure Cgen�q W yry SAIMrger .uo uro .no .s�o r.ersw .sw .sw .ssc ov un b Im oa s qW Client BP Well MPB Disposal N3 Formation District Prudhoe Bay, Alaska Country United States Loadcase : Water nnegw �•. MnM1W Mxn — YRe Mew � r>NN6� '^ d Schlumpler x00000 600000 100000 Inleeu6 V.I.. IW O G 1066pp6 12000JD 7 NW I N IUV K il0 � 1M N� Im x00000 600000 100000 Inleeu6 V.I.. IW O G 1066pp6 12000JD Client Well BP MPB Disposal #3 Schloherger Fonnadon: District Prudhoe Bay, Alaska Country United States kw loadcase : Water FraCCADE` IT 44� �E 36M s}oo a.s a.m 4..5 6o.ls o. oas 1 o doo ,W SY11E'131 P4 Wg111Y WCN.xI �n F.X'L. h 1. YWRAI�W"�w 'AYM NIumE� LM Appendix C: Fracture Study Well B-34 Hilcorp Alaska, LLC DIO Application: MPU Moose Pad Appendix C MPB-34 Fracture Model 12/5/16 Methods A fracture modeling study was performed on the Ugnu sands to understand the current state of the injection and slurry disposal. MPU B-24 and MPU B-50 data was utilized to generate the Ugnu model which will also be applicable to the upcoming MPU B-34 disposal well. To validate the model a pressure fall off was performed but due to the variance in the data only the reservoir pressure and the Loss Coefficient could be quantified. Young's Modulus data is from previously analyzed core data. A slurry injection was simulated with a viscous fluid composed of linear gel at a viscosity of 34 cP, which is high enough to encompass 85% of actual slurry injections, and solids composed of 40/70 sand. The injection was pumped at the highest rate attainable with the surface G&I injection pumps of 7.6 BPM and this was done down 4.5" L-80 tubing as is the current completion in the MPU B-24. Fracturing of the Disposal zone A rock mechanics model of the disposal zone was created based on offset well open hole logs and is shown below in Table 1. Depth (h) Stress (psi) Gradient Modulus Poisson's Ratio Toughness loss Coef, :r Top , Bottom Thickness . Top : Bottom ":' (psi/ft) (MMpsi) : (psrsgrt(in)) (fgsgramin)) : (gal/100ft°2) ',. UGNUDISPOSALZONE 4639 4680 41.4 3490 3490 0.152 0.35 0.33 1000.0 0.00600 TABLE 1—ROCK MECHANICS LOG OF DISPOSALZONE The Loss Coefficient, also known as the leak off coefficient, was matched to a pressure fall off performed on 10/14/2016 in the MPU B-24 well. The reservoir pressure of the disposal zone was measured at 2750 PSI giving a reservoir pressure gradient of 0.6 PSI/FT which is higher than the initial reservoir pressure due to two factors: 1) the MPU B-50 well was online injecting at more than 25,000 BWPD at the time and 2) years of water disposal into the Ugnu from both MPU B-50 and, more recently, MPU B-24. The rock mechanics model above was used to model fracture length and height growth. A batch slurry injection as described in the Methods section above was modelled and this is shown below in Figure 1. W a) t 3000 3400 3800 -0.2 0.0 0.2 20 40 60 80 100 120 Fracture Penetration (ft) FIGURE 1—FRACTURE GEOMETRY AFTER ATYPICAL BATCH SLURRY INJECTION As shown above, due to the low Young's modulus of 0.35 MMPSI of the disposal zone the fracture attains a max width of 0.56 inches which makes the Ugnu an ideal zone for disposal. Fracture height growth is less than 100' because of the high stress contrast found in the confining zones above and below the zone of injection. Even if the stress contrasts are less than expected, the leak off of the Ugnu will dissipate energy as the more height is opened thus limiting the fracture height growth. Fracturing of the Confining zones A rock mechanics model of the confining zones was created based on offset well open hole logs and is shown below in Table 2. The differential stresses creating the confined fracture type geometry of the slurry injection is caused by a difference in Poisson's Ratio of the confining layers and the disposal zone. This allows for the fracture that are longer than they are tall and will keep the fracture contained within the confining zones. Depth (ft) Stress (psi) Gradient Modulus Poisson's Ratio Toughness Loss Coef. j z Top � Bottom )Thickness . Top • Bottom [-j (psi/ft) "](MMpsi) . (psi•sgrt(in)) I(ft/sgrt(min)) :',(gal/1001`02) UPPER CONFINING ZONE 1 46021 46231 A IST 3477 3477 0.755 0.41 0.34 10001 0.00500 LOWER CONFINING ZONE 1 46801 47261 46.0 3753 37531 0.8021 0.45 0.371 10001 0.00500 TABLE 2— ROCK MECHANICS LOG OF UPPER AND LOWER CONFINING ZONES MILNE POINT UNIT G&I FRACTURE MODELLING AND ANALYSIS Jeremy Mardambek 12/6/2016 List of Figures, Table, and Equations FIGURE 1—LIKELY CROSS SECTION OF UGNU DEFORMATION IN DISPOSAL ZONE WITH WELL IN BLUE FIGURE 2 — Layers As Defined by the Rock Mechanics Log FIGURE 3 — HORNER PLOT OF RESERVOIR PRESSURE FROM THE PFO ON 10/14/2016 FIGURE 4 — PKN GEOMETETRY AND EQUATIONS FIGURE 5— LIKELY GEOMETERY OF EXISITNG G&I SLURRY INJECTIONS BASED ON ROCK MECHANICS FIGURE 6 — MATCH OF LEAK OFF COEFFICIENT FROM PFO FIGURE 7—FRICTION PRESSURE PER 100' MD IN 4.5" TUBING USING LINEAR GEL FIGURE 8 — MARSH FUNNEL VISCOSITY OF SLURRY FROM 2/2016 thru 3/2016 FIGURE 9—HISTOGRAM OF VISCOSITY FROM DAILY INJECTION SHEETS TABLE 1—ROCK MECHANICS OF CONFINING ZONES TABLE 2—TABLE OF EROSION IN 4.5" L-80 TUBING TABLE 3—RESULTS OF STOKES LAW FOR SOLIDS TRANSPORT Equation = PR/(1-PR)*(OB-Pr)+Pr Equation 2 ......... .................. (0.5*((DTSHEAR/DTCOMPRESS)**2)-1)/(((DTSHEAR/DTCOMPRESS)**2)-1) Equation Vel erosion = C/pA0.5 Equation 4...................................................Vel settling = 6.64*E5*DiameterA2*(SGsolids—SGfluids)/visc EXECUTIVE SUMMARY The purpose of this document is to anchor surface operations to what is possible and what is prudent based on subsurface analysis at the G&I facility on B pad at Milne Point. Frac modelling was performed using all available data and based on the modelling, surface operations are setup correctly for optimizing the subsurface performance. Discussions include the rock mechanics and the uncertainty of the measurements, physical limitations of the well, current procedures for slurry injection, deviations from these procedures, and recommendations for future operations. The goal of the Milne Point G&I operation is to inject tens of millions of barrels of slurry and other Class II waste produced by drilling and production operations, without incident, into the Ugnu formation. The current record for G&I on the North Slope is GNI-03 at Prudhoe Bay which by the author's estimate from public data has injected more than 36 MMbbls of slurry containing more than 2.2 MM tons of solids. In all, the five Prudhoe GNI wells (GNI-01, GNI-02, GNI-02A, GNI-03, & GNI-04) have injected more than 100 MMbbls of slurry and likely more than 6.0 MM tones of solids. Using the Prudhoe Bay wells as an analogue, the future of the Milne Point G&I program has potential to be at least the same and possibly better. This write up is broken out into seven sections as enumerated below Section I — Qualitative Descriptions of the Disposal and Containment Zones Section II — Rock Mechanics of the Disposal and Containment Zones Section III —The Well and Physical Limitations Section IV—Monitoring Minimums and Analysis From the Existing Data Section V —Current Procedure for Batch Injection and Opportunities to Optimize Section VI — Protocols for Deviations from the Standard Procedures for Batch Injection and Possible Explanations Section VII — Regulatory Requirements and Reporting The goal of the Milne Point G&I operation is to inject tens of millions of barrels of slurry and other Class II waste produced by drilling and production operations, without incident, into the Ugnu formation. The current record for G&I on the North Slope is GNI-03 at Prudhoe Bay which by the author's estimate from public data has injected more than 36 MMbbls of slurry containing more than 2.2 MM tons of solids. In all, the five Prudhoe GNI wells (GNI-01, GNI-02, GNI-02A, GNI-03, & GNI-04) have injected more than 100 MMbbls of slurry and likely more than 6.0 MM tones of solids. Using the Prudhoe Bay wells as an analogue, the future of the Milne Point G&I program has potential to be at least the same and possibly better. SECTION I — Qualitative Descriptions of the Disposal and Containment Zones From a G&I prospective the Ugnu formation at Milne Point is deep enough and should be considered a high porosity, high permeability unconsolidated sand which is capable of large volumes of slurry injection over long periods of time. The main advantages and one major disadvantage of the Ugnu are described below. Advantages of Disposal Zone 1. Due to the high porosity, the sands itself has superior storage capacity. Almost all of the solids from the slurry will be contained in this porosity and not in the actual fracture created by the batch injections. Along with an already high starting porosity the unconsolidated nature of the Ugnu will allow it to undergo what is called shear dilation and deformation creating even more storage in the matrix thus forming a large zone of deformation around the wellbore. This is shown below in Figure 1. FIGURE 1— LIKELY CROSS SECTION OF UGNU DEFORMATION IN DISPOSAL ZONE WITH WELL IN BLUE 2. The high permeability comes with a high injectivity index (BWPD/psi) above the reservoir pressure and increases dramatically as the rock fractures. After a batch injection is complete the high permeability will allow the near wellbore stress to leak off faster and the well will approach original pre-injection conditions quickly assuming all the solids were flushed away from the wellbore with proper flush volumes. 3. The width of a fracture is inversely proportional to the Young's Modulus which for this soft unconsolidated rock is a small value thus a larger width takes up volume which is not needed to propagate a fracture vertically up through possible containment zones. A larger frac width also has a much lower chance of near well bore screen out as particles will have no problem entering the fracture. Disadvantages of Disposal Zone 1. The only disadvantage of the Ugnu is due to its unconsolidated nature. If during an injection, especially a slurry injection, the near wellbore stresses do not bleed off into the formation and the surface pressure falls off, the formation will back flow into the well with unknown results. The highest potential for this occurring is when the surface equipment fails and an abrupt SI occurs. This was the likely failure mechanism for GNI-02 at PBU and even after multiple coil cleanouts the well had to be sidetracked eventually. This can be mitigated by tapering shut-ins and