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Home My WebLink AboutDIO 047DISPOSAL INJECTION ORDER 47 1. May 15, 2024 Hilcorp application to convert Susan Dionne Well 8 (PTD 213-051) to Class II Disposal 2. May 30, 2024 Notice of public hearing 3. January 29, 2025 Hilcorp Application to Amend DIO 47 (DIO 47.001) 4. March 13, 2025 DIO 47 Amendment email chain (DIO 47.001) STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue Anchorage, Alaska 99501 Re: THE APPLICATION OF Hilcorp Alaska, LLC for disposal of Class II oil field wastes by underground injection into the Beluga 135 Zone in well Susan Dionne 8, located within the Ninilchik Unit in Sections 6 and 7 of T1S, R13W, SM. ) ) ) ) ) ) ) ) ) Disposal Injection Order 47 Docket Number: DIO-24-002 Ninilchik Unit Well Susan Dionne 8 PTD 213-051 Kenai Peninsula Kenai Peninsula Borough July 8, 2024 IT APPEARING THAT: 1. By application dated May 15, 2024, Hilcorp Alaska, LLC (Hilcorp) requested authorization for underground disposal of Class II oil field waste fluids into the existing Ninilchik Unit (NU) well Susan Dionne 8 (SD8; API Number 50-133-20611-00-00). 2. Within the application, Hilcorp provided an affidavit stating all surface owners within a one- quarter mile of existing SD8 well were provided a copy of the application for disposal. 3. Pursuant to 20 AAC 25.540, the Alaska Oil and Gas Conservation Commission (AOGCC) tentatively scheduled a public hearing for July 16, 2024. On May 30, 2024, the AOGCC published notice of that hearing on the State of Alaska’s Online Public Notice website, the AOGCC’s website, and electronically transmitted the notice to all persons on the AOGCC’s email distribution list. On June 2, 2024, the notice was published in the Anchorage Daily News. On June 5, 2024, the notice was published in the Peninsula Clarion. 4. The AOGCC did not receive any requests to hold the hearing, public comments, or protests. 5. The public hearing tentatively scheduled for July 16, 2024 was vacated. 6. Hilcorp’s application, testimony, supplemental information, and AOGCC’s public records provide sufficient information to make an informed decision. FINDINGS: 1. Location of Adjacent Wells (20 AAC 25.252(c)(1)) SD8 is an idle gas development well located on the Susan Dionne drill site within the NU. The bottomhole location for the well is 482 feet from the north line and 682 feet from the west line of Section 7, Township 1S, Range 13W, Seward Meridian (SM). Only one well, Susan Dionne 1A (SD1A; API Number 50-133-10002-01-00), penetrates Hilcorp’s informally named Beluga 135 zone within a ¼-mile radius of SD8 (see Figure 1). SD1A was completed in the Beluga 135 zone at a location approximately 80 feet from SD8 to gather data about the reservoir and its suitability for disposal injection operations. SD1A and SD8 both have good cement across the proposed injection zone and its confining layers. 2. Notification of Operators and Surface Owners (20 AAC 25.252(c)(2) and 20 AAC 25.252(c)(3)) Hilcorp is the only operator within a ¼-mile radius of the proposed disposal well. Hilcorp identified and notified 13 surface owners within a ¼-mile radius of SD8. Disposal Injection Order 47 August 8, 2024 Page 2 of 9 Figure 1. Index Map – SD8 Area The green dashed line represents the SD8 boundary; the red dashed circle represents a radius of one-quarter mile from the planned disposal zone. (Source: Hilcorp Alaska, LLC’s application) 3. Geological Information on Disposal and Confining Zones (20 AAC 25.252(c)(4)) In SD8, Hilcorp’s proposed disposal injection zone lies within the Beluga Formation (Beluga) between 3,896’ and 3,945’ measured depth (MD), which are equivalent to 3,754’ and 3,799’ true vertical depth (TVD). This requested interval is a portion of Hilcorp’s informally named Beluga 135 zone. It consists of very fine- to fine-grained, moderately to well-sorted sandstone that was deposited as part of a vertical sequence of stacked fluvial channels that are separated by intervals of interlaminated mudstones and siltstones with occasionalthin coal seams. Beluga 135 sand porosity ranges from 19 to 30% and permeability ranges from 3 to 139 millidarcies. The top of the Beluga 135 zone is marked by a thin coal seam that can be correlated across the local geologic structure. There are no known faults at these depths in the vicinity of the Susan Dionne Pad. Upper confinement is provided by an aggregate of more than 115 true vertical feet of laterally continuous, interlaminated mudstones and siltstones with occasional thin coal seams that constitute Hilcorp’s Beluga 131 to upper Beluga 135 intervals. Lower confinement is provided by more than 75 true vertical feet of laterally continuous mudstone and siltstone layers with occasional thin coal seams within the lower Beluga 135, Beluga 136, and Tyonek T-2 intervals. 4. Well Logs (20 AAC 25.252(c)(5)) Log data for SD8, SD1A, and the other nearby wells are on file with the AOGCC. Disposal Injection Order 47 August 8, 2024 Page 3 of 9 5. Demonstration of Mechanical Integrity and Disposal Zone Isolation (20 AAC 25.252(c)(6)) The casing across the proposed disposal zone in SD8 is 7-5/8” 29.7# L-80. Cement across the disposal zone and confining layers consists of 352 barrels (bbls) of 14.5 pounds per gallon (ppg) Class G lead and 62 bbls of 15.5 ppg Class G. A subsequent Cement Bond Log (CBL) run on September 20, 2013, showed top of cement at 1,550’ MD and sufficient cement across the Beluga 135 disposal zone and associated confining layers for isolation. Figure 1. Stratigraphic Correlation between SD8 (left) and Nearby Well SD1A (right). Proposed disposal zone identified by light yellow fill within the central vertical bar. (Source: Hilcorp Alaska, LLC’s application) Disposal Injection Order 47 August 8, 2024 Page 4 of 9 Figure 3. Beluga 135 Structure Map – SD8 Area Red circle represents the requested aquifer exemption area (one-quarter-mile radius). (Source: Hilcorp Alaska, LLC) The tubing is isolated from the casing with two hydraulic-set isolation packers straddling the Beluga 135 disposal zone. The annulus was pressure tested to 2,000 pounds per square inch (psi) in 2014. In SD8, open perforations in the underlying Tyonek Formation will be isolated, and the Beluga 135 disposal zone will be perforated prior to disposal operations. An injection test in the disposal zone will be performed, and the results will be detailed in a Sundry Report (AOGCC’s Form 10-404). Hilcorp will perform a Mechanical Integrity Test (MIT) once the Beluga 135 Disposal Injection Order 47 August 8, 2024 Page 5 of 9 disposal zone is isolated and ready for disposal operations. This testing, as proposed, meets the requirements of 20 AAC 25.412. 6. Disposal Fluid Type, Composition, Source, Volume, and Compatibility with Disposal Zone (20 AAC 25.252(c)(7)) Waste disposal injection will consist primarily of solids-free produced water from Hilcorp's NU operations, and other fluids eligible for injection into a Class II disposal well. The average daily disposal volume will depend on whether Deep Creek Unit well NNA 1 remains the primary disposal well for NU operations. If so, disposal will only occur in SD8 if additional disposal capacity is required or if NNA 1 needs to be supplemented. The maximum daily disposal volume is currently 3,000 bbls, and during 2023 it averaged 292 bbls. This corresponds to an average injection rate of 2.0 barrels per minute (bpm). This rate and daily disposal volume is consistent with DIO 28, which authorizes injection disposal operations in NNA 1, and fracture modeling used to validate confinement of injected fluids. No compatibility issues were identified when Hilcorp collected and analyzed fluid samples destined for disposal in NNA 1 and compared these to water samples from the equivalent Beluga 135 zone in SD1A. 7. Estimated Injection Pressures (20 AAC 25.252(c)(8)) The estimated maximum injection pressure will be 2,025 pounds per square inch gauge (psig) and 2.0 bpm. An injectivity test was performed in strata equivalent to the Beluga 135 disposal zone in nearby SD1A well at various rates (Sundry 323-142) indicating an average injection pressure of 1800-1900 psi to achieve a 2.0 bpm rate. 8. Evaluation of Confining Zones (20 AAC 25.252(c)(9)) The effectiveness of the confining zones – both upper and lower – has been demonstrated by an injectivity test performed in the Beluga 135 disposal zone in SD1A. Analysis of these results was provided in Hilcorp’s application. Stimulation model results for the proposed disposal zone, using a third-party model, were submitted as part of Hilcorp’s application. This modeling found that the planned disposal operations into the proposed disposal zone, as outlined in the application, will not propagate fractures through the confining zones. Based on the geologic similarities and very close proximity of SD1A to SD8, the fracture modeling submitted with the application is considered applicable to SD8. The previously proposed injection rates, volumes, and pressures are in line with the fracture modeling results. 9. Standard Laboratory Water Analysis of the Formation (20 AAC 25.252(c)(10)); Aquifer Exemption (20 AAC 25.252(c)(11)) Standard laboratory water analyses for samples collected from the Beluga 135 in nearby well SD1A were submitted with Hilcorp’s application. Water samples obtained from SD1A are considered representative of the formation waters in SD8 due to close proximity. Hilcorp has applied, in conjunction to this DIO application, for an Aquifer Exemption Order (AEO) under AOGCC Docket AEO-24-001. That application aims to exempt those portions of aquifers within a ¼-mile radius of SD8 that are common to and correlate with the Beluga 135 disposal zone in SD8. Although the Total Dissolved Solids content of the Beluga 135 Disposal Injection Order 47 August 8, 2024 Page 6 of 9 formation waters is quite low (1,700 to 1,920 mg/l), in the AOGCC’s judgement the Beluga 135 zone will not serve as a source of water for human consumption because it is gas-bearing, excessively contaminated by six metals and several organic compounds, lies at great depth requiring a well that would be very expensive to drill, equip, maintain, and operate, and is located in an area having plentiful very shallow freshwater aquifers. There are 13 registered water wells and five subsurface water rights authorizations recorded within Sections 5, 6, 7, and 8 of T1S, R13W, SM that lie within about 1-1/2 miles of the proposed injection zone. The deepest and closest drinking-water well in this area is the Susan Dionne Pad Water Well, which is 257 feet deep and located on the same drill site. The total depth reached by this water well lies about 3,450 vertical feet shallower than the top of the planned injection zone in SD8. There are no other water wells within one-half mile radius of the planned injection zone within SD8. The other registered wells and subsurface water rights mentioned above range in depth from 50’ to 200’. In addition, Hilcorp identified two public water system sources wells in the area: a 200-foot deep well at Scenic View RV Park located 1.8 miles northeast of Susan Dionne 8, and a 45-foot deep well at Ninilchik 132.6 Cabins and RV Park is located three miles southwest of Susan Dionne 8. 