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Home My WebLink AboutDIO 046DISPOSAL INJECTION ORDER 46 1. August 9, 2023 Hilcorp application for DIO RE: NCIU A-08 2. September 7, 2023 Notice of Public Hearing, affidavit, and email list 3. October 9, 2023 Hilcorp affidavit 4. ---------------------- emails 5. October 10, 2023 Transcript and presentation 6. October 24, 2023 Hilcorp additional information, questions from hearing 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 Sterling Formation in the North Cook Inlet Unit Well A- 08, located in Sections 6, T11N, R09W S.M. ) ) ) ) ) ) ) Disposal Injection Order 46 Docket Number: DIO-23-003 North Cook Inlet Unit Well A-08 Cook Inlet Basin November 20, 2023 IT APPEARING THAT: 1. By application received August 18, 2023, Hilcorp Alaska, LLC (Hilcorp) requested authorization for underground disposal of Class II oil field waste fluids into the existing North Cook Inlet Unit (NCIU) well A-08 (NCIU A-08). 2. On August 25, 2023, Hilcorp provided an affidavit stating all surface owners within a one- quarter mile of the existing NCIU A-08 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) scheduled a public hearing for October 10, 2023. On September 7, 2023, 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 September 10, 2023, the notice was published in the Anchorage Daily News. 4. The AOGCC did not receive any public comments or protests. 5. A public hearing was held on October 10, 2023, where Hilcorp provided testimony and presented evidence in support of its application. The hearing record was left open until October 27, 2023, for Hilcorp to respond to the AOGCC’s requests for additional information. 6. On October 24, 2023, Hilcorp submitted the requested information. 7. Hilcorp’s application, testimony, supplemental information, and AOGCC public records for NCIU wells provide sufficient information to make an informed decision. FINDINGS: 1. Location of Adjacent Wells (20 AAC 25.252(c)(1)) NCIU A-08 is an existing gas development well located 1256 feet from the north line and 1080 feet from the west line of Section 6, Township 11N, Range 09W, Seward Meridian. The surface location is on the Hilcorp-operated Tyonek Platform in 120 feet of water approximately 5 miles due east of Tyonek, Alaska and 40 miles west-southwest of Anchorage, Alaska. Six wells penetrate the disposal zone within a ¼-mile radius of NCIU A-08 (see Figure 1). Disposal Injection Order 46 November 20, 2023 Page 2 of 10 Figure 1. Top Sterling Geological Structure Map showing true vertical depth subsea (TVDSS) of top of disposal zone. NCIU A-08 well path shown to northwest of Tyonek platform (center). (Source: Hilcorp Alaska, LLC’s application) Disposal Injection Order 46 November 20, 2023 Page 3 of 10 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. The sole surface owner within a ¼-mile radius of NCIU A-08 is the State of Alaska. 2. Geological Information on Disposal and Confining Zones (20 AAC 25.252(c)(4)) The proposed disposal injection interval in NCIU A-08 lies within the Sterling Formation and consists of a series of coarse-grained sand beds interspersed with relatively thin layers of carbonaceous mudstone. Strata correlative with this interval, which lie between 4,015’ measured depth (MD), which is equivalent to 3,274’ true vertical depth (TVD), and 4,207’ MD (3,387’ TVD) in NCIU A-08, were previously used for disposal injection in offset wells NCIU B-01A, detailed in Disposal Injection Order (DIO) 33, and NCIU A-12 (DIO 17). Lithologic units are correlative throughout the unit and a cross section comparing NCIU A-12 to NCIU A-08 shown in Figure 2. demonstrates the similarities between the two zones. [See also AOGCC Sundry 323-110.] Upper confinement is provided by a stacked sequence of siltstones, mudstones, and coals interbedded with scattered sands from approximately 3,717’ to 4,015’ MD (3,092’ to 3,274’ TVD). This sequence contains an aggregate thickness of about 68 true vertical feet of mudstone and coal. Lower confinement is provided by a sequence of interlaminated mudstone, claystone, coal, and siltstone interbedded with occasional sand intervals from approximately 4,208’ to 4,343’ MD (3,387’ to 3,465’ TVD). This sequence contains an aggregate thickness of at least 40 true vertical feet of mudstone and coal. Disposal Injection Order 46 November 20, 2023 Page 4 of 10 Figure 2. Stratigraphic correlation between NCIU A-12 (left) and NCIU A-08 (right). Disposal zone identified with blue fill. (Source: Hilcorp Alaska, LLC’s application) Disposal Injection Order 46 November 20, 2023 Page 5 of 10 3. Well Logs (20 AAC 25.252(c)(5)) Log data from NCIU A-08 and offsetting wells are on file with the AOGCC. Hilcorp provided a cross section through NCIU wells A-12 and A-08 identifying the confining and disposal zones. 