using water or higher viscosity water to flush the near well bore area after a slurry injection. Section II — Rock Mechanics of the Disposal and Containment Zones The disposal zone and containment zones are composed of rocks with different mechanical properties and this contrast in both stress and modulus drives the containment of the slurry injections. Without this contrast the formation would be unable to contain the fractures created during pumping operations. Rock Mechanics of the Disposal Zone As stated earlier in Advantages of the Disposal Zone section above, the disposal zone of the Ugnu is composed of soft unconsolidated rock. The important values of rock mechanics of the disposal zone are shown below in Figure 2 followed by a discussion. PCI E Me Poisson's ratio (psi) (MMpsi) FIGURE 2 — Layers As Defined by the Rock Mechanics Log Closure Pressure — Pcl Closure pressure (Pcl) is simply the minimum horizontal stress of the formation. Equation 1 below shows the formula for calculating Pcl with Poisson's Ratio (PR), overburden stress (OB), and reservoir pressure Pr. Poisson's ratio is calculated foot by foot from the ratio of shear and compressional sonic waves from the dipole sonic log as shown below in Equation 2. Equation = PR/(1-PR)*(OB-Pr)+Pr Equation 2 ............... (0.5*((DTSHEAR/DTCOMPRESS)**2)-1)/(((DTSHEAR/DTCOMPRESS) **2)-1) Using the above equation, the Pcl was calculated to be 3490 PSI which calculates to a 0.75 PSI/FT stress gradient with the OB assumed to be 1.05 PSI/FT. This is directly from the open hole logs and represents the stress at the time the well was drilled in early 1996. A pressure fall off (PFO) was performed on the B-24 well on 10/14/2016 and the reservoir pressure was found to be 2750 PSI giving a reservoir pressure gradient of 0.6 PSI/FT. This is much higher than expected and is likely due to the fact that the MPB-50 well injects more than 30,000 BWPD less than 3000' away. I believe the reservoir pressure measured by the PFO is influenced by the offset injection thus increasing the current Pcl. Also because the effect is felt from the offset injection the PFO data is largely useless outside of measuring reservoir pressure and a guess at Leak Off Coefficient. See Figure 3 below for the Horner plot showing the reservoir pressure. Another reason this seems valid is according the G&I facility operators the well has as SITP over 800 PSI even after a long shut in. ImwV/m FIGURE 3 — HORNER PLOT OF RESERVOIR PRESSURE FROM THE PFO ON 10/14/2016 Another data point that validates this analysis is the well head injection pressure of the MPU B-50 well of approximately 1100 PSI. The only way left to model the frac is to simply believe the stress from the open hole logs and Young's Modulus as measured in core data. Due to the uncertainty surrounding such a guess the author cannot recommend adjusting the current G&I operations if they are working well but it is possible to make general statements about containment simply using the rock mechanics as calculated by the open hole logs. The stress contrast in the overlying and underlying strata provide the stress differentials needed to create the Perkins -Kern (PKN) type frac geometry. This geometry is shown below in FIGURE 4. Xf = uz H Elliptical Cross Section FIGURE 4 — PKN GEOMETETRY AND EQUATIONS Characteristic Dimension Height (d) 114 W lQEli L) E' Q f, L 1/4 Pnet H E' Even if the stress contrasts are not as significant as expected and the height is larger than expected, because the leak off is so high in the disposal zone and the confining zones the frac should dissipate energy quickly and under no normal operating circumstances should grow above the Ugnu A sand as defined in the MPU B-50. Figure 5 below shows the likely geometry of a typical G&I fracture based current understanding. 3000 Fracture Penetration (ft) FIGURE 5—LIKELYGEOMETERYOF EXISITNG G&I SLURRY INJECTIONS BASED ON ROCK MECHANICS Fracture Width Frac width is a function of Young's Modulus as shown by the equations on Figure 4 above. A lack of fracture width is also a source of well bore screen outs but because the Ugnu has such a low Young's Modulus, for a given net pressure build the rock will increase in fracture width until it become easier to propagate the frac in the direction of maximum horizontal stress. The B-24 modelling shows the fracture widths is likely 0.25". Leak Off Coefficient During a PFO the rate, change in height, and length go to zero thus making the analysis of the pressure fall off in net pressure much more straight forward to calculate than the net pressure while pumping. The match of the Leak Off Coefficient with the PFO is shown below in Figure 6. Even though the starting point does not tie, the magnitude of the leak off is the same as the PFO thus giving a valid guess. This analysis should be taken as a guess within an order of magnitude as it is highly uncertain due to the inability to match the Pcl from the PFO performed on 10/14/2016. The Leak Off Coefficient was found to be 0.006 ft/minuteA0.5 in the sands and 0.005 ft/minute A0.5 in the shaley sections. This is the leak off with a slurry injection and will change with other fluids or solids injection from the one performed on 10/14/2016. The Leak Off Coefficient