10. Mechanical Condition of Wells Penetrating the Disposal Zone Within a ¼-Mile Radius of the proposed disposal wells (20 AAC 25.252(c)(12)) Only one well, SD1A, penetrates the Beluga 135 disposal zone within a 1/4-mile radius of the existing SD8 well. Construction information for each well, including cement tops for casing set across the Beluga 135, is summarized in the application. Detailed well construction information is in the AOGCC’s well files. In addition, Hilcorp has summarized the results of the CBLs run for the two wells, and the logs are on file with AOGCC. CONCLUSIONS: 1. The application requirements and conditions for approval of an underground disposal application in 20 AAC 25.252 have been met. 2. The Beluga 135 aquifer within a 1/4-mile radius of the proposed disposal zone within SD8 is judged to qualify as exempt under 20 AAC 25.440 because it is hydrocarbon bearing, contaminated by metals and organic compounds, and is located at such a depth that makes it economically and technologically impractical to serve as a source of drinking water now or in the future. Hilcorp has separately applied for an Aquifer Exemption Order (AEO) under AOGCC Docket AEO-24-001. An AOGCC issued AEO is not effective for disposal operations until approved by the United States Environmental Protection Agency under 20 AAC 25.440 (d)(1). 3. The proposed Beluga 135 disposal zone and associated confining layers are laterally continuous over this portion of the NU. Interlaminated mudstones, siltstones, and thin coal seams totaling approximately 115’ true vertical thickness above, and about 75’ true vertical thickness below, the injection zone will confine injected wastes. 4. Injected fluids will remain confined to the intended zone as supported by injectivity results from correlative sands within the nearby SD1A well. 5. Waste fluids will be contained within the Beluga 135 disposal zone by the confining lithologies based on the SD1A modeled injection rates, volumes, fluid densities, and pressures, which exceed expected SD8 operating conditions. Cement isolation of the injection zone in the well bore and operating conditions further support the AOGCC’s conclusion about confinement. Disposal Injection Order 47 August 8, 2024 Page 7 of 9 6. No fluid or formation compatibility issues are expected by disposing of water produced from the Beluga, Sterling, and Tyonek Formations into the Beluga 135 disposal zone at SD8. 7. Reviews of mechanical integrity of the SD8 and SD1A wells show that for the expected volumes the wellbores are adequately cemented and cased to prevent the movement of injected fluids outside of the disposal zone. Supplemental mechanical integrity demonstrations and surveillance of injection operations are appropriate to ensure waste fluids are contained within the disposal zone. Included are mechanical integrity testing, temperature surveys, monitoring of injection performance (pressures and rates), and analysis of the data for indications of anomalous events. NOW, THEREFORE, IT IS ORDERED THAT Hilcorp’s request for authorization for underground disposal of Class II fluids into well SD8 is GRANTED. 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 Beluga 135 Disposal Zone within the SD8 well. RULE 1: Injection Strata for Disposal Underground disposal of the Class II fluids listed below is permitted into the Beluga 135 Disposal Zone within SD8 in the zone that is common to and correlates with the interval between 3,896’ and 3,945’ MD (equivalent to 3,754’ and 3,799’ TVD) in well SD8 (API Number 50-133-20611- 00-00). RULE 2: Authorized Fluids This authorization is limited to Class II eligible waste fluids generated within the NU 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. Commercial Class II disposal injection (i.e., fluids from a different operator or from a different unit) is prohibited. 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 zones or migrate out of the approved injection stratum. Disposal injection is authorized at (a) rates that do not exceed 2.0 bpm and (b) surface pressures that do not exceed 2,025 psig. RULE 4: Demonstration of Mechanical Integrity The mechanical integrity of SD8 must be demonstrated before injection begins and before returning the well to service following a workover affecting 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, rate, etc.) have stabilized. Subsequent mechanical integrity tests must be performed at least once every two years Disposal Injection Order 47 August 8, 2024 Page 8 of 9 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. The AOGCC must be notified at least 24 hours in advance to enable a representative to witness a mechanical integrity test. Unless an alternative means is approved by the AOGCC, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure equivalent to the maximum injection pressure, or 1500 psi, whichever is greater, that shows stabilizing pressure and does not change more than 10 percent during a 30-minute period. Results of mechanical integrity tests must be readily available for AOGCC inspection. 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 directed by the AOGCC. If fluids are found to be fracturing through a confining zone 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 until 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 zone. 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. The operator 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 must be submitted by July 1st. The annual report shall also include a section titled “Induced Seismicity” in which the operator shall detail its monitoring efforts and evaluate the risks. RULE 7: Notification of Improper Class II Injection 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. Disposal Injection Order 47 August 8, 2024 Page 9 of 9 Notification or other legal requirements of any other State or Federal agency remain the operator's responsibility. DONE at Anchorage, Alaska, and dated August 8, 2024. Jessie L. Chmielowski Gregory C. Wilson Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Gregory Wilson Digitally signed by Gregory Wilson Date: 2024.08.08 14:31:01 -08'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.08.08 14:53:26 -08'00' From:Coldiron, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Disposal Injection Order 47 (Hilcorp) Date:Friday, August 9, 2024 7:48:53 AM Attachments:dio47.pdf THE APPLICATION OF Hilcorp Alaska, LLC for disposal of Class II oil field wastes by underground injection into the Beluga 135 Zone in well Susan Dionne 8, located within the Ninilchik Unit in Sections 6 and 7 of T1S, R13W, SM. Samantha Coldiron AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: samantha.coldiron@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.coldiron%40alaska.go v Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVAL DISPOSAL INJECTION ORDER 47.001 DISPOSAL INJECTION ORDER 28A.001 DISPOSAL INJECTION ORDER 30A.001 Mr. Daniel Taylor, P.E. Well Integrity Engineer Hilcorp Alaska, LLC. 3800 Centerpoint Drive Anchorage, AK 99503 Re: Docket Number: DIO-25-001 Disposal Injection Order 47.001 Request for Amendment to Rule 2 of Disposal Injection Order (DIO) 47 Amendment to Rule 6 of DIO 47 Susan Dionne 8 (PTD 2130510), Ninilchik Unit, Kenai Peninsula DIO 28A.001 Amendment to Rule 2 and Rule 5, Rescinding Rule 7 of DIO 28A NNA-1 (PTD 2012150) Deep Creek Unit, Kenai Peninsula DIO 30A.001 Expiration of DIO 30A NNA-2 (PTD N/A) Deep Creek Unit, Kenai Peninsula Dear Mr. Taylor: By emailed letter dated January 29, 2025, Hilcorp Alaska, LLC (Hilcorp) requested an amendment to Rule 2 of DIO 47 to allow disposal of wastes Hilcorp generated from other Units. In accordance with 20 AAC 25.556(d), the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS Hilcorp’s request to amend DIO 47 Rule 2: Authorized Fluids, to authorize disposal of Hilcorp generated wastes from additional Units. In addition, on its own motion, AOGCC amends DIO 47 Rule 2, to authorize commercial disposal operations (i.e. wastes generated from other operators, and/or from other Units). In addition, on its own motion, AOGCC amends DIO 47 Rule 6: Surveillance, to increase reporting requirements. In addition, on its own motion, AOGCC amends DIO 28A Rule 2: Authorized Fluids, to authorize commercial disposal operations, amends DIO 28A Rule 5: Surveillance, to increase reporting DIO 47.001 DIO 28A.001 DIO 30A.001 March 19, 2025 Page 2 of 5 requirements, and rescinds DIO 28A Rule 7: Administrative Action. Administrative action of an AOGCC issued order is now authorized under 20 AAC 25.556(d). In addition, on its own motion, in accordance with 20 AAC 25.556(c)(1), AOGCC concludes that DIO 30A has EXPIRED. DIO 30A was issued on June 14, 2005, but the proposed disposal well NNA-2 was not drilled and as such disposal operations did not commence. NOW THEREFORE IT IS ORDERED THAT: DIO 47 shall be amended to read as follows: RULE 2: Authorized Fluids This authorization is limited to Class II eligible 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. Commercial Class II oil field waste disposal is approved. Commercial (third party non- Hilcorp generated, and/or generated from other Units) Class II oil field waste disposal shall be in compliance with all rules of this DIO and it remains the responsibility of Hilcorp to accurately account for volumes and ensure that all fluids injected meet Class II eligibility requirements. 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. The operator 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 DIO 47.001 DIO 28A.001 DIO 30A.001 March 19, 2025 Page 3 of 5 of the disposal order findings, conclusions, and rules based on actual performance. The annual report must be submitted by July 1st. The annual report shall also include a section titled “Induced Seismicity” in which the operator shall detail its monitoring efforts and evaluate the risks. Commercial disposal injection details shall also be provided in the annual performance report. The report shall include: 1. an overview of commercial activities for the year; 2. a list, based on manifests, showing waste generating company, identification of well or pad where the waste was generated, type of waste, volume, transport company/driver, signature/name of Hilcorp authority confirming waste as Class II; 3. a list of the operators that Hilcorp has a Facility User Agreement (FUA) with; 4. a list of operators that Hilcorp has a Road Use Agreement (RUA) with; 5. a list of Hilcorp employees having completed the Hilcorp commercial Class II training and are authorized to accept waste; 6. a review of the Hilcorp Waste Analysis Plan (WAP) and any changes to the plan; 7. a review of the External Manifest procedures including any changes to the process; and 8. a review of the pre-call and approval policy that is designed to ensure the facility is ready and able to accept and process the commercial waste. DIO 28A shall be amended to read as follows: RULE 2: Authorized Fluids This authorization is limited to Class II eligible 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. Commercial Class II oil field waste disposal is approved. Commercial (third party non- Hilcorp generated, and/or generated from other Units) Class II oil field waste disposal shall be in compliance with all rules of this DIO and it remains the responsibility of Hilcorp to accurately account for volumes and ensure that all fluids injected meet Class II eligibility requirements. DIO 47.001 DIO 28A.001 DIO 30A.001 March 19, 2025 Page 4 of 5 RULE 5: Surveillance The operator shall obtain a baseline temperature log and 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. The operator 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 must be submitted by July 1st. The annual report shall also include a section titled “Induced Seismicity” in which the operator shall detail its monitoring efforts and evaluate the risks. Commercial disposal injection details shall also be provided in the annual performance report. The report shall include: 1. an overview of commercial activities for the year; 2. a list, based on manifests, showing waste generating company, identification of well or pad where the waste was generated, type of