4. Demonstration of Mechanical Integrity and Disposal Zone Isolation (20 AAC 25.252(c)(6)) The casing across the disposal zone in NCIU A-08 is 7” 26# J-55. Cement across the disposal zone and confining layers was placed using a stage collar at 6,031’ MD where 860 sacks of 15.6 pounds per gallon (ppg) Class G cement (equivalent to 168 barrels, or bbls) was placed as the second stage of a two--stage cement job. A subsequent Cement Bond Log (CBL) run on July 23, 1969, showed top of cement at 3,012’ MD and sufficient cement across the disposal zone and confining layers for zonal isolation. The tubing is isolated from the casing with a cement packer placed by coiled tubing on July 3, 2020, using a cement retainer, and 12 bbls of 15.3 ppg cement was pumped through the retainer at 4,500’ MD and tubing punch holes at 4,516’ MD. A Radial CBL (RCBL), run on July 4, 2020, showed excellent cement below 4,010’ MD and patchy cement up to 3,895’ MD. This interpretation was confirmed by the AOGCC in approved Sundry 323-110. The annulus was pressure tested to 1,500 pounds per square inch (psi), before and after perforating the disposal zone. An injection test of 1,271 bbls pumped at a rate of about 1.0 barrels per minute (bpm) showed no annular communication. These results are detailed in the Sundry Report submitted as follow-up to Sundry 323-110. The Sterling X and Y sands were isolated with a pressure tested Cast Iron Bridge Plug (CIBP) set at 4,232’ MD and topped with 25’ of cement. These results are detailed in the Sundry Report submitted as follow-up to Sundry 323-110. This testing meets the requirements of 20 AAC 25.412. 5. Disposal Fluid Type, Composition, Source, Volume, and Compatibility with Disposal Zone (20 AAC 25.252(c)(7)) Waste disposal injection will consist of drilling mud, drill cuttings, reserve pit fluids, rig wash fluids, formation material, completion fluids, produced water, stimulation fluids, deck drainage, and other fluids eligible for injection into a Class II disposal well. The average daily disposal volume will depend on whether NCIU A-13 remains the primary disposal well for the Tyonek platform. If so, disposal will only occur in NCIU A-08 if additional disposal capacity is required or if A-13 ceases to be the primary disposal well. The maximum daily volume to be disposed of is 3,500 bbls and corresponds to an average injection rate of 2.4 bpm. This rate and daily disposal volume is consistent with DIO 33 and the fracture modeling used to validate confinement of injected fluids. Given the historical disposal activities into this zone, no fluid compatibility issues are anticipated [DIO 33 finding 8]. 6. Estimated Injection Pressures (20 AAC 25.252(c)(8)) The estimated maximum injection pressure will be 2,500 pounds per square inch gauge (psig). An injectivity test was performed at a rate of about 1.0 bpm with a resulting injection pressure Disposal Injection Order 46 November 20, 2023 Page 6 of 10 of 1,450 psig. These results were consistent with injection results in B-01A as well as the Findings and Conclusions in DIO 17 and DIO 33 [specifically DIO 33 – Finding 9]. 7. Evaluation of Confining Zones (20 AAC 25.252(c)(9)) The effectiveness of the confining intervals – both upper and lower – has been demonstrated by past injection in the proposed disposal zone at NCIU A-12 and NCIU B-01A. Fracture model results for the proposed disposal zone, using a third-party fracture model, were submitted as part of DIO 17. This modeling was also used for DIO 33. DIO 17 found that the planned disposal operations, as outlined in this application, into the proposed disposal zone will not propagate fractures through the confining zones [DIO 33 – Finding 8]. Based on the geologic similarities of NCIU A-08 to A-12 and B-01A, the fracture modeling submitted with the application for DIO 17 (and by extension to DIO 33) is considered applicable to NCIU A-08. The previously proposed injection rates, volumes, and pressures are in line with the fracture modeling results presented in DIO 17 and DIO 33. 