is a combination of Cl, Cii, and Ciii which are defined as slurry filtrate viscosity, reservoir fluid compressibility, and wall building effects respectively. These effects combine to give the total Leak Off Coefficient. `t N CD CD r CD L C N Z, Measured Data 100 Simulated Data Frac 1 FIGURE 6 — MATCH OF LEAK OFF COEFFICIENT FROM PFO Rock Mechanics of the Containment Zones The containment zones above and below the Ugnu are alternating shales and sands with higher shale content, and due to the Poisson's ratio, under higher stress. Below is a summary of the rock mechanics of the upper and lower containment zones. Depth (it) Stress (psi) Gradient Modulus POISSGn'sflad0 Toughness Loss Coef. .r, Top Bottom I;!Thickness -'Sop cl Bottom (osi/k) •iMMosil Flosl0sortlinll :fft/smH TABLE 1— ROCK MECHANICS OF CONFINING ZONES Section III —The Well and Physical Limitations The MPU B-24 was not drilled as a G&I disposal well and was converted to be so. Because of this the rate is limited by its tubing size. Friction in 4.5" L-80 A database of friction correlations was used to estimate the friction pressure of a typical slurry injection. A value of 1PSI/100' of MD was used for the frac modelling. O O N O 0 O N J a o LO 0 r 0 N O Rate 19941=0117 FIGURE 7—FRICTION PRESSURE PER 100' MD IN 4.5" TUBING USING LINEAR GEL Risks of Erosion in 4.5" L-80 Tubing Calculated below in Equation 3 is the erosional velocity of the 4.5" L-80 tubing and Table X is the result of the equation for different density fluids. Equation erosion = C/p^0.5 Because slurry injection contains solids, the actual erosional velocities will be lower than those stated below in Table 2 but impossible to determine exactly. Periodic caliper runs are a good idea in order to quantify the erosional rates of the 4.5" tubing. In 4.5- 680 0=100 Density (lbm/gal)'Density (Ibm/ftA3) Etrosional Velocity (ft/sec) Flow Area (ftA2) ftA3/sec BPM BFFD 8.3 62.3 12.71 0.085 1.08 11.6 16,656 8.5 63.6 12.51 0.0851 1.07111.51 16,489 9 67.3 12.21 0.0851 1.04111.11 16,024 9.5 71.1 2.651 0.0851 1.01 10.8 15,597 10 -11.91 74.8 11.61 0.0851 0.99 10.6 15,202 TABLE 2 -TABLE OF EROSION IN 4.5" L-80TUBING Solids Fall Out Risks Stokes' Law is related the diameter of the solids in the slurry to settling velocity in tubing for a given viscosity and density of solids and fluids. This is shown below in Equation 4. The G&I ball mills have a Number 40 mesh filter on the output thus limiting the size of the solids particles to 0.42mm. See Table 3 below for a calculation of the minimum solids transport velocity using stokes law for different density fluids in the 4.5" L-80 tubing. Solids were assumed to be a worse case SG of sand at 2.65 g/cc. This table shows fresh water has enough density to move the solid particles at flow rates as low as 0.86 BPM so this should not be an issue if the post slurry injection flushes are done at above this rate. Equation 4...................................................Vel settling = 6.64*E5*DiameterA2*(SGsolids - SGfluids)/visc FF0M5WTPANT r In4.5" L80 Mesh areengm Averaaegameter(ft) 9tecific Gravity Pr000ant 3�dficGrarity Ruid Dencwntvniruh\A, anN q*t1! nVr1nAfv1ft1m %MA am Number 40 1 0.00121 2.65 11 8.3 20 0.0807 0.86 1,242 Number40 0.00121 2.65 1.02 8.5 20 0.0797 0.85 1,227 Nunber40 0.00121 2.651 1.081 9 201 0.0768 0.82 1,182 Number 40 1 0.001211 2.651 1.141 951 201 0.0739 0.79 1,136 Number 40 1 0.001211 2MI 1.201 101 201 0.0709 0.76 1,091 TABLE 3 - RESULTS OF STOKES LAW FOR SOLIDS TRANSPORT Section IV - Monitoring Minimums and Analysis From the Existing Data The existing monitoring on the MPU B-24 is enough to perform basic analysis of normal operations and anomalies. Currently the Milne point SCADA data record, in real time, one second pressure and rate data. This is enough data to monitor the minimums as enumerated in the AOGCC law as detailed in Section VII of this document. This minimum data includes well head injection pressure (WHIP), rate, IA pressure, and OA pressure. Beyond the SCADA data Daily Injection Sheets are filled out using 30 -minute data on slurry injections listing the viscosity, rate, WHIP, and the density of the slurry. These sheets are useful and this practice should be continued to understand if there is a shift in performance of the well or surface equipment. Ideally this analysis is repeated using pressure fall offs performed using SCADA data when Milne Point is having a major turnaround so that all injectors into the Ugnu can be shut in. A PFO performed during this event will give a better estimate of static reservoir pressure and Pcl. Section V -Current Procedure for Batch Injection and Opportunities to Optimize The current batch slurry injection procedure is enumerated in this section. This procedure has been working to date and although opportunities exist to optimize it in the form of using larger mesh size solids or lower viscosity fluids the existing surface operations practices are matched well to the subsurface performance. Because the frac modelling had inconsistencies in the data the author recommends keeping these practices the same. ENUMERATION OF PROCEDURE FORG&I SLURRYTANK INJECTION POST GRIND 1. Verify that slurry to be injected has a minimum 40 vis (secs in Marsh Funnel), and is not more than 10% solids by volume. 2. Verify utility water tank has enough volume for flush 250bbl or production water from B-50 to B-24 is active and ready. 3. One operator will be required to monitor injection pump throughout entire injection operation. 4. Notify control room and B -pad operator of your intent to swap from production to slurry (radio CH 1). 5. After notifying the control room and 8 -pad operator and receiving acknowledgment loosen set screw on choke and slowly close choke. 6. Close production water valve on tree. 7. Turn wall switch to off to bypass SSV for slurry injection. 8. Open slurry injection valve and notify G&I operator slurry line is open. 9. Open all valves between injection tank 1 and desired inj pump. 10. Injection pump 1 valve sequence CPSV1, CPDV1, CPPV3A, CPPDV7A and IPSV1. 11. Injection pump 2 valve sequence CPSV1, CPDV1, CPPV3A, CPPDV7A, IPS81, IPSB2 and IPSV1. 12. Open purge fan supply air valve. 13. Open Inji pump crankcase air supply. 14. Turn on appropriate purge fan 15. Turn on charge pump 1 or 2. 16. Slowly open suction relief line at injection pump IPD2 (inj pumpl) IPD4 (inj pump 2). 17. Open inj pump discharge valves (IPDVB1, IPDVIA inj pump 1) (IPDV2A, IPDV2B inj pump 2). 18. Reset SSV on HMI in control room. 19. Turn injection pump control status on at inj pump control panel. 20. Turn VFD on for desirable pump. Push REF enter desired Hz (40Hz) push start button. 21. Turn off injection pump crankcase air. 22. when slurry injection is complete go to flush Clear lines to well with 15bbls of utility water. 23. Call control room and B_pad operator to let them know you are going back on production water wait for approval from control room. 24. Shut down injection pump and charge pump close (IPDVBI, IPDVIA inj pumpl or IPDV2A, IPDV2B inj pump 2. 25. Turn off purge fan supply air. 26. Open discharge pressure relief valve relieve pressure and close valve. 27. Close slurry valve on B-24 tree. 28. Turn wall switch to ON. 29. Follow B-50 to B-24 production water injection procedure in B-24 well house. VISCOSITY FROM DAILY INJECTION SHEETS Each cuttings batch is different but as long as an appropriate viscosity is attained each time there should not be an issue. Viscosity is controlled by adding Bentonite to the slurry tank and performing multiple marsh funnel viscosities. The majority of G&I injections occur above 10 cP and below 30 cP. This viscosity is enough to push the slurry through the surface facilities and enough to push it into the formation and away from the wellbore. The frac modelling was done with the higher end of viscosities at 34 cP but within the current operating parameters. Because the inputs to the slurry are so variable it is difficult to apply general procedures to ensure a consistent viscosity is attained. Some drill cuttings will have a higher initial viscosity due to shales entrained in the cuttings and residual bentonite which is used as a gelling agent on the drill rigs. Other slurry will contain tank bottoms and sandy drill cuttings which will have a lower initial viscosity and higher solid settling. As long as the viscosity of each slurry injection is measured with a representative sample as enumerated in the above procedure there should not be any issues with solid settling in the tubing or near wellbore screen outs. See Figure 8 below for the viscosity data from three months of daily injection sheets. MARSH FUNNEL VISCOSITY 120 100 a 80 N 60 U • m 40 20 ' 11 -Jan 31 -Jan 20 -Feb 11 -Mar 31 -Mar FIGURE 8 — MARSH FUNNEL VISCOSITY OF SLURRY FROM 2/2016 thru 3/2016 20 -Apr 10 -May The two anomalies on FIGURE 8 in late February and mid-March are due to injection of high viscosity gel in order to completely clean out the tanks that store the G&I slurry which is done as periodic maintenance. 350 300 ro a 250 v l s 200 OC M 150 4 C � 100 U Q 5e Histogram of Viscosity 10,101 (10,201 (20,301 (30,401 (40,501 (50,601 (60,701 (70,801 (80,901 (90, 1001(10D, 110] Viscosity Sin (cP) FIGURE 9— HISTOGRAM OF VISCOSITY FROM DAILY INJECTION SHEETS Section VI — Protocols for Deviations from the Standard Procedures for Batch Injection and Possible Explanations The largest risk to the G&I process is the building up of near well bore stresses and the subsequent flow back of the unconsolidated Ugnu sands into the wellbore. To avoid this pressure must not be dropped quickly from the surface for any reason. If problems of surface rate or pressure arise, keeping the pressure bottled up in the well is the safest options until intervention well work can be performed. Catastrophic Loss of Surface Injection Pressure The surface injection pumps and flow path from the pumps to the well would be the first items ensure operations are normal. Assuming the surface equipment is in working order a catastrophic loss of surface injection pressure will be due to a large volume being introduced quickly into the process. The IA is the most likely of source for an instant creation of volume thus dropping the pressure catastrophically. The IA should be monitored during slurry injections and the gas cap should be replenished or bled off depending on the temperature of the slurry injection. Another source of catastrophic loss of surface injection pressure is height growth in the formation beyond what is normally attained. Much like opening up the IA and introducing a large volume into the process, height growth is a similar phenomenon but is harder to detect. If this occurs, it could keep occurring due to the flow path created by previous injections but chances of this are low because the formation has a high Leak Off Coefficient and large stress contrasts. Large Increase of Surface Injection Pressure Large increases in surface pressure can be due to multiple factors but likely are due to solids building in the tubing or the casing stopping up the slurry injections. To mitigate this risk viscosity must be closely monitored and solids kept below the 10% by volume cut off. This has been effective based on current performance and should be continued. If a screen out event occurs the best option is to keep the pressure bottled up and not bleed the well off quickly which can pull the unconsolidated formation back into the wellbore. A tied in slick line tag should be the first diagnostic tool and more intensive interventions should be taken with the main risk of not letting the formation flow into the wellbore kept as paramount to the intervention of the operations. Section VII — Regulatory Requirements and Reporting The AOGCC has laid out the regulations governing this well in section 20 AAC 25.252 of the Alaska Oil and Gas Laws and Regulations. This regulation is based on the Class II definition of a disposal well as spelled out in the EPA regulation 40 C.F.R. 144.6(b). Most of this regulation is fulfilled with the permitting of a new well. Sections D, E, possibly F, & possibly G will apply to the daily operations of this well. They are explained below. Section D — Mechanical integrity and monitoring Initial mechanical integrity must be demonstrated under rule 20 AAC 25.412. After this the operator must continue to monitor the well for mechanical integrity by monitoring and recording well head injection pressure (WHIP), rate, IA pressure, and OA pressure during injection operations. Also this data must be submitted with the Monthly Injection Report (10-406). Section E —Abnormal WHIP, IA pressure, & OA pressure or failed test The commission must be notified by the next working day in the case of a failed test or abnormal pressure along with a plan to either correct the issue or increase monitoring. Actions after the anomaly is reported are up to the commission. Section F — Addition mechanical integrity tests Further testing will be required by the commission if they deem necessary in order to prevent waste or protect fresh water sources. Assuming the well is set up correctly this should not be an issue but could be with a change in regulations. Section G — Modifying the Existing DIO This could come up if after operations the WHIP or the rate is not what was expected or changes over time due to changes in the near wellbore or reservoir pressure. If a modification is needed the AOGCC must be involved ahead of time. Appendix D: Milne Point Unit Aquifer Exemption Order Hilcorp Alaska, LLC DIO Application: MPU Moose Pad Appendix D Appendix D: Milne Point Unit Aquifer Exemption Order STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Re: THE REQUEST ) Aquifer Exemption Order No. 2 OF CONOCO, INC.) for an aquifer ) Milne Point Unit Exemption order for the ) Kuparuk River Field Milne Point Unit. July 8, 1987 IT APPEARING THAT: 1. Conoco, Inc. (Conoco), by letter of May 1, 1987, requested that the Alaska Oil and Gas Conservation Commission issue an order exempting those portions of all freshwater aquifers lying directly below the Milne Point Unit for Class II injection activities. 2. Notice of an opportunity for a public hearing on June 11, 1987 was published in the Anchorage Daily News on May 15, 1987. 3. Neither a protest nor a request for a public hearing was timely filed. Accordingly, the Commission will, in its discretion, issue an order without a public hearing. 4. A copy of Conoco's request was forwarded to the U.S. Environmental Protection Agency (EPA) - Region 10 on May 8, 1987 in conformance with Section 13 of the Memorandum of Agreement, between the Alaska Oil and Gas Conservation Commission and EPA, effective June 19, 1986. 5. A request for additional information was received from EPA on June 1, 1987, and a copy of Conoco's "Supplement to the Application..." dated June 12, 1987 was forwarded to EPA on June 18, 1987. FINDINGS: 1. Those portions of freshwater aquifers occurring beneath the Milne Point Unit do not currently serve as a source of drinking water. 2. Those portions of freshwater aquifers occurring beneath the Milne Point Unit are situated at a depth and location that makes recovery of water for drinking water purposes economically impracticable. 3. Those portions of freshwater aquifers occurring beneath the Milne Point Unit are reported to have a total dissolved solids content of more than 3,000 and less than 10,000 mg/I, and are not reasonably expected to supply a public water system. 4. By letter of July 2, 1987, EPA - Region 10 advises that the aquifers occurring beneath the Milne Point Unit qualify for exemption. It is considered to be a minor exemption and a non - substantial program revision not requiring notice in the Federal Register. 5. The Milne Point Unit area constitutes a compact land parcel which can readily be described by governmental subdivisions. CONCLUSION: Those portions of freshwater aquifers lying directly below Milne Point Unit qualify as exempt freshwater aquifers under 20 AAC 25.440. NOW, THEREFORE, IT IS ORDERED THAT the portions of aquifers on the North Slope described by the one-quarter ('/4) mile area beyond and lying directly below the following tracts of land are exempted for Class TI injection activities only. Umiat Meridian T1 3N R9E Sections 13, 14, 23 and 24. T1 3N R10E All Sections. T13N R11E Sections 5, 6, 7, 8, 15, 16, 17, 18, 19, 20, 21, 22, 29, 30, 31 and 32. DONE at Anchorage, Alaska, and dated July 8, 1987. C. V. Chatterton, Chairman Alaska Oil and Gas Conservation Commission Lonnie C. Smith, Commissioner Alaska Oil and Gas Conservation Commission W. W. Barnwell, Commissioner Alaska Oil and Gas Conservation Commission Appendix E: Water Cost Study Hilcorp Alaska, LLC DIO Application: MPU Moose Pad Appendix E �GVJones 8 Associates, Inc. �� warex •xx wasrewarex xxoceaa exaixeexa 1200 E 76" Avenue, Unit 1207 Anchorage, Alaska 99518 Phone: (907) 346-4123 MEMORANDUM To: Wyatt Rivard Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 From: Lisa Woolard/ GVJ&Af... f �% Subject: Potable Water Equipment and Facilities Costs Date: February 6, 2018 Purpose Hilcorp Alaska, LLC (HAK) wishes to determine costs for equipment and facilities to produce potable water from raw water sources available on the North Slope of Alaska. HAK asked GV Jones & Associates, Inc. (GVJ&A) to assist with preparation of rough order of magnitude (ROM) cost estimates for such equipment and facilities. This memorandum presents background information and ROM cost estimates for equipment and facilities to produce potable water from three types of potential raw water sources; fresh surface water, seawater, and deep well water (saline, from oil/gas formations). Potable Water Equipment Basic treatment unit processes for each of the three types of potential raw water sources were assumed as follows: • fresh surface water (i.e. tundra pond, lake, or river water reservoir). Nanofiltration, Giardia/Crypto filters, chlorine -based disinfection. Suitable surface water disposal of nanofilter concentrate. Seawater (seawater collected below seabed i.e. driven well point, infiltration gallery). Reverse Osmosis, deep well injection of brine waste. Deep well water. Oil/Gas separation, volatiles stripping, reverse osmosis, deep well injection of brine waste. Costs of equipment were solicited from equipment suppliers based on the production of 20,000 gallons per day (gpd) of potable water. The costs presented herein are necessarily ROM estimates and are not based upon preliminary design nor engineering of the equipment and facilities. The ROM estimates are compiled to reflect comparative costs of the three source waters and treatment unit processes assumed for each. Fresh Surface Water Source A North Slope fresh water source such as a tundra pond, lake, or river water reservoir was assumed for this analysis. Fresh surface water must be treated to potable water regulations and standards including the surface water treatment rules (SWTRs). As such, a common treatment train may include: straining, antiscalant, nanofiltration (NF), filters specific to Giardia lamblia and Cryptosporidium removal, and chlorine -based disinfection including a water volume reserved for chlorine contact time. A NF treatment system may require about 26,667 gpd of feed water to produce 20,000 gpd of potable water and 6,667 gpd of nanofilter concentrate (NFC) requiring disposal. Disposal of NFC to surface waters requires a discharge permit and potentially a mixing zone. Requirements of the discharge to both marine and fresh receiving waters include stringent water quality standards that are not always easily met. Alternatively, if already available at a site, the simplest method of disposal of NF concentrate (NFC) from a regulatory and compliance standpoint may be deep well injection. Seawater Source A North Slope seawater source is best utilized if the seawater may be collected below the sea bed, either in a driven well point or an infiltration gallery, such that the seawater may be collected with the least amount silt, sand, and debris; and the collection point is protected from ice movement in the shallow waters of North Slope seas. The EPA does not require seawater sources to be treated to the S WTRs, generally due to seawater not being heavily impacted by pathogenic organisms that are typically fresh water organisms. And, the treatment methods necessarily applied to seawater to remove dissolved solids, such as distillation and reverse osmosis (RO), are capable of pathogen removal well in excess of that required by the S WTRs. The Alaska Department of Environmental Conservation (ADEC) may require treatment of permeate by chlorine disinfection of they determine it is required (4 -log inactivation of viruses). As such, a common treatment train may include: straining, antiscalant, reverse osmosis, and chlorine -based disinfection. A RO treatment system may require about 40,000 gpd of feed water to produce 20,000 gpd of potable water and 20,000 gpd of RO concentrate (ROC) requiring disposal. The simplest method of disposal of ROC (also called brine) from a regulatory and compliance standpoint may be deep well injection. Disposal of ROC to marine receiving water requires a discharge permit and potentially a mixing zone. Requirements of the discharge to marine receiving water includes stringent water quality standards that are not always easily met. Deep Well Source A North Slope deep well water source in oil/gas field areas is likely saline and containing hydrocarbon constituents. Since the deep well source is considered a groundwater, ADEC is not likely to require disinfection. As such, a treatment train may include: gas separation/stripping, oil/water separation, straining, antiscalant, and RO. Similar to the above RO option in regard to ROC quantity, disposal to marine receiving water requires a discharge permit and potentially a mixing zone, including stringent water quality standards that are not always easily met. In addition to ROC disposal, the treatment of the deep well source water requires disposal or use of the hydrocarbon constituents removed in the pretreatment unit processes. These residual constituents may be returned to the production processes particular to the site or combined with the ROC for deep well injection. Deep well injection of waste waters for any of the above options is regulated by the ADEC with their General Permit 2016DB00I Class I Well Waste Disposal and EPA with their Class I UIC Permit AK Page 3 11000. Deep well injection of waste waters could also be conducted under a Class II permit if the disposal well was associated with oil and gas production operations. Facilities Costs Equipment suppliers were solicited to provide budgetary costs for the treatment unit processes noted above for each source water option. A spreadsheet was compiled of the ROM costs and a summary of that information is provided in Table 1. Table 1. Estimated ROM Costs for Potable Water Facilities Source Facilities $ M Cost Operating Cost $per 1000 gallons Surface Water Freshwater 1.21 21.83 Seawater 2.03 26.79 -Deep Well Water 7.23 63.55 Estimated Costs for Potable Water Systems Milne Point Unit (February 2018) Source Cost Commercial Potable Water: No installation. Purchased at $90/1000 gallon or $1800/day from Deadhorse AK, does not include transport. $90.00 per 1000 gallons Installation Cost: 20,000 gallon/day filtration -purification system fed byfresh surface water. Process Equipment and Tanks (Nanofiltration) $379,600 20 x 23 Building $294,676 Source pumps & Pipeline Depend on surface situation - Assume 800 feet of line $130,000 Surfacewater Disposal Pipeline - Assume 1000 feet of line $162,500 Allowance: Civil, Mech, Elect, Controls; 15 % $120,641 Contractor Gen Requirements 10%, O&P 10%, 20% Contingency $119,617 Total Installation Cost S1,210,000 Operating Cost: Trucking, chemicals and maintenance on a per 1000 gallon basis. Trucking $10.87 Chemicals $0.32 Maintenance $10.64 Total Operating Cost 21.83 Installation Cost: 20,000 gallon/day desalination and purification system fed by seawater water. Process Equipment and Tanks (reverse osmosis) $577,200 10% of 4200' ND multi source disposal well for injecting desalination vessel waste water. (MPB-34 Comp) $490,000 20 x 23 Building $294,676 Sewater Bed Well point $100,000 Source pumps & Pipeline Depend on surface situation -Assume 800 feet of line $130,000 Allowance: Civil, Mech, Elect, Controls; 15 % $238,781 Contractor Gen Requirements 10%, C&P 10%, 20% Contingency $201,374 Total Installation Cost $2,030,000 Operating Cost: Trucking, chemicals and maintenance on a per 1000 gallon basis. Trucking $11.01 Chemicals $0.70 Maintenance $13.30 Wellwork: Assume 10% of rig workover ($1.3MM *B-01 Comp) costs on multisource disposal well every 10 years resulting in an additional cost of roughly $1.78 per 1000 gallons $1.78 Total Operating Cost 26.79 1oft Estimated Casts for Potable Water Systems Milne Point Unit (February 2018) Source Cost Deep Well Water flMethane TDS> 2000 mL Cost for a 20,000 gallon/day filtration-purification system fed by gassy, saline subsurface water (deep-well). i 100% of 3200' TVD purpose built water well with hookups. (MPJ-02 Comp) $4,500,000 10% of 4200' TVD multi source disposal well for injecting desalination vessel waste water. (MPB-34 Comp) jgg0,000 Gravel Pads for wells (permitting & installation) $60,000 Source-water gas separation, waste water tankage, injection pumps, piping $160,000 30 x 40 building $768,720 Process Equipment and Tanks (oil/water separation and reverse osmosis) $777,200 Allowance: Civil, Mech, Elect, Controls; 15 % $255,888 Contractor Gen Requirements 10%, O&P 10%, 20% Contingency $215,800 Total Installation Cost $7,230,000 Operating Cost: Trucking, chemicals and maintenance on a per 1000 gallon basis. Trucking $11.19 Chemicals $0.80 Maintenance $15.96 Wellwork: Assume 100% of rig workover (1.3MM *B-03 Comp) costs on purpose built source water well every 5 years adding a cost of roughly $35.60 per 1000 gallons $35.60 Wellwork: Assume 10% of rig workover ($1.3MM *B-01 Comp) costs on multisource disposal well every 10 years resulting in an additional cost of roughly $1.78 per 1000 gallons $1.78 Total Operating Cost 193.55 2 oft