waste, volume, transport company/driver, signature/name of Hilcorp authority confirming waste as Class II; 3. a list of the operators that Hilcorp has a Facility User Agreement (FUA) with; 4. a list of operators that Hilcorp has a Road Use Agreement (RUA) with; 5. a list of Hilcorp employees having completed the Hilcorp commercial Class II training and are authorized to accept waste; 6. a review of the Hilcorp Waste Analysis Plan (WAP) and any changes to the plan; 7. a review of the External Manifest procedures including any changes to the process; and 8. a review of the pre-call and approval policy that is designed to ensure the facility is ready and able to accept and process the commercial waste. RULE 7: Administrative Action (Rescinded by 20 AAC 25.556(d)) NOW THEREFORE IT IS ORDERED THAT DIO 30A is expired. DIO 47.001 DIO 28A.001 DIO 30A.001 March 19, 2025 Page 5 of 5 DONE at Anchorage, Alaska and dated March 19, 2025. Jessie L. Chmielowski Gregory C. Wilson Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2025.03.19 12:30:59 -08'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.03.19 13:58:52 -08'00' From:Coldiron, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Disposal Injection Orders 47.001, 28A.001, and 30A.001expired (Hilcorp) Date:Wednesday, March 19, 2025 2:25:56 PM Attachments:DIO47.001_DIO28A.001_DIO30A.001expire.pdf Docket Number: DIO-25-001 Disposal Injection Order 47.001 Request for Amendment to Rule 2 of Disposal Injection Order (DIO) 47 Amendment to Rule 6 of DIO 47 Susan Dionne 8 (PTD 2130510), Ninilchik Unit, Kenai Peninsula DIO 28A.001 Amendment to Rule 2 and Rule 5, Rescinding Rule 7 of DIO 28A NNA-1 (PTD 2012150) Deep Creek Unit, Kenai Peninsula DIO 30A.001 Expiration of DIO 30A NNA-2 (PTD N/A) Deep Creek Unit, Kenai Peninsula Samantha Coldiron AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: samantha.coldiron@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.coldiron%40alaska.go v 4 CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From:Daniel Taylor To:Wallace, Chris D (OGC) Cc:Wyatt Rivard; Noel Nocas Subject:RE: [EXTERNAL] RE: Ninilchik SD 8 (PTD 213051) / DIO 47 Amendment Application Date:Thursday, March 13, 2025 1:44:19 PM Mr. Wallace, Your suggestion to authorize commercial disposal (DIO 47 & DIO 28A) under the same conditions as DIO 34B Rule 6 is reasonable. You are correct about the NNA #2 well (DIO 30A). The project never materialized and should be expired. Regards, Daniel Taylor, P.E. Well Integrity O: 907-777-8319 C: 907-947-8051 From: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Sent: Wednesday, March 12, 2025 12:41 PM To: Daniel Taylor <dtaylor@hilcorp.com> Cc: Wyatt Rivard <wrivard@hilcorp.com>; Noel Nocas <Noel.Nocas@hilcorp.com> Subject: [EXTERNAL] RE: Ninilchik SD 8 (PTD 213051) / DIO 47 Amendment Application Daniel, We are reviewing this application and are looking to amend the DIO 47 to authorize commercial disposal (other operators and/or other Units) and increase reporting by the same conditions as DIO 34B Rule 6 . Any concerns? We are also looking to do the same for DIO 28A. Any concerns? I note DIO 30A for NNA #2 was also a Deep Creek DIO - but I cannot find NNA 2 and no DIO 30A reporting which makes me think the well was not drilled and that the DIO 30A should be expired based on no disposal. Please confirm and let me know if I am missing anything. Are there any additional Class II wells in Ninilchik/Deep Creek/ road access corridor that I should authorize for commercial disposal with increased reporting requirements (same as DIO 34B) at this time? Thanks and Regards, Chris Wallace, Sr. Petroleum Engineer, Alaska Oil and Gas Conservation Commission, 333 West 7th Avenue, Anchorage, AK 99501, (907) CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 793-1250 (phone), (907) 276-7542 (fax), chris.wallace@alaska.gov 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: Daniel Taylor <dtaylor@hilcorp.com> Sent: Tuesday, February 4, 2025 8:55 AM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Wyatt Rivard <wrivard@hilcorp.com>; Noel Nocas <Noel.Nocas@hilcorp.com> Subject: Ninilchik SD 8 (PTD 213051) / DIO 47 Amendment Application Mr. Wallace, Ninilchik field, Susan Dionne 8 (PTD 213051) is planned to be converted to a Class II disposal well operating under DIO 47. Please see the attached Application for Amendment of DIO 47 clarifying and requesting injection of Hilcorp Alaska, LLC eligible Class II waste generated outside of the Ninilchik Unit. Regards, Daniel Taylor, P.E. Well Integrity O: 907-777-8319 C: 907-947-8051 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 3 January 29, 2025 Jessie Chmielowski, Commissioner Greg Wilson, Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 RE: Application for Amendment Disposal Injection Order 47 Kenai, Alaska Dear Commissioners: Hilcorp Alaska, LLC (“Hilcorp”), as Operator of the Ninilchik Unit (“NU”) in Kenai Alaska, hereby respectfully submits this application to amend Disposal Injection Order 47 (“DIO 47”) issued August 8, 2024, to modify the below sections of Rule 2 by removing the stipulations noted below (bold & strikethrough): RULE 2: Authorized Fluids This authorization is limited to Class II eligible waste fluids generated within the NU 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. Commercial Class II disposal injection (i.e., fluids from a different operator or from a different unit) is prohibited. Hilcorp requests the ability to inject authorized waste fluids per DIO 47 Rule 2 that are generated from other Hilcorp Alaska, LLC operated fields on the Kenai Peninsula. Having this capability increases the available well stock and flexibility for managing eligible Class II waste fluids. Having additional Class II disposal locations also provides shorter trucking options and the ability to address seasonal road conditions that affect Hilcorp’s primary disposal well in the Ninilchik area, Deep Creek Unit NNA No. 1 (NNA-1). Per the original DIO 47 permit application, the Susane Dionne 8 (SD-8) disposal well is intended to provide backup capacity for the NNA 1 disposal well. NNA 1 currently injects fluids trucked in from the Ninilchik Unit, Deep Creek Unit and Niolaevsk (“Red Pad”)” and is expected to be utilized for additional development of the Cottonfield, Whiskey Gulch and Seaview prospects. 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Phone: 907-777-8319 Email: dtaylor@hilcorp.com In accordance with 20 AAC 25.252 (section c, 7), Hilcorp’s application stated, “The primary disposal fluid planned for SD-8 is formation fluid from NU and other fields in the Kenai Peninsula. Waste disposal injection may also include other fluids eligible for Class II injection.” The term “other fields” is a reference to Hilcorp Alaska, LLC lease properties only and was not intended to include third parties or Harvest. Fluids eligible for Class II injection will be manifested to SD-8 using the Cook Inlet-Kenai Manifest. Employees and contractors who manifest wastes to Hilcorp’s injection facilities receive training every 2 years in Hilcorp’s Waste Management and Manifesting Training. Hilcorp maintains records concerning the nature and composition of injected fluids until three years after the well is plugged and abandoned. Manifests are kept on-site for at least one year after which they are forwarded to Anchorage for archiving. Should you require additional information regarding this application, please don’t hesitate to contact me at 777-8319. Sincerely, Daniel Taylor, P.E. Well Integrity Engineer Hilcorp Alaska, LLC cc: Chris Wallace Senior Petroleum Engineer, AOGCC (via e-mail) Samantha Coldiron Special Assistant, AOGCC (via e-mail) Digitally signed by Daniel Taylor (1691) DN: cn=Daniel Taylor (1691) Date: 2025.02.03 13:28:00 - 09'00' Daniel Taylor (1691) 2 Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RE: Docket Number: DIO-24-002 Hilcorp Alaska, LLC (Hilcorp), by letter dated May 15, 2024, filed an application to the Alaska Oil and Gas Conservation Commission (AOGCC) for a Class II Underground Injection Control Disposal Injection Order for existing well Susan Dionne 8, onshore in the Ninilchik Unit (NU), Kenai Peninsula, Alaska. In response to an application for disposal filed by an operator, the AOGCC may issue an order authorizing the underground disposal of oil field wastes that the commission determines are suitable for disposal in a Class II well, as defined in 40 C.F.R. 144.6(b) as revised as of July 1, 1998, which is adopted by reference, or the underground storage of hydrocarbons.1 This notice does not contain all the information filed by Hilcorp. You may obtain more information about this filing by contacting the AOGCC’s Special Assistant, Samantha Coldiron, at (907)793-1223 or samantha.coldiron@alaska.gov. A public hearing on the matter has been tentatively scheduled for July 16, 2024, at 10:00 a.m. The hearing, which may be changed to full virtual, if necessary, will be held in the AOGCC hearing room located at 333 West 7th Avenue, Anchorage, AK 99501. The audio call in information is (907) 202 7104 Conference ID: 977 858 930#. Anyone who wishes to participate remotely using MS Teams video conference should contact Ms. Coldiron at least two business days before the scheduled public hearing to request an invitation for the MS Teams. To request that the tentatively scheduled hearing be held, a written request must be filed with the AOGCC no later than 4:30 p.m. on June 17, 2024. If a request for a hearing is not timely filed, the AOGCC may issue an order without a hearing. To learn if the AOGCC will hold the hearing, call (907) 793-1223 after June 18, 2024. In addition, written comments regarding this application may be submitted to the AOGCC, at 333 west 7th Avenue, Anchorage, AK 99501 or samantha.coldiron@alaska.gov. Comments must be received no later than 4:30 p.m. on July 3, 2024, except that, if a hearing is held, comments must be received no later than the conclusion of the July 16, 2024, hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact Samantha Coldiron, at (907) 793-1223, no later than July 9, 2024. Brett W. Huber, Sr. Chair, Commissioner 1 20 AAC 25.252 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2024.05.30 09:22:29 -08'00' Lisi Misa being first duly sworn on oath deposes and says that she is a representative of the An- chorage 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 afore- said 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 AFFIDAVIT OF PUBLICATION ______________________________________ Notary Public in and for The State of Alaska. Third Division Anchorage, Alaska MY COMMISSION EXPIRES ______________________________________ 06/02/2024 and that such newspaper was regularly distrib- uted to its subscribers during all of said period. That the full amount of the fee charged for the foregoing publication is not in excess of the rate charged private individuals. Signed________________________________ Subscribed and sworn to before me Account #: 100869 ST OF AK/AK OIL AND GAS CONSERVATION COMMISSION333 W. 7TH AVE STE 100, ANCHORAGE, AK 99501 Order #: W0046117 Cost: $304.42 Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RE: Docket Number: DIO-24-002 Hilcorp Alaska, LLC (Hilcorp), by letter dated May 15, 2024, filed an application to the Alaska Oil and Gas Conservation Commission (AOGCC) for a Class II Underground Injection Control Disposal Injection Order for existing well Susan Dionne 8, onshore in the Ninilchik Unit (NU), Kenai Peninsula, Alaska. In response to an application for disposal filed by an operator, the AOGCC may issue an order authorizing the underground disposal of oil field wastes that the commission determines are suitable for disposal in a Class II well, as defined in 40 C.F.R. 144.6(b) as revised as of July 1, 1998, which is adopted by reference, or the underground storage of hydrocarbons.[1] This notice does not contain all the information filed by Hilcorp. You may obtain more information about this filing by contacting the AOGCC’s Special Assistant, Samantha Coldiron, at (907)793- 1223 or samantha.coldiron@alaska.gov. A public hearing on the matter has been tentatively scheduled for July 16, 2024, at 10:00 a.m. The hearing, which may be changed to full virtual, if necessary, will be held in the AOGCC hearing room located at 333 West 7th Avenue, Anchorage, AK 99501. The audio call in information is (907) 202 7104 Conference ID: 977 858 930#. Anyone who wishes to participate remotely using MS Teams video conference should contact Ms. Coldiron at least two business days before the scheduled public hearing to request an invitation for the MS Teams. To request that the tentatively scheduled hearing be held, a written request must be filed with the AOGCC no later than 4:30 p.m. on June 17, 2024. If a request for a hearing is not timely filed, the AOGCC may issue an order without a hearing. To learn if the AOGCC will hold the hearing, call (907) 793-1223 after June 18, 2024. In addition, written comments regarding this application may be submitted to the AOGCC, at 333 west 7th Avenue, Anchorage, AK 99501 or samantha.coldiron@alaska.gov. Comments must be received no later than 4:30 p.m. on July 3, 2024, except that, if a hearing is held, comments must be received no later than the conclusion of the July 16, 2024, hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact Samantha Coldiron, at (907) 793-1223, no later than July 9, 2024. Brett W. Huber, Sr. Chair, Commissioner Pub: June 2, 2024 STATE OF ALASKA THIRD JUDICIAL DISTRICT ______________________________________2024-06-03 2024-07-14 Document Ref: KRTF2-TYZYM-MZRKN-RWROF Page 29 of 36 Proofed by Schrader, Donna, 05/30/2024 01:54:43 pm Page: 2 Classified Proof Proofed by Schrader, Donna, 05/30/2024 01:54:43 pm Page: 3 Classified Proof From:Coldiron, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Public Hearing Notices (Hilcorp) Date:Thursday, May 30, 2024 12:29:33 PM Attachments:DIO-24-002 Public Hearing Notice Susan Dionne 8.pdf AEO-24-001 Public Hearing Notice Susan Dionne 8.pdf Docket Number: AEO-24-001 Hilcorp Alaska, LLC (Hilcorp), by application dated May 15, 2024, requests the Alaska Oil and Gas Conservation Commission (AOGCC) issue an order for aquifer exemption for an area extending one-quarter mile beyond the proposed injection zone in well Susan Dionne 8 within Sections 6 and 7 of Township 1 South, Range 13 West, Seward Meridian that lies within the boundaries of the Ninilchik Unit. Docket Number: DIO-24-002 Hilcorp Alaska, LLC (Hilcorp), by letter dated May 15, 2024, filed an application to the Alaska Oil and Gas Conservation Commission (AOGCC) for a Class II Underground Injection Control Disposal Injection Order for existing well Susan Dionne 8, onshore in the Ninilchik Unit (NU), Kenai Peninsula, Alaska. Samantha Coldiron AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: samantha.coldiron@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.coldiron%40alaska.go v 1 UIC CLASS II INJECTION WELL PERMIT APPLICATION SUSAN DIONNE 8 Ninilchik Unit Ninilchik, Alaska May 2024 Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99508 AOGCC | SD-8 UIC Class II Permit Application Hilcorp Alaska, LLC | Page 2 TABLE OF CONTENTS COVER LETTER………………………………………………………………………………………….4 PERMIT APPLICATION FORM…………………………………………………………………………6 MAPS AND AREA OF REVIEW……………………………………………………………………….19 EXHIBIT A-1: Ninilchik Unit Regional Map……………………………………...…………19 EXHIBIT A-2: Susan Dionne Area of Review…………………………………..………….23 EXHIBITS ATTACHED UNDER SEPARATE COVER: EXHIBIT A-3: Susan Dionne 8 Wellbore Schematic EXHIBIT A-4: Landowner Information EXHIBIT A-5: Public Announcement Affidavit EXHIBIT A-6: Beluga 135 Regional Cross Section EXHIBIT A-7: Beluga 135 Structure Map EXHIBIT A-8: Beluga 135 in SD-8 Type Log EXHIBIT A-9: Susan Dionne 8 Cement Bond Log (T# 23575) EXHIBIT A-10: NNA 1 Fluid Sample Compositional Analysis EXHIBIT A-11: SD-8 and SD-1A Beluga 135 Stratigraphic Cross Section EXHIBIT A-12: Aquifer Exemption Request EXHIBIT A-13: Susan Dionne 1/1A Wellbore Schematic EXHIBIT A-14: Susan Dionne 1A Radial Cement Bond Log (Transmittal # T20240507) EXHIBIT A-15: Susan Dionne 1/1A USIT (Transmittal # T20240507) AOGCC | SD-8 UIC Class II Permit Application Hilcorp Alaska, LLC | Page 4 AA. B.. HILCORP ALASKA, LLC May 15, 2024 Chairman Brett Huber, Sr. Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Subject: Application to convert Susan Dionne Well 8 (PTD 213-051) to Class II Disposal Dear Chairman Huber: Hilcorp Alaska, LLC (“Hilcorp”) submits this application for Susan Dionne 8 (“SD-8”) to be used for Class II disposal into the proposed disposal interval between approximately 3,550-3,950’ true vertical depth (TVD). This document covers the information required in 20 AAC 25.252 (c) and provides a brief overview of SD-8, the surrounding development, and the intended disposal zone. Hilcorp owns and operates the Susan Dionne pad which produces gas from the Ninilchik Unit (“NU”), as defined as the Affected Area described in Conservation Order No. 701C and shown in Exhibit A-1. Susan Dionne pad is in the town of Ninilchik, on the eastern margin of Cook Inlet, approximately 90 miles southwest of the city of Anchorage. Currently, produced water from Hilcorp’s NU operations, including Deep Creek Unit and Nikolaevsk (“Red Pad”), is hauled by truck to the Deep Creek Unit NNA No. 1 (“NNA 1”) well for disposal under DIO 28. NNA 1 is 7.5 miles inland from Ninilchik and accessed via an unpaved road that is subject to closures with inclement weather. Due to NNA 1’s daily injection and remote location relative to other NU infrastructure, the NNA pad must be frequently monitored and requires dedicated resources for trucking and injection pump operation. Ongoing production and additional development of NU – including prospects farther south at Cottonfield, Whiskey Gulch, and Seaview – depend heavily upon disposal at NNA 1. To enhance operational flexibility and reliability at existing operations, reduce resource constraints, add redundancy to NU’s disposal capacity, and facilitate new development at NU and the surrounding areas in the Kenai Peninsula, Hilcorp is seeking approval for Class II disposal at SD-8. The SD-8 well at Susan Dionne pad is accessed via a short access road off the Sterling Highway. As a pad with multiple active producers, the Susan Dionne facility is continuously operated and supervised. With the approval of this disposal application, Hilcorp will install a produced water injection module, a 200-barrel produced water tank, and all associated piping, electrical, and Post Office Box 244027 Anchorage, AK 99524-4027 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 Phone: 907/777-8300 Fax: 907/777-8301 By Samantha Coldiron at 1:19 pm, May 15, 2024 AOGCC | SD-8 UIC Class II Permit Application Hilcorp Alaska, LLC | Page 5 instrumentation/control tie-ins at Susan Dionne pad. The project scope will enable injection activity without additional supervision and allow for more consistent, efficient operations. While SD-8 was drilled in 2013 as an oil exploratory well, its original completion was as a dual- string gas producer in the Beluga 135 (short string) and the Tyonek T-140 (long string). In June 2014, production with this design was deemed uneconomic, all perforations were isolated, and the dual completion was replaced with a 4-1/2” completion accessing the Tyonek T-83 and T-90. Between June 2014 – March 2015, SD-8 produced gas from these two Tyonek sands. In March 2015, the Tyonek T-90 was isolated, leaving only the Tyonek T-83 open until August 2018. Perforations were then added to the Tyonek T-2 to revive the declining gas rate, but the Tyonek T-2 interval was unproductive. SD-8 has remained offline ever since, with no future uphole gas development opportunities. It does, however, have potential utility as a Class II disposal well. (The current wellbore schematic for SD-8 is shown in Exhibit A-3.) Following the approval of this application, Hilcorp will submit a sundry request to isolate open perforations in the Tyonek T-2 and T-83 sands and perforate the Beluga 135 into the proposed disposal zone. The following sections cover the information required by 20 AAC 25.252 (c). Sincerely, Casey Morse Well Integrity Engineer Hilcorp Alaska, LLC Digitally signed by Casey Morse (11458) DN: cn=Casey Morse (11458) Date: 2024.05.15 09:21:18 - 08'00' Casey Morse (11458) AOGCC | SD-8 UIC Class II Permit Application Hilcorp Alaska, LLC | Page 6 PERMIT APPLICATION FORM In accordance with 20 AAC 25.252 (c), an application for underground disposal or storage must include: 1. a plat showing the location of all proposed disposal and storage wells, abandoned or other unused wells, production wells, dry holes, and any other wells within one-quarter mile of each proposed disposal or storage well; Exhibit A-2 is a map of the Susan Dionne pad showing all wells within the one-quarter mile radius of the proposed injection zone. 2. a list of all operators and surface owners within a one-quarter mile radius of each proposed disposal or storage well; Hilcorp Alaska, LLC is the only operator in the area of SD-8. Exhibit A-4 presents information pertaining to records of land ownership within one-quarter mile of the Susan Dionne property boundary. Exhibit A-4 includes the Kenai Peninsula Borough (KBP) Parcel ID number, property usage, property legal description, property owner name, property owner mailing address, and property owner type. 3. an affidavit showing that the operators and surface owners within a one-quarter mile radius have been provided a copy of the application for disposal or storage; See Exhibit A-5. 4. the name, description, depth, and thickness of the formation into which fluids are to be disposed or stored and appropriate geological data on the disposal or storage zone and confining zones, including lithologic descriptions and geologic names; The Beluga 135 reservoir is a stacked channel composed of very-fine to fine-grained, moderately sorted sandstone. Core analysis shows an average porosity of ~23.5% and an average permeability (Klinkenberg) of ~61.7 mD. Additionally, X-Ray Diffraction (XRD) analysis from Susan Dionne 3 determined rock compositions of ~38% quartz, ~27% feldspar, and ~32% clay. The reservoir is heavily depleted from its initial reservoir pressure (~1,695 psi); recent pressure data suggests a reservoir pressure range of 350-700 psi. There are many internal confining beds and arresting beds above and below the proposed injection sand in the form of interlaminated mudstones, siltstones, sandstones, and coals. The uppermost confining beds, comprising the Beluga 131 through Beluga 134 siltstones and coals, are approximately 116’ thick. The lowermost confining beds, comprising the Beluga 136 and Tyonek T-2 siltstones and coals, are approximately 76’ thick. As demonstrated by Exhibit A-6 (cross section A-A’), the Beluga 135 reservoir is present across the entire Paxton-Kalotsa-Dionne structure at Ninilchik. This north-south cross section visually highlights that the Beluga 135 disposal interval increases in both sand quality and thickness near the top of structure; is both laterally and vertically continuous across the field; and contains an abundance of stacked upper and lower confining coals and shales that impede gas and fluid migration. AOGCC | SD-8 UIC Class II Permit Application Hilcorp Alaska, LLC | Page 7 The Exhibit A-7 structure map on the top of the Beluga 135 disposal interval shows that faulting is not a concern at Susan Dionne and that the reservoir structure is relatively simple across 3400-4000’ TVDss, the proposed Beluga 135 injection interval. Furthermore, there are no known transmissive faults at those depths in the vicinity of Susan Dionne pad. The reservoir properties for the proposed disposal zone are presented in Table 1. The target sand interval is located at ~3,597’ TVDss in SD-8. The Beluga 135 permeability and porosity ranges presented in the table are based on available core data from the Susan Dionne 3 and Kalotsa 2 wells. Critical to note is that the laminated nature of the sands makes it likely that the Beluga 135’s vertical permeability range is much lower than the measured horizontal permeability range given in the table. Table 1: Beluga 135 Reservoir Properties Proposed Class II Well (isn’t it class II?) Injection Zone Gross Thickness (feet) Porosity (%) Permeability (horizontal) (mD) SD-8 Beluga 135 Sand 50 19 - 30 3 - 139 Type Log Exhibit A-8 shows the proposed Beluga 135 injection zone (marked via orange box) in SD-8; additional arresting zone sands; and the mudstones, siltstones, and coals that make up the confining beds. The gross Beluga 135 interval spans 3,862’- 4,055’ MD. Exhibit B-8 includes the following log tracks: o Track 1: True Vertical Depth Subsea (TVDss); o Track 2: Comments indicating intervals with noteworthy mechanical components of the well (e.g., packers, active/inactive perforations, fill, etc.); o Track 3: Gamma Ray curve in green, scaled 30-100 API and shaded dark green for measurements at/above 80 API; o Track 4: Measured Depth in’ (MD) of SD-8; o Track 5: Shallow, medium, and deep resistivity on a 2-200 ohm-m log scale with deep resistivity shaded light green if > 8 ohm-m and dark green if > 15 ohm-m; and o Track 6: Sonic curve (DTC) from 135 to 54us/ft; Neutron Porosity curve (NPHI) from 0.6 to 0 pu; Density curve (RHOB) from 1.65 to 2.65 g/cm3; DTC and NPHI crossover shaded in yellow; NPHI and RHOB crossover shaded in red; and coal flags shaded gray <= 1.95 RHOB and >= 0.45 NPHI. AOGCC | SD-8 UIC Class II Permit Application Hilcorp Alaska, LLC | Page 8 5. logs of the disposal or storage wells, if not already on file, or other similar information; All relevant SD-8 well logs are on file with the AOGCC. 6. a 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 (A) the casing of the disposal or storage wells, if the wells are existing; The casing across the proposed Beluga 135 disposal zone in SD-8 is 7-5/8” 29.7 lb/ft L-80. The well was completed with 352 barrels of 14.5 ppg Class G lead cement and 62 barrels of 15.5 ppg Class G tail cement. The cement bond log dated 9/20/2013 (Exhibit A-9) shows a good bond across the Beluga 135 and across the upper and lower confining layers sufficient for zonal isolation. The tubing in SD-8 is isolated from the casing with two hydraulic-set isolation packers straddling the Beluga 135 interval. After setting the straddle packers, the inner annulus was successfully pressure tested to 2,000 psi for 30 minutes (6/14/2014). Following approval of this disposal application, Hilcorp will submit a sundry request to isolate the deeper Tyonek T-2 and T-83 perforations, perform an updated mechanical integrity test on the inner annulus in accordance with 20 AAC 25.412, perforate the Beluga 135 sand, and perform an injectivity test into the proposed disposal zone. 7. a statement as to the type of oil field wastes to be disposed or hydrocarbons stored, their composition, their source, the estimated maximum amounts to be disposed or stored daily, and the compatibility of fluids to be disposed or stored with the disposal or storage zone; The primary disposal fluid planned for SD-8 is formation fluid from NU and other fields in the Kenai Peninsula. Waste disposal injection may also include other fluids eligible for Class II injection. Currently, NNA 1 is the primary disposal well for NU waste. The average daily disposal volume into SD-8 will depend on whether NNA 1 remains the primary disposal well for NU. Disposal into SD-8 will only occur if additional disposal capacity is required or if NNA 1 ceases to be the primary disposal well. The average daily injection into NNA 1 during calendar year 2023 was 292 barrels per day; no slurry was disposed. The maximum daily volume to be disposed of is 3000 barrels, which corresponds to an average injection rate of approximately 2.0 BPM. This average injection rate and daily disposal volume are consistent with DIO 28 and align with the fracture modeling (detailed below) used to validate confinement of injected fluids into the proposed Beluga 135 disposal zone. Fluid samples delivered to NNA 1 for disposal were captured on five occasions in January 2024. The compositional analysis of these fluid samples is attached in Exhibit A-10. In any operation that mixes fluids from different sources, fluid compatibility – specifically as it relates to potential for developing scale in a wellbore and/or reservoir – must be considered. Hilcorp AOGCC | SD-8 UIC Class II Permit Application Hilcorp Alaska, LLC | Page 9 analyzed the scaling tendencies of NNA 1’s disposal water and water from the Beluga 135 interval in Susan Dionne 1A (“SD-1” or “SD-1A”) using the analytes shown in Table 2. Table 2: NNA 1 and SD-1A Analytes Analysis of the analytes across the seven samples confirmed that injecting NNA 1 disposal water into the Beluga 135 at SD-1A will not change or enhance the potential for scale within the wellbore or reservoir. Furthermore, Hilcorp anticipates that disposal into the Beluga 135 at SD-8 will primarily consist of produced water from nearby wells completed in the Beluga, Sterling, and Tyonek formations. To date, Hilcorp has not identified any fluid compatibility concerns from injecting similar fluids into its disposal wells across the Cook Inlet Basin. 8. the estimated average and maximum injection pressure; SD-1A penetrates the Beluga 135 at ~3,607’ TVDss, which is slightly downdip from where SD-8 penetrates the Beluga 135 at 3,597’ TVDss. In 3D space these wells are ~80’ apart in the Beluga 135. The proximity of SD-1A to SD-8 makes it a strong analogue for comparison. Exhibit A-11 is a stratigraphic cross section flattened on the Beluga 135 horizon showing nearly identical log signatures between SD-1A and SD-8. (Note: No open hole Density/Neutron logs were run when SD-1A was drilled in 1962; the cased hole Neutron log run in 2001 shows a similar signature as that seen in SD-8’s open hole Neutron log.) Not only does each well have clear markers defining the Beluga 135’s confining layers, but the overall Beluga 135 sand package is of uniform thickness across the two wells. These characteristics strongly suggest that the fluids found in the Beluga 135 at SD-1A would be analogous to those in the Beluga 135 at SD-8. On May 1, 2023, an injectivity test of the Beluga 135 sand was performed at SD-1A in accordance with Sundry 323-142. Results from that test suggest average injection pressures Analytes Units NNA-1 Sample 1 NNA-1 Sample 2 NNA-1 Sample 3 NNA-1 Sample 4 NNA-1 Sample 5 SD-1A Sample 1 SD-1A Sample 2 Density of brine at 60 deg F 1.0034 1.0056 1.0056 1.0056 1.0026 NA NA Specific Gravity (60 deg F) Brine 1.0044 1.0066 1.0066 1.0066 1.0036 NA NA Salinity ppt 5.7 8.6 8.6 8.6 4.7 0.0689*0.0726* pH 8.5 8.8 8.5 8.5 8.5 9.5 9.1 Total Dissolved Solids ppm 5350 7858 7937 7869 4583 1700 1920 Boron mg/L <1.4 <1.4 <1.4 <1.4 <1.4 <10 <10 Phosphorus mg/L <0.29 <0.29 <0.29 <0.29 <0.29 NA NA Aluminum mg/L 0.1 0.09 0.09 0.09 0.11 11 J 15.8 J Manganese mg/L 0.03 0.02 0.02 0.02 0.02 0.333 0.645 Iron mg/L 0.18 <0.13 0.17 0.15 <0.13 23.9 J 51.6 Chromium mg/L <0.02 <0.02 <0.02 <0.02 <0.02 .463 J .627 J Calcium mg/L 6.4 8.1 9.9 7.7 13 <25 16 J Barium mg/L 1.3 2.6 3.2 2.5 1.1 0.4 0.5 Magnesium mg/L 4.2 5.6 6.9 5.5 4.2 <25 <25 Strontium mg/L 0.82 1.2 1.5 1.2 0.77 NA NA Potassium mg/L 25 46 57 46 20 35 J 35.7 J Sodium mg/L 1820 2622 3174 2563 1585 613 641 Lithium mg/L 0.11 0.2 0.25 0.2 0.08 NA NA Chloride by Ion Chromatography mg/L 246 659 661 578 198 41.8 44 Sulfate mg/L <0.5 <0.5 <0.5 <0.5 <0.5 NA NA *Salinity from Chloride AOGCC | SD-8 UIC Class II Permit Application Hilcorp Alaska, LLC | Page 10 from 1800-1900 psi to achieve typical (2 BPM) injection rates. Testing at SD-1A was performed up to a maximum injection pressure of 2,026 psi. The analysis below confirms confinement of the injected fluids under all conditions tested on the SD-1A. The maximum injection pressure into the Beluga 135 at SD-8 will be below 2,025 psi to stay within the limits of tested parameters for this disposal interval. 9. evidence to support a commission finding that the proposed disposal or storage operation will not initiate or propagate fractures through the confining zones that might enable the oil field wastes or stored hydrocarbons to enter freshwater strata; As part of the injectivity test performed at SD-1A on May 1, 2023, Hilcorp also performed an injection step rate test to evaluate injectivity of the Beluga 135. As discussed previously, the results of this test should be analogous to the injectivity into the Beluga 135 disposal zone at SD-8. Further, the fluid injected during the injectivity test was produced water from offset wells in NU, which has similar fluid properties to the disposal fluids envisioned in this application. To understand the potential for fracture propagation in the Beluga 135, Hilcorp analyzed the injectivity data from SD-1A using StimPlan software. Figure 1 below shows the injection rate and pressure data for the duration of the injectivity test with comments on how Hilcorp analyzed the results. Figure 1: SD-1A Injectivity and Step Rate Test Data (May 1, 2023) In the initial injection period, the goal is to identify a closure pressure. Figure 2 plots the pressure decline curve for the first injection cycle pumped at a rate of 2.2 BPM. AOGCC | SD-8 UIC Class II Permit Application Hilcorp Alaska, LLC | Page 11 Figure 2: SD-1A ISIP Identification – Initial Injection Cycle The ISIP is identified as the pressure at which the treating pressure curve changes from flat to steeply downward with a corresponding drop in treating rate. The injectivity data at SD-1A yields an interpretation of ISIP at 1,755 psi, as marked by the green dot in Figure 2. This measurement represents the wellbore pressure immediately after pumping stops, quantifying the maximum bottomhole treating pressure free from the influence of fluid friction. Because the ISIP at SD-1A during the initial injection cycle is very close to the final pump pressure before breakover, there are minimal frictional effects present in the wellbore at this time. This is a clear indication that no fracture occurred during this injection cycle. After analyzing the ISIP from the initial injection cycle, the log-log plot in Figure 3 of derivative pressure and derivative time is used to define the various flow regimes that occurred during the injection cycle. In this plot, the pink dots represent pressure change relative to ISIP (dp) and the blue line represents the derivative of the pressure decline curve over time [h(dT)/dT]. AOGCC | SD-8 UIC Class II Permit Application Hilcorp Alaska, LLC | Page 12 Figure 3: SD-1A Derivative Pressure and Derivative Time Log-Log Plot – Initial Injection Cycle AOGCC | SD-8 UIC Class II Permit Application Hilcorp Alaska, LLC | Page 13 For any pressure decline following an injection period that exceeds fracture gradient (i.e. when fracturing has occurred), three flow regimes should be present in the same consistent order: a. Fracture Linear Flow – The period where fluid exits the wellbore into an open fracture in the formation. During this period, the pressure behavior is dominated by a formation leak-off coefficient (Ct). On a log-log plot, this appears as a 0.5 slope (black line) through the derivative pressure curve (blue line) and where dp (pink dots) is roughly twice the value of the derivative. This flow regime only exists when injection pressures exceed fracture gradient. b. Formation Linear Flow or Pseudo Linear Flow – The flow regime that occurs just before pseudo radial flow, provided sufficient volumes have been pumped at a high enough rate. During this flow regime, any fractures are closed, and the pressure decline is dominated by a relatively high pressure differential as fluids leave the near wellbore via the perforations. This is observed as a 0.5 slope (black line) of the derivative (blue line). c. Pseudo-Radial Flow – This flow regime is always present following any injection period. In this flow regime, pressure dissipates radially from the near wellbore region and approaches reservoir pressure. This is observed on the log-log plot as a negative slope of the derivative curve (blue line). Any injection cycle will conclude with pseudo-radial flow. Given that an injection cycle must conclude with pseudo-radial flow, the analysis of the SD- 1A injection cycle can be worked backwards along the x-axis of the log-log plot. Figure 3 shows the pseudo-radial flow regime at all times greater than dt = 2.0. Because formation linear flow must precede pseudo-radial flow, the 0.5 slope prior to dt = 2.0 is formation linear flow. Figure 3 captures this flow regime during the period that the 0.5 slope curve (black line) overlays the derivative curve (blue line). Prior to the formation linear flow regime, the fracture linear flow regime is indicated by an inflection of the derivative curve (blue line) with another 0.5 slope. However, in the SD-1A injectivity data, these earlier conditions do not exist. Therefore, analysis of the log-log plot suggests no fracturing occurred during this injection cycle. Analysis of Figures 2 and 3 support the conclusion that no fractures were propagated into the Beluga 135 formation while injecting produced water at 2.2 BPM into SD-1A. For the step rate test analysis (Figure 1), the first injection step is excluded because pressure had not stabilized. A more detailed view of SD-1A’s step rate test data is below in Figure 4, with the initial step rate cycle circled in green. AOGCC | SD-8 UIC Class II Permit Application Hilcorp Alaska, LLC | Page 14 Figure 4: SD-1A Step Rate Test (May 1, 2023) The individual treating pressure and rate points in Figure 4 are then used to create the cross- plot of treating pressure and injection rate shown in Figure 5. Figure 5: SD-1A Treating Pressure and Injection Rate Cross-Plot When fractures propagate during injection, Figure 5 should show two distinct slopes as a function of increasing injection rate: one slope covering the period of lower-rate injection prior AOGCC | SD-8 UIC Class II Permit Application Hilcorp Alaska, LLC | Page 15 to fracture formation and another slope when the formation has broken down and is fractured under a higher injection rate In the SD-1A data, a second slope is not observed at rates up to 4 BPM, suggesting that the Beluga 135 formation will not fracture at injection rates below 4 BPM. Not only is this behavior consistent with Hilcorp’s experience injecting into formations with similar permeability across its Alaska operations, but the expected injection rate into the Beluga 135 interval at SD-8 is ~2 BPM, far below the 4 BPM injection rate at SD-1A. Finally, the same analysis techniques used to determine fracture initiation at 4 BPM during SD-1A’s initial injection cycle can be applied to the last injection cycle. Figure 6 shows the ISIP plot for the final 4 BPM injection cycle. Figure 6: SD-1A ISIP Identification – Final Injection Cycle In this final injection cycle, the ISIP (green dot) is observed at a similar pressure as the ISIP from the initial injection cycle (Figure 2). Once again, this observed pressure is near the final pump pressure, aligning well with the ISIP of 1,755 psi determined in the first injection cycle. While Figure 3 discussed previously shows the log-log derivative plot for the initial injection cycle, Figure 7 below shows that same plot for SD-1A’s final injection cycle. The interpreted results of this injection cycle are consistent with those of the initial cycle: While both pseudo- radial flow and formation linear flow are observed, there is no indication of fracture linear flow regime and thus no indication of fracture propagation during the final injection cycle. AOGCC | SD-8 UIC Class II Permit Application Hilcorp Alaska, LLC | Page 16 Figure 7: SD-1A Derivative Pressure and Derivative Time Log-Log Plot – Final Injection Cycle Analysis of Figures 6 and 7 supports the conclusion that fractures did not propagate into the Beluga 135 at SD-1A while injecting produced water at the maximum injection rate of 4 BPM. Based on the combined analysis of the injectivity test and step rate test data at SD-1A, there are no indications of Beluga 135 fracturing with produced water injection at 4 BPM. Given the analogous disposal interval and fluid properties of the proposed disposal activities for SD-8 as compared to recent injectivity testing at SD-1A, Hilcorp is confident that no fractures will propagate in the Beluga 135 disposal zone while injecting into SD-8 at rates of 2 BPM or less. Additionally, given the lower permeability and higher stress in the confining coals above and below the Beluga 135 disposal zone, it is even less likely that fractures will propagate through the confining layers due to the proposed disposal activities at SD-8. 10. a standard laboratory water analysis, or the results of another method acceptable to the commission, to determine the quality of the water within the formation into which disposal or storage is proposed; As part of the work described in Sundry 323-142, fluid samples were collected from the Beluga 135 in SD-1A. Laboratory analysis from that sample collection is attached as Exhibit A-10. Analyte concentrations of those samples are also summarized above in Table 2. AOGCC | SD-8 UIC Class II Permit Application Hilcorp Alaska, LLC | Page 17 11. a reference to any applicable freshwater exemption issued in accordance with 20 AAC 25.440; and Attached hereto as Exhibit A-12 is the Aquifer Exemption Request associated with this disposal application. 12. a report on the mechanical condition of each well that has penetrated the disposal or storage zone within a one-quarter mile radius of a disposal or storage well. SD-1A is the only well within a one-quarter mile radius of SD-8 that penetrates the proposed Beluga 135 disposal zone. Permitted under the name Ninilchik No. 1 and spudded on July 20, 1962, SD-1A was shortly thereafter abandoned before being re-entered under the new well name McCoy Prospect No. 1. In September 2001, Marathon renamed the well Susan Dionne 1 (SD-1) and re-entered it in December 2001. A total depth of 7,430’ MD (7,294 TVD) was reached on December 16, 2001, when SD-1 was renamed yet again to reflect its recompletion, this time to Susan Dionne 1A (SD-1A). (Note: Due to SD-1/1A’s evolving names, some inconsistency with the log titles exists.) SD-1A’s 20” conductor was set at 193’ MD (196’ TVD) (hole size 26”) and cemented with 600 sacks of Class G cement. Its 13-3/8” surface casing was set at 2,046’ MD (2,045’ TVD) (hole size 18 5/8”) and cemented with 1,800 sacks of Class G cement. The 9-5/8” intermediate casing ends at 7,430’ MD (7,316’ TVD) (hole size 12-1/4”) and cemented with 2,800 sacks of Class G cement. SD-1A’s intermediate casing USIT log run on December 17, 2001 to a top depth of 2,950’ MD shows corrosion-induced loss of pipe wall thickness over a portion of the 40 lb/ft casing starting from ~3,600’ MD to the crossover at ~5,050’ MD. The deeper 47 lb/ft casing is in good condition with minimal wall loss. The USIT log shows consistent cement coverage across the proposed Beluga 135 disposal zone and the confining layers up to a depth of ~3,300’ MD. Above this point the cement bond degrades and pockets of a liquid filled micro-annulus start to develop. Following the December 2001 recomplete to SD-1A, a 4-1/2” production casing was installed to isolate all open Beluga 135 perforations. This casing was set at 7,422’ MD (7,308 TVD) (hole size 8.681”) and cemented with 445 sacks of Class G lead cement (12.5 ppg) and 326 sacks of Class G tail cement (15.7 ppg). During the cement job, the plug was bumped and the floats held. The radial CBL of this pipe dated May 23, 2013 shows consistent cement bond up to ~3,000’ MD. Gas production from the Tyonek reservoir was attempted, but unsuccessful; all Tyonek perforations were plugged back with a series of cast-iron bridge plugs up to 4,890’ MD. In April 2021, 20’ MD of Beluga 135 perforations were added (3,790-3,810’ MD) under Sundry 323-142 as a means for gathering the data necessary (i.e. formation fluid samples and an injectivity test) to evaluate the efficacy of using SD-8 for Class II disposal. The location of SD-1A is illustrated in Exhibit A-2. Wellbore schematic for SD-1A; SD-1A’s radial cement bond log of the 4-1/2” casing; and SD-1A’s USIT log of the 9-5/8” casing are provided as Exhibits A-13, A-14, and A-15, respectively. AOGCC | SD-8 UIC Class II Permit Application Hilcorp Alaska, LLC | Page 18 Exhibit A-1: Ninilchik Unit Regional Map AOGCC | SD-8 UIC Class II Permit Application Hilcorp Alaska, LLC | Page 19 Exhibit A-2: Susan Dionne Area of Review AOGCC | SD-8 UIC Class II Permit Application Hilcorp Alaska, LLC | Page 20 Exhibit A-3: Susan Dionne 8 Wellbore Schematic Submitted under separate cover via email dated 5/15/2024 _____________________________________________________________________________________ Updated By CRR 7-27-21 SCHEMATIC Ninilchik Unit Well: SD 08 PTD: 213-051 API: 50-133-20611-00-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 16" Conductor 109 / X-56 / N/A 15” Surf 80’ 10-3/4” Surface 45.5 / L-80 / Butt 9.95” Surf 2,568' 7-5/8" Intermedia te 29.7 / L-80 / BTC 6.875” Surf 5,659' 29.7 / P-110HC / BTC 6.875” 5,659’ 9,310’ 5" Liner 15 / L-80 / DWC/C/HT 4.408” 8,838’ 11,918' TUBING DETAIL 4-1/2” Tubing 12.6 / L-80 (June-2014) 3.958” Surface 4,079’ 10-3/4” Cement Job: 13-1/2” hole. 270bbls of 12# Class A lead, and 86bbls of 15.8# Class G tail. No losses during job. 100 bbls cement returned to surface. 7-5/8” Cement Job: 9-7/8” hole. 352bbls of 14.5# Class G lead, and 62bbls of 15.5# Class G tail. Had losses during job. No spacer nor cement returned to surface. Plug did not bump. Cement inside casing found at 8986’ MD (14bbls). TOC at 1,550’ MD from 9/20/13 CBL 5” Cement Job: 6-3/4” hole. Pumped 123bbls of 15.3#s of 15.5# Class G tail. Did see cement circulated to surface. TOC at 9,330’ MD from 9/20/13 CBL. JEWELRY DETAIL No Top Depth ID Item 1A 176’ 3.813” SSSV hydraulic landing nipple (SLB BP-6i) 1B 176’ 2.125” Wireline SSSV: WRDP-2 (SLB) 2 3,785’ 4.000” 7-5/8” Hydraulic Isolation Packer 3 4,055’ 4.000” 7-5/8” Hydraulic Isolation Packer 4 4,069’ 3.725” 4-1/2” XN Nipple 5 4,079’ 3.958” 4-1/2” WLEG 6 7,442’ N/A 2.13” Possiset at 7442’. ToC at ~7431’ (3/26/15) 7 7,738’ N/A CIBP w/ TOC @ ~7,713’ (6/4/14) 8 10,595’ N/A CIBP w/ cement (10/18/13) 9 11,000’ N/A CIBP 10 11,162’ N/A CIBP 11 11,260’ N/A CIBP 12 11,489’ N/A CIBP PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Perf’d Status Beluga 135 3,932’ 3,952’ 3,787’ 3,805’ 20 02/04/14 Isolated (June-2014) T-2 4,130’ 4,144’ 3,971’ 3,984’ 14 08/20/18 Open T-83 7,280’ 7,300’ 6,945’ 6,963’ 6 06/25/14 Open 7,295’ 7,307’ 6,959’ 6,970’ 6 06/17/14 Open T-90 7,467’ 7,475’ 7,122’ 7,130’ 6 06/17/14 Isolated (3/26/15) 7,493’ 7,502’ 7,147’ 7,156’ 8 06/17/14 Isolated (3/26/15) T-140 8,046’ 8,076’ 7,675’ 7,704’ 30 02/13/14 Isolated (6/4/14) 8,054’ 8,076’ 7,683’ 7,712’ 30 02/12/14 Isolated (6/4/14) G Zone 10,638’ 10,688’ 10,136’ 10,184’ 50 10/15/13 Isolated (10/18/13) 10,698’ 10,730’ 10,193’ 10,224’ 32 10/15/13 Isolated (10/18/13) Hemlock 3 11,042’ 11,058’ 10,521’ 10,537’ 16 10/4&11/13 Isolated WF 1 11,194’ 11,212’ 10,666’ 10,683’ 18 9/30/13 Isolated WF 2 & 3 11,280’ 11,350’ 10,749’ 10,816’ 70 9/26/13 Isolated WF 4C 11,535’ 11,565’ 10,992’ 11,021’ 30 9/22/13 Isolated WF 4E 11,650’ 11,713’ 11,102’ 11,161’ 63 9/22/13 Isolated WF 4F 11,779’ 11,806’ 11,223’ 11,249’ 27 9/22/13 Isolated AOGCC | SD-8 UIC Class II Permit Application Hilcorp Alaska, LLC | Page 21 Exhibit A-4: Landowner Information Submitted under separate cover via email dated 5/15/2024 PARCEL ID SITE ADDRESS OWNER ADDRESS CITY, STATE, ZIP ACREAGE LEGAL DESCRIPTION PLAT OWNER TYPE PROPERTY USAGE 15701003 <Null>BACHNER BEA PO BOX 81205 FAIRBANKS, AK 99708 10.06 T 1S R 13W SEC 6 SEWARD MERIDIAN HM GOVT LOT 1 <Null>Private Accessory Building 15701010 <Null>KITTY COMPANY PO BOX 39677 NINILCHIK, AK 99639 5 T 1S R 13W SEC 5 SEWARD MERIDIAN HM N1/2 NW1/4 SW1/4 SW1/4 <Null>Private Vacant 15701013 11601 STERLING HWY AURORA COMMUNICATIONS INTERNATIONAL INC PO BOX 6671 SANTA BARBARA, CA 93160 150.77 T 1S R 13W SEC 7 SEWARD MERIDIAN HM GOVT LOTS 1 & 2 & SW1/4 NE1/4 <Null>Private Commercial 15701016 <Null>GAIN HENRY G & F EUGENIA 204 SECO DR PORTLAND, TX 78374 27 T 1S R 13W SEC 8 SEWARD MERIDIAN HM NW1/4 NW1/4 LYING WEST OF THE STERLING HWY <Null>Private Vacant 15701042 <Null>NORMAN STEPHEN ANTHONY 1313 N WILLIAMS ST APT 1603 DENVER, CO 80218 19.9 T 1S R 13W SEC 7 SEWARD MERIDIAN HM N1/2 SE1/4 NE1/4 <Null>Private Vacant 15701072 <Null>BULLARD TOM & KAREN 8429 HEATHER CIR ANCHORAGE, AK 99502 5 T 1S R 13W SEC 6 SEWARD MERIDIAN HM - PW PTN OF GL 2 BEGIN @S1/16 CORNER COMMON TO SEC 5&6; TH S 0 DEG 08'E 420 FT; TH WEST 330 FT; TH N42 DEG 00'W 565 FT; TH E 707.1 FT TO POB PER PW RES 99-25 REC @291/688 <Null>Private Residential 15701073 10869 MATT ST HILCORP ALASKA LLC 1111 TRAVIS ST HOUSTON, TX 77002 39.4 T 1S R 13W SEC 6 SEWARD MERIDIAN HM - PW PTN OF GL 2 BEGIN @SEC CORNER COMMON TO SECS 5,6,7&8 TH W 2165 FT+/- TO MHW COOK INLET; TH ALONG MHW N47 DEG 15'E 977 FT+/-; TH N44 DEG 26'E 920 FT+/-; TH E 93.4 FT; TH S42 DEG 00'E 565.0 FT; TH E 330.0 FT; TH S 0 DEG 08'E 900.0 FT+/- TO POB PER PW RES 99-25 REC @291/688 <Null>Private Industrial 15701074 <Null>BUTLER KIM V PO BOX 877589 WASILLA, AK 99687 40 T 1S R 13W SEC 7 SEWARD MERIDIAN HM NE1/4 NE1/4 <Null>Private Vacant 15701076 10725 STERLING HWY BURTON JAMES G & IMELDA M PO BOX 39677 NINILCHIK, AK 99639 8.73 T 1S R 13W SEC 5 SEWARD MERIDIAN HM 2000006 DIONNE SUB TRACT A http://www.borough.kenai.ak.us/components/c om_papyruslist/document.php?d=1397115 Private Residential 15701077 <Null>BERGER JEFF F PO BOX 39229 NINILCHIK, AK 99639 5.48 T 1S R 13W SEC 5 SEWARD MERIDIAN HM 2000006 DIONNE SUB TRACT B http://www.borough.kenai.ak.us/components/c om_papyruslist/document.php?d=1397115 Private Vacant 15701078 10985 STERLING HWY WIEGMANN ERIC CLIFFORD & FLORENCE CHARLENE GRACE PO BOX 39740 NINILCHIK, AK 99639 4.71 T 1S R 13W SEC 5 SEWARD MERIDIAN HM 2000006 DIONNE SUB TRACT C http://www.borough.kenai.ak.us/components/c om_papyruslist/document.php?d=1397115 Private Residential 15701082 10860 MATT ST LINK RICHARD A & LOURDES L & MATTHEW PO BOX 3178 SOLDOTNA, AK 99669 1.96 T 1S R 13W SEC 5 SEWARD MERIDIAN HM 2005022 DIONNE SUB LYNX ADDN LOT 1D http://www.borough.kenai.ak.us/components/c om_papyruslist/document.php?d=2255562 Private Residential 15721040 <Null>TURNER HILERY DEAN PO BOX 15366 FRITZ CREEK, AK 99603 2.39 T 1S R 13W SEC 5 SEWARD MERIDIAN HM 0770046 ILIAMNA MEADOWS SUB LOT 15 http://www.borough.kenai.ak.us/components/c om_papyruslist/document.php?d=1398936 Private Vacant ------Waters of COOK INLET STATE OF ALASKA -- AOGCC | SD-8 UIC Class II Permit Application Hilcorp Alaska, LLC | Page 22 Exhibit A-5: Public Announcement Affidavit Submitted under separate cover via email dated 5/15/2024 AOGCC | SD-8 UIC Class II Permit Application Hilcorp Alaska, LLC | Page 23 Exhibit A-6: Beluga 135 Regional Cross Section (A-A’) Submitted under separate cover via email dated 5/15/2024 AOGCC | SD-8 UIC Class II Permit Application Hilcorp Alaska, LLC | Page 24 Exhibit A-7: Beluga 135 Structure Map Submitted under separate cover via email dated 5/15/2024 -3900-3900-39003900-3650-3650 -3650-3650-3650-3 6 5 0 -3650 -3650 -3650 -3650-3650-3650 -36 5 0 -3650 -3650 -3650 -3950-39500-360 0 -3600 -3600-3600-3600-36 0 0-3600 -3600 -3600-3600-3 6 0 0 -36 0 0 -3600 -3600 -4050 -4050 -3550 -3550 -3550-3550-3 5 5 0 -3550 -3550 -3550-3550-3 5 5 0 -3550 -3500 -3500-3500-3500 -3500 -3500 -3500 -350 0-4000-4000 -3850-3850-3850-3850-3800 -380 0 - 3 8 0 0 -3800-3800-3800-3800-3800-3750 -3750 -3750 -3750 -3750-3750 -3750-3750-3750-3750 700-3700 -3700-3700-3700-3700-3700 -3700-3700-3700-3700- 3 7 0 0 -370 0 -3700 -3 7 00 4250 -4200 -4150 -4100-4100 -4350 -3450 -3450 -3450 -3450 -3450-3450-3400 Dionne 1A Dionne 2 Dionne 3 Dionne 4 Dionne 5 Dionne 6 Dionne 7 Dionne 8 Kalotsa 1 Kalotsa 2 Kalotsa 3 Kalotsa 4 Kalotsa 6 Paxton 1 Paxton 2 Paxton 3 Paxton 4 Paxton 8 Paxton 10 Paxton 6 Paxton 11 Kalotsa 7 Kalotsa 8 202400 203200 204000 204800 205600 206400 207200 208000 208800 209600 210400 211200 212000 212800 213600 214400 215200 202400 203200 204000 204800 205600 206400 207200 208000 208800 209600 210400 211200 212000 212800 213600 214400 2152002229600223040022312002232000223280022336002234400223520022360002236800223760022384002239200224000022408002241600222960022304002231200223200022328002233600223440022352002236000223680022376002238400223920022400002240800224160005001000150020002500ftUS 1:11742 Hilcorp: Kenai Team Ninilchik: Paxton/Kalotsa/Susan Dionne Beluga 135 Structure Susan Dionne 8 Disposal Well Contour inc 50 Date 04/02/2024 Sean Wagner Top Beluga 135: -4400.00-4350.00-4300.00-4250.00-4200.00-4150.00-4100.00-4050.00-4000.00-3950.00-3900.00-3850.00-3800.00-3750.00-3700.00-3650.00-3600.00-3550.00-3500.00-3450.00-3400.00-3350.00 TVDss depth [ft] Top disposal zone in Susan Dionne 8 A A' AOGCC | SD-8 UIC Class II Permit Application Hilcorp Alaska, LLC | Page 25 Exhibit A-8: Beluga 135 in SD-8 Type Log Submitted under separate cover via email dated 5/15/2024 AOGCC | SD-8 UIC Class II Permit Application Hilcorp Alaska, LLC | Page 26 EXHIBIT A-9: Susan Dionne 8 Cement Bond Log Reference AOGCC file T# 23575 AOGCC | SD-8 UIC Class II Permit Application Hilcorp Alaska, LLC | Page 27 Exhibit A-10: NNA 1 Fluid Sample Compositional Analysis Submitted under separate cover via email dated 5/15/2024 GPB LABORATORY REPORT 907-659-5654 PBILabSupervisor@hilcorp.com Sample Facility: Sample ID Number:PE00026 Collection Date/Time: Sample Point: Sample Description: Well Number: NINILCHIK Sample #1 NNA 1 Injection Well Results Analysis Name Result Units Sample Information Sample Type:Produced Water 01/28/2024, 12:00 AM Meter Number: Density of brine at 60 deg F 1.0034 Specific Gravity (60 deg F) Brine 1.0044 Salinity 5.7 ppt pH 8.5 Total Dissolved Solids 5350 ppm Boron <1.4 mg/L Phosphorus <0.29 mg/L Aluminum 0.10 mg/L Manganese 0.03 mg/L Iron 0.18 mg/L Chromium <0.02 mg/L Calcium 6.4 mg/L Barium 1.3 mg/L Magnesium 4.2 mg/L Strontium 0.82 mg/L Potassium 25 mg/L Sodium 1820 mg/L Lithium 0.11 mg/L Chloride by Ion Chromatography 246 mg/L Sulfate <0.5 mg/L Analyzed by: BRISR5, MO10579 Sample Comment: Report Date: 2/20/2024, 4:42:48PM GPB LABORATORY REPORT 907-659-5654 PBILabSupervisor@hilcorp.com Sample Facility: Sample ID Number:PE00027 Collection Date/Time: Sample Point: Sample Description: Well Number: NINILCHIK Sample #2 NNA 1 Injection Well Results Analysis Name Result Units Sample Information Sample Type:Produced Water 01/24/2024, 12:00 AM Meter Number: Density of brine at 60 deg F 1.0056 Specific Gravity (60 deg F) Brine 1.0066 Salinity 8.6 ppt pH 8.8 Total Dissolved Solids 7858 ppm Boron <1.4 mg/L Phosphorus <0.29 mg/L Aluminum 0.09 mg/L Manganese 0.02 mg/L Iron <0.13 mg/L Chromium <0.02 mg/L Calcium 8.1 mg/L Barium 2.6 mg/L Magnesium 5.6 mg/L Strontium 1.2 mg/L Potassium 46 mg/L Sodium 2622 mg/L Lithium 0.20 mg/L Chloride by Ion Chromatography 659 mg/L Sulfate <0.5 mg/L Analyzed by: BRISR5, MO10579 Sample Comment: Report Date: 2/20/2024, 4:42:48PM GPB LABORATORY REPORT 907-659-5654 PBILabSupervisor@hilcorp.com Sample Facility: Sample ID Number:PE00028 Collection Date/Time: Sample Point: Sample Description: Well Number: NINILCHIK Sample #3 NNA 1 Injection Well Results Analysis Name Result Units Sample Information Sample Type:Produced Water 01/28/2024, 12:00 AM Meter Number: Density of brine at 60 deg F 1.0056 Specific Gravity (60 deg F) Brine 1.0066 Salinity 8.6 ppt pH 8.5 Total Dissolved Solids 7937 ppm Boron <1.4 mg/L Phosphorus <0.29 mg/L Aluminum 0.09 mg/L Manganese 0.02 mg/L Iron 0.17 mg/L Chromium <0.02 mg/L Calcium 9.9 mg/L Barium 3.2 mg/L Magnesium 6.9 mg/L Strontium 1.5 mg/L Potassium 57 mg/L Sodium 3174 mg/L Lithium 0.25 mg/L Chloride by Ion Chromatography 661 mg/L Sulfate <0.5 mg/L Analyzed by: BRISR5, MO10579 Sample Comment: Report Date: 2/20/2024, 4:42:48PM GPB LABORATORY REPORT 907-659-5654 PBILabSupervisor@hilcorp.com Sample Facility: Sample ID Number:PE00029 Collection Date/Time: Sample Point: Sample Description: Well Number: NINILCHIK Sample #4 NNA 1 Injection Well Results Analysis Name Result Units Sample Information Sample Type:Produced Water 01/29/2024, 12:00 AM Meter Number: Density of brine at 60 deg F 1.0056 Specific Gravity (60 deg F) Brine 1.0066 Salinity 8.6 ppt pH 8.5 Total Dissolved Solids 7869 ppm Boron <1.4 mg/L Phosphorus <0.29 mg/L Aluminum 0.09 mg/L Manganese 0.02 mg/L Iron 0.15 mg/L Chromium <0.02 mg/L Calcium 7.7 mg/L Barium 2.5 mg/L Magnesium 5.5 mg/L Strontium 1.2 mg/L Potassium 46 mg/L Sodium 2563 mg/L Lithium 0.20 mg/L Chloride by Ion Chromatography 578 mg/L Sulfate <0.5 mg/L Analyzed by: BRISR5, MO10579 Sample Comment: Report Date: 2/20/2024, 4:42:48PM GPB LABORATORY REPORT 907-659-5654 PBILabSupervisor@hilcorp.com Sample Facility: Sample ID Number:PE00030 Collection Date/Time: Sample Point: Sample Description: Well Number: NINILCHIK Sample #5 NNA 1 Injection Well Results Analysis Name Result Units Sample Information Sample Type:Produced Water 01/29/2024, 12:00 AM Meter Number: Density of brine at 60 deg F 1.0026 Specific Gravity (60 deg F) Brine 1.0036 Salinity 4.7 ppt pH 8.5 Total Dissolved Solids 4583 ppm Boron <1.4 mg/L Phosphorus <0.29 mg/L Aluminum 0.11 mg/L Manganese 0.02 mg/L Iron <0.13 mg/L Chromium <0.02 mg/L Calcium 13 mg/L Barium 1.1 mg/L Magnesium 4.2 mg/L Strontium 0.77 mg/L Potassium 20 mg/L Sodium 1585 mg/L Lithium 0.08 mg/L Chloride by Ion Chromatography 198 mg/L Sulfate <0.5 mg/L Analyzed by: BRISR5, MO10579 Sample Comment: Report Date: 2/20/2024, 4:42:48PM AOGCC | SD-8 UIC Class II Permit Application Hilcorp Alaska, LLC | Page 28 Exhibit A-11: SD-8 and SD-1A Beluga 135 Stratigraphic Cross Section Submitted under separate cover via email dated 5/15/2024 AOGCC | SD-8 UIC Class II Permit Application Hilcorp Alaska, LLC | Page 29 Exhibit A-12: Aquifer Exemption Request Submitted under separate cover via email dated 5/15/2024 AOGCC | SD-8 UIC Class II Permit Application Hilcorp Alaska, LLC | Page 30 Exhibit A-13: SD-01A Schematic (04-30-21) Submitted under separate cover via email dated 5/15/2024 _____________________________________________________________________________________ Updated by DMA 04-30-21 SCHEMATIC Well: SD 1A PTD: 185-208 API: 50-133-10002-01-00 CASING DETAIL Size Type Wt/ Grade ID Top Btm 20" Conductor 59 & 78.6 / H-20SS N/A Surf 193' 13-3/8" Surface 54.5 & 61 / J-55 12.515 Surf 2,046' 9-5/8" (1962) Intermediate 40 & 47 / N-80 8.681 Surf 7,430' 4-1/2" (12/21/01) Production 12.6 / L-80 3.958 Surf 7,422' JEWELRY DETAIL No Depth (MD) Depth (TVD) ID OD Item 1 2,286' 2,285’ 1/4" .049" wall Chemical injection line / mandrel w/ check valve 2 4,890’ 4,845’ CIBP set 4/27/21 3 5,780' 5,706’ CIBP set 2/26/03 4 7,050' 6,944’ CIBP set 2/20/02 5 7,230' 7,120’ CIBP set 2/9/02 6 7,333' 7,221’ CIBP 7 7,422' 7,308’ Plug - Bottom @ 7,450' 8 10,350' 10,196’ Plug - Bottom @ 10,450' 9 10,600' 10,443’ Plug - Bottom @ 10,700' Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Perf Date Status BEL-135 3,790' 3,810' 3,777' 3,797' 40’ 4/27/21 Open BEL_135 3,761' 3,762' 3,748' 3,749' 1' 11/29/62 Squeezed (1962) BEL_135 3,776' 3,786' 3,763' 3,772' 10' 11/30/62 Isolated behind 4-1/2” 12/21/01 BEL_135 3,824' 3,825' 3,810' 3,811' 1' 11/29/62 Squeezed (1962) T-12 4,912' 4,932' 4,866' 4,885' 20' 2/25/2003 Plugged 4/27/21 T-12 4,912' 4,932' 4,866' 4,885' 20' 2/26/2003 Plugged 4/27/21 T-65 6,758' 6,780' 6,660' 6,681' 22' 2/20/02 Plugged 2/26/03 T-67 6,846' 6,876' 6,746' 6,775' 30' 2/20/02 Plugged 2/26/03 T-83 7,070' 7,108' 6,964' 7,001' 38' 2/9/02 Plugged 2/20/02 T-90 7,235' 7,320' 7,125' 7,208' 85' Plugged 2/9/02 T-90 7,245' 7,270' 7,135’ 7,160' 25' Plugged 2/9/02 T-90 7,287' 7,312' 7,176' 7,200' 25' Plugged 2/9/02 OPEN HOLE / CEMENT DETAIL 20" 26" hole Cmt w/600sks Type 1 13-3/8" 18-5/8" hole Cmt w/ 1,800 sks of Type 1 cmt 9-5/8" 12-1/4" hole Cmt w/ 2,800 sks of cmt. 12/17/01 USIT and VDL show cement up to at least 3000’ MD (didn’t log any higher) 4-1/2" 8-1/2" hole Cmt w/ 445 sks (165 bbls) of Class G @ 12.5 ppg, & 326 sks (69 bbls) of Class G @ 15.7 ppg, Class G. Floats held. ToC at 2980’ MD per 5/23/13 CBL AOGCC | SD-8 UIC Class II Permit Application Hilcorp Alaska, LLC | Page 31 Exhibit A-14: SD-1A Radial CBL Transmittal # T20240507, Item #2: RADIAL CEMENT BOND LOG (RCBL) 05/23/2013 AOGCC | SD-8 UIC Class II Permit Application Hilcorp Alaska, LLC | Page 32 Exhibit A-15: SD-1A USIT Transmittal # T20240507, Item #1: ULTRA SONIC IMAGING TOOL (USIT) 12/16/2001 BEL_135 BEL_134 BEL_132 BEL_120 Beluga 136 T-3 Coal BEL_131 T-2 BEL_115 BEL_133 BEL_110 UNDEFInactiveUNDEFUNDEFActive 3303.5 3854.6 3350 3400 3450 3500 3550 3600 3650 3700 3750 3800 3578.6 4176.3 3600 3650 3700 3750 3800 3850 3900 3950 4000 4050 4100 4150 UNDEFActive UNDEFUNDEF3313.2 3864.4 3350 3400 3450 3500 3550 3600 3650 3700 3750 3800 3850 3474.1 4035.9 3500 3550 3600 3650 3700 3750 3800 3850 3900 3950 4000 BEL_135 BEL_134 BEL_132 BEL_120 Beluga 136 T-3 Coal BEL_131 T-2 BEL_115 BEL_133 BEL_110 1640 ftUSDionne 8 [SSTVD] Spud date: 07/10/2013 Operator: Hilcorp Alaska, LLC TD (MD): 12130.0 ft TD (TVDSS): 11396.3 ft SSTVD 1:350 Perforation_Log 30.00 100.00gAPI GR Color fill MD 2.0000 ohm.m 200.0000 RESM 2 200ohm.m RESS 2 200ohm.m RESD 15 ohm 8 ohm 0.60 0.00ft3/ft3 NPHI 135.00 54.00us/ft DTC 1.65 2.65g/cm3 RHOB Color fill Color fill Color fill Color fill Dionne 1A [SSTVD] Spud date: 07/20/1962 Operator: Union Oil Company of California TD (MD): 14990.0 ft TD (TVDSS): 14672.3 ft SSTVD 1:350 Perforation_Log 30.00 100.00gAPI GR Color fill MD 2 200ohm.m RESS 2 200ohm.m RESD 15 ohm 8 ohm 0.70 0.20ft3/ft3 TPHI 135.00 54.00us/ft DTC Color fill BEL_98 BEL_93 BEL_135 BEL_134 BEL_132 BEL_120 BEL_100 BEL_95 BEL_94 Beluga 136 T-3 Coal BEL_131 BEL_99B BEL_99A BEL_99 T-2 BEL_96 BEL_115 BEL_133 BEL_110 BEL_97 BEL_98 BEL_93 BEL_135 BEL_134 BEL_132 BEL_120 BEL_100 BEL_95 BEL_94 Beluga 136 T-3 Coal BEL_131 BEL_99B BEL_99A BEL_99 T-2 BEL_96 BEL_115 BEL_133 BEL_110 BEL_97 3021 3979 3050 3100 3150 3200 3250 3300 3350 3400 3450 3500 3550 3600 3650 3700 3750 3800 3850 3900 3950 5527.6 6853.6 5600 5650 5700 5750 5800 5850 5900 5950 6000 6050 6100 6150 6200 6250 6300 6350 6400 6450 6500 6550 6600 6650 6700 6750 6800 BEL_98 BEL_135 BEL_134 BEL_132 BEL_120 BEL_100 BEL_95 Beluga 136 T-3 Coal T-5A BEL_131 BEL_99B BEL_99A BEL_99 T-2 BEL_96 BEL_115 BEL_133 T-4 BEL_110 BEL_97 T-5 3021 3979 3050 3100 3150 3200 3250 3300 3350 3400 3450 3500 3550 3600 3650 3700 3750 3800 3850 3900 3950 3268.5 4309.1 3300 3350 3400 3450 3500 3550 3600 3650 3700 3750 3800 3850 3900 3950 4000 4050 4100 4150 4200 4250 BEL_98 T-5B BEL_135 BEL_134 BEL_132 BEL_120 BEL_100 Beluga 136 T-3 Coal T-5A BEL_131 BEL_99B BEL_99A BEL_99 T-2 BEL_96 BEL_115 BEL_133 T-4 BEL_110 BEL_97 T-5 3021 3979 3050 3100 3150 3200 3250 3300 3350 3400 3450 3500 3550 3600 3650 3700 3750 3800 3850 3900 3950 4741.4 5746.8 4800 4850 4900 4950 5000 5050 5100 5150 5200 5250 5300 5350 5400 5450 5500 5550 5600 5650 5700 BEL_98 T-5B BEL_135 BEL_134 BEL_132 BEL_120 BEL_100 Beluga 136 T-3 Coal T-5A BEL_131 BEL_99B BEL_99A BEL_99 BEL_115 BEL_133 T-4 T-6 BEL_110 T-5 3021 3979 3050 3100 3150 3200 3250 3300 3350 3400 3450 3500 3550 3600 3650 3700 3750 3800 3850 3900 3950 3259.5 4309.1 3300 3350 3400 3450 3500 3550 3600 3650 3700 3750 3800 3850 3900 3950 4000 4050 4100 4150 4200 4250 BEL_98 T-5B BEL_135 BEL_134 BEL_132 BEL_120 BEL_100 Beluga 136 T-3 Coal T-5A BEL_131 BEL_99B BEL_99A BEL_99 T-2 BEL_115 BEL_133 T-4 T-6 BEL_110 T-5 3021 3979 3050 3100 3150 3200 3250 3300 3350 3400 3450 3500 3550 3600 3650 3700 3750 3800 3850 3900 3950 5189.9 6293.9 5250 5300 5350 5400 5450 5500 5550 5600 5650 5700 5750 5800 5850 5900 5950 6000 6050 6100 6150 6200 6250 T-5B BEL_135 BEL_134 BEL_132 BEL_120 BEL_100 Beluga 136 T-3 Coal T-5A BEL_131 BEL_99B BEL_99A BEL_99 T-2 BEL_115 BEL_133 T-4 T-6 BEL_110 T-5 3021 3979 3050 3100 3150 3200 3250 3300 3350 3400 3450 3500 3550 3600 3650 3700 3750 3800 3850 3900 3950 3667.9 4839.6 3700 3750 3800 3850 3900 3950 4000 4050 4100 4150 4200 4250 4300 4350 4400 4450 4500 4550 4600 4650 4700 4750 4800 T-5B BEL_135 BEL_134 BEL_132 BEL_120 BEL_100 Beluga 136 T-3 Coal T-5A BEL_131 BEL_99B BEL_99A T-2 BEL_115 BEL_133 T-4 T-6 BEL_110 T-5 3021 3979 3050 3100 3150 3200 3250 3300 3350 3400 3450 3500 3550 3600 3650 3700 3750 3800 3850 3900 3950 4216.4 5298.9 4250 4300 4350 4400 4450 4500 4550 4600 4650 4700 4750 4800 4850 4900 4950 5000 5050 5100 5150 5200 5250 T-5B BEL_135 BEL_134 BEL_132 BEL_120 BEL_100 Beluga 136 T-3 Coal T-5A BEL_131 BEL_99B BEL_99A BEL_99 T-2 BEL_115 BEL_133 T-4 T-6 BEL_110 T-5 3021 3979 3050 3100 3150 3200 3250 3300 3350 3400 3450 3500 3550 3600 3650 3700 3750 3800 3850 3900 3950 3816 5038 3850 3900 3950 4000 4050 4100 4150 4200 4250 4300 4350 4400 4450 4500 4550 4600 4650 4700 4750 4800 4850 4900 4950 5000 T-5B BEL_135 BEL_134 BEL_132 BEL_120 BEL_100 Beluga 136 T-3 Coal T-5A BEL_131 BEL_99B BEL_99A BEL_99 T-2 BEL_115 BEL_133 T-4 T-6 BEL_110 T-5 3021 3979 3050 3100 3150 3200 3250 3300 3350 3400 3450 3500 3550 3600 3650 3700 3750 3800 3850 3900 3950 3640 4599.2 3700 3750 3800 3850 3900 3950 4000 4050 4100 4150 4200 4250 4300 4350 4400 4450 4500 4550 T-5B BEL_135 BEL_134 BEL_132 BEL_120 BEL_100 Beluga 136 T-3 Coal T-5A BEL_131 BEL_99B BEL_99A BEL_99 T-2 BEL_115 BEL_133 T-4 T-6 BEL_110 T-5 6216 ftUS 2053 ftUS 1978 ftUS 453 ftUS 1684 ftUS 4073 ftUS 1259 ftUS 2325 ftUSDionne 2 [SSTVD] Spud date: 07/29/2004 Operator: Marathon Oil Company TD (MD): 11026.0 ft TD (TVDSS): 7787.0 ft SSTVD 1:400 30.00 100.00gAPI GR Color fill MD 2.0000 ohm.m 200.0000 RESM 2 200ohm.m RESS 2 200ohm.m RESD 15 ohm 8 ohm 0.60 0.00ft3/ft3 NPHI 135.00 54.00us/ft DTC 1.65 2.65g/cm3 RHOB Color fill Color fill Color fill Color fill Dionne 8 [SSTVD] Spud date: 07/10/2013 Operator: Hilcorp Alaska, LLC TD (MD): 12130.0 ft TD (TVDSS): 11396.3 ft SSTVD 1:400 30.00 100.00gAPI GR Color fill MD 2.0000 ohm.m 200.0000 RESM 2 200ohm.m RESS 2 200ohm.m RESD 15 ohm 8 ohm 0.60 0.00ft3/ft3 NPHI 135.00 54.00us/ft DTC 1.65 2.65g/cm3 RHOB Color fill Color fill Color fill Color fill Dionne 5 [SSTVD] Spud date: 07/13/2006 Operator: Marathon Oil Company TD (MD): 9600.0 ft TD (TVDSS): 7831.3 ft SSTVD 1:400 30.00 100.00gAPI GR Color fill MD 2.0000 ohm.m 200.0000 RESM 2 200ohm.m RESS 2 200ohm.m RESD 15 ohm 8 ohm 0.60 0.00ft3/ft3 NPHI 135.00 54.00us/ft DTC 1.65 2.65g/cm3 RHOB Color fill Color fill Color fill Color fill Kalotsa 2 [SSTVD] Spud date: 01/06/2017 Operator: Hilcorp Alaska, LLC TD (MD): 8200.0 ft TD (TVDSS): 7712.4 ft SSTVD 1:400 30.00 100.00gAPI GR Color fill MD 2.0000 ohm.m 200.0000 RESM 2 200ohm.m RESS 2 200ohm.m RESD 15 ohm 8 ohm 0.60 0.00ft3/ft3 NPHI 1.65 2.65g/cm3 RHOB Color fill Color fill Color fill Dionne 6 [SSTVD] Spud date: 11/06/2008 Operator: Marathon Oil Company TD (MD): 6737.0 ft TD (TVDSS): 4364.3 ft SSTVD 1:400 30.00 100.00gAPI GR Color fill MD 2.0000 ohm.m 200.0000 RESM 2 200ohm.m RESS 2 200ohm.m RESD 15 ohm 8 ohm 0.60 0.00ft3/ft3 NPHI 135.00 54.00us/ft DTC 1.65 2.65g/cm3 RHOB Color fill Color fill Color fill Color fill Kalotsa 3 [SSTVD] Spud date: 06/08/2017 Operator: Hilcorp Alaska, LLC TD (MD): 9265.0 ft TD (TVDSS): 8028.3 ft SSTVD 1:400 30.00 100.00gAPI GR Color fill MD 2.0000 ohm.m 200.0000 RESM 2 200ohm.m RESS 2 200ohm.m RESD 15 ohm 8 ohm 0.60 0.00ft3/ft3 NPHI 1.65 2.65g/cm3 RHOB Color fill Color fill Color fill Kalotsa 4 [SSTVD] Spud date: 05/15/2017 Operator: Hilcorp Alaska, LLC TD (MD): 9400.0 ft TD (TVDSS): 7990.1 ft SSTVD 1:400 30.00 100.00gAPI GR Color fill MD 2.0000 ohm.m 200.0000 RESM 2 200ohm.m RESS 2 200ohm.m RESD 15 ohm 8 ohm 0.60 0.00ft3/ft3 NPHI 1.65 2.65g/cm3 RHOB Color fill Color fill Color fill Paxton 8 [SSTVD] Spud date: 08/29/2014 Operator: Hilcorp Alaska, LLC TD (MD): 9310.0 ft TD (TVDSS): 7867.9 ft SSTVD 1:400 30.00 100.00gAPI GR Color fill MD 2.0000 ohm.m 200.0000 RESM 2 200ohm.m RESS 2 200ohm.m RESD 15 ohm 8 ohm 0.60 0.00ft3/ft3 NPHI 1.65 2.65g/cm3 RHOB Color fill Color fill Color fill Paxton 2 [SSTVD] Spud date: 01/19/2008 Operator: Marathon Oil Company TD (MD): 8436.0 ft TD (TVDSS): 7813.7 ft SSTVD 1:400 30.00 100.00gAPI GR Color fill MD 2.0000 ohm.m 200.0000 RESM 2 200ohm.m RESS 2 200ohm.m RESD 15 ohm 8 ohm 0.60 0.00ft3/ft3 NPHI 135.00 54.00us/ft DTC 1.65 2.65g/cm3 RHOB Color fill Color fill Color fill Color fill -3900-3900-3900-3900-3650-365 0 -3650-3650-3650- 365 0 -3650 -3650 -365 0 -3650-3650-3650-3 6 5 0 -3650-3650 -3650 -3950-3950-3950-3950-3 6 0 0 -36 0 0 -3600 -3600-3600-3600-3 6 0 0 -3600 -360 0 -3600-3600-3600 -3 6 0 0 -3600 -3600-4050 -405 0 -3550 -355 0 -3550-3550- 3 5 5 0 -3550 -355 0 -3550-3550-3550 -35 5 0 -3500 -3500 -3500-3500-3500 -350 0 -350 0 -3500-3 5 0 0-4000-4000-4000 -385 0-3850-3850-3850-3850-3850-3800-380 0 -38 0 0 -3800-380 0 -3800-3800-3800-3800-3800-3750-375 0 -3750-37 5 0 -3750 -3750 -3750-3750-3750-3750-3750-375 0 -3700-370 0 -3700-3700-3700-3700-3700-3700-3700 -3700-3700-3700-3700-3700-3 7 0 0 -370 0 -3 7 0 0-430 0 -4250 -4250 -4200-420 0 -4150-415 0 -4100-410 0 -445 0 -440 0 -4350 -3450 -345 0 -3450-3450 -3450-3450-3400 Dionne 1A Dionne 2 Dionne 3 Dionne 4 Dionne 5 Dionne 6 Dionne 7 Dionne 8 Kalotsa 1 Kalotsa 2 Kalotsa 3 Kalotsa 4 Kalotsa 6 Paxton 1 Paxton 2 Paxton 3 Paxton 4 Paxton 8 Paxton 10 Paxton 6 PEARL 8 Paxton 12 Paxton 11 Kalotsa 7 Kalotsa 8 202400 203200 204000 204800 205600 206400 207200 208000 208800 209600 210400 211200 212000 212800 213600 214400 215200 202400 203200 204000 204800 205600 206400 207200 208000 208800 209600 210400 211200 212000 212800 213600 214400 2152002229600223040022312002232000223280022336002234400223520022360002236800223760022384002239200224000022408002241600222960022304002231200223200022328002233600223440022352002236000223680022376002238400223920022400002240800224160005001000150020002500ftUS 1:11742 Hilcorp: Kenai Team Ninilchik: Paxton/Kalotsa/Susan Dionne Beluga 135 Structure Susan Dionne 8 Disposal Well Contour inc 50 Date 04/02/2024 Sean Wagner Top Beluga 135: -4400.00 -4350.00 -4300.00 -4250.00 -4200.00 -4150.00 -4100.00 -4050.00 -4000.00 -3950.00 -3900.00 -3850.00 -3800.00 -3750.00 -3700.00 -3650.00 -3600.00 -3550.00 -3500.00 -3450.00 -3400.00 -3350.00 TVDss depth [ft] Top disposal zone in Susan Dionne 8 A A'