8. Standard Laboratory Water Analysis of the Formation (20 AAC 25.252(c)(10)); Aquifer Exemption (20 AAC 25.252(c)(11)); A standard laboratory water analysis was submitted with the application for Aquifer Exemption Order #4 and for Disposal Injection Order 17. Aquifer Exemption Order (AEO) 4 dated September 29, 1998, exempts those portions of aquifers within the NCIU that are common to and correlate with the interval below 2,900 feet MD in NCIU A-12. Wireline analytical techniques compliant with EPA recommended methods coupled with laboratory analysis of water samples in wells offsetting NCIU B-01A were used to characterize formation water salinities. The AOGCC concluded in AEO 4 that freshwater aquifers underlying NCIU do not serve as a source of drinking water. Further, the AOGCC concluded that freshwater exists at a depth and location that makes its recovery for drinking purposes economically impractical. The closest drinking water well to the NCIU is onshore approximately 8 miles to the northwest, in the Beluga River Unit. The proposed disposal zone in NCIU A-08 is within this interval and thus within the existing aquifer exemption. 9. Mechanical Condition of Wells Penetrating the Disposal Zone Within a ¼-Mile Radius of the proposed disposal wells (20 AAC 25.252(c)(12)) Six wells 1 penetrate the Sterling within a 1/4-mile radius of NCIU A-08. Construction information for each well, including cement tops for casing set across the Sterling, is summarized in the order application. Detailed well construction information is in the AOGCC well files; this information includes cementing records that indicate cement has been circulated to surface in the surface casing annulus for each of the six wells. In addition, Hilcorp has summarized the results of the CBLs run for five of the six wells (no bond log was run in A-16; however, cement was circulated to surface). The NCIU A-03A well (approximately 1,300’ from NCIU A-08) does not have adequate isolation across the disposal zone. The top of the disposal zone in NCIU A-03A is at 3,647’ MD (3,265’ TVD), but top of cement is at 4,184’ MD (3,597’ TVD). At the public hearing, the AOGCC requested additional analyses from Hilcorp to determine the volume of injected 1 The six well are NCIU A-01, A-01A, A-03, A-03A, A-13, and A-16. Disposal Injection Order 46 November 20, 2023 Page 7 of 10 fluid required to reach the NCIU A-03A well. Hilcorp responded by email on October 24, 2023, stating that it would require 34,000,000 bbls of injected fluid at NCIU A-08 before the plume reached NCIU A-03A. The AOGCC accepts this analysis. For the expected volume of injected fluids (less than 100,000 bbls/year), this equates to 34 years of disposal at maximum expected volumes. CONCLUSIONS: 1. The application requirements and conditions for approval of an underground disposal application in 20 AAC 25.252 have been met. 2. Aquifers below 2,900’ MD in the NCIU A-12 well are exempt under 20 AAC 25.440 by AEO 4. This aquifer exemption covers the proposed disposal zone in NCIU A-08. 3. Proposed injection sands and confining layers are laterally continuous over the field. Stacked confining zones totaling approximately 185 feet true vertical thickness above and approximately 160 feet true vertical thickness below the injection zone will provide confinement of injected wastes. 4. Injected fluids will remain confined to the intended interval as supported by results from historical injection into correlative sands for both the NCIU A-12 and B-01A wells. 5. Waste fluids will be contained within the receiving intervals by the confining lithologies within the Sterling based on the DIO 17 and DIO 33 modeled injection rates, volumes, fluid densities, and pressures (which exceed expected operating conditions), and the historical injection in the proposed disposal zone common to NCIU A-08, NCIU B-01A, and NCIU A-12. Cement isolation of the injection zone in the well bore and operating conditions further support the AOGCC’s conclusion about confinement. Modeling worst-case conditions (i.e., continuous injection) predicts a zone of influence (waste plume area) for injected materials to occupy a fracture domain extending approximately 400 feet laterally from the well and vertically 125 feet, all within the identified geologic confinement. Batch injection will likely result in a radial- type disposal domain, reducing the predicted lateral and vertical propagation of the fractures that result from the slurry injection. [DIO 33 Conclusion 5] 6. By disposing of water produced from the Sterling Formations back into the Sterling at NCIU A-08, no fluid/formation compatibility issues are expected. DIO 33 Conclusion 8 states: “Fluid compatibility in the Sterling disposal zone is not an issue. Operating experience and data from disposal injection—(i) involving similar materials and performance parameters (i.e., pressures, rates, and volumes), (ii) including the historical injection of 135,000 barrels of Class II drilling waste, and (iii) involving the same injection zone in nearby NCIU A-12—provide a suitable analogy for underground disposal using annulus injection tubings in NCIU B-01A.” 7. Reviews of mechanical integrity of six nearby 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. NOW, THEREFORE, IT IS ORDERED THAT Hilcorp’s request for authorization for underground disposal of Class II fluids into well NCIU A-08 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 Sterling Undefined Waste Disposal Zone within the NCIU A-08 well. Disposal Injection Order 46 November 20, 2023 Page 8 of 10 RULE 1: Injection Strata for Disposal Underground disposal of the Class II fluids listed below is permitted into the Sterling Undefined Waste Disposal Formation within NCIU A-08 in the interval between 4,015’ to 4,207’ MD (3274’ and 3387’ TVD) RULE 2: Authorized Fluids This authorization is limited to Class II gas field waste fluids generated within the NCIU 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 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 intervals or migrate out of the approved injection stratum. Disposal injection is authorized at (a) rates that do not exceed 2.4 bpm and (b) surface pressures that do not exceed 2,500 psig. RULE 4: Demonstration of Mechanical Integrity The mechanical integrity of NCIU A-08 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 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 of 1500 psi, or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, that shows stabilizing pressure and does not change more than 10 percent during a 30-minute period. Results of 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 so directed by the AOGCC. If fluids are found to be fracturing through a confining interval or migrating out of the approved injection stratum, the operator must immediately shut in the well. Upon discovery of such an event, the operator must immediately notify the AOGCC, provide details of the operation, and propose actions to prevent recurrence. Injection may not be restarted until approved by the AOGCC. A monthly report of daily tubing Disposal Injection Order 46 November 20, 2023 Page 9 of 10 and casing annuli pressures and injection rates must be provided to the AOGCC if the well indicates any well integrity failure or lack of injection zone isolation. The AOGCC may immediately suspend, revoke, or modify this authorization if injected fluids fail to be confined to the approved disposal interval. 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. Notification or other legal requirements of any other State or Federal agency remain the operator's responsibility. DONE at Anchorage, Alaska, and dated November 20, 2023. Brett W. Huber, Sr. Jessie L. Chmielowski Chair, Commissioner Commissioner Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2023.11.20 10:41:27 -09'00' Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.11.20 10:49:08 -09'00' Disposal Injection Order 46 November 20, 2023 Page 10 of 10 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. From:Carlisle, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Disposal Injection Order 46 (NCIU) Date:Monday, November 20, 2023 11:43:23 AM Attachments:dio46.pdf THE APPLICATION OF Hilcorp Alaska, LLC for disposal of Class II oil field wastes by underground injection into the Sterling Formation in the North Cook Inlet Unit Well A-08, located in Sections 6, T11N, R09W S.M. Samantha Carlisle Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: samantha.carlisle@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.carlisle%40alaska.gov 6 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. From:Casey Morse To:Carlisle, Samantha J (OGC) Cc:Wallace, Chris D (OGC) Subject:Tyonek NCIU A-08 DIO Hearing Follow-up Date:Tuesday, October 24, 2023 12:10:22 PM Samantha, During the hearing for Docket DIO-23-003 on 10/10/2023, Hilcorp Alaska LLC committed to provide a response regarding two questions raised by the AOGCC Commissioners. Below are Hilcorp’s responses to those outstanding items: Domestic wastewater generated at the Tyonek platform is treated with a biological treatment unit and discharged in accordance with APDES General Permit Number AKG315211. The cumulative volume of injected fluids necessary to reach from the subject NCIU A-08 wellbore to the NCIU A03-A wellbore is approximately 34,000,000 bbls according to the calculations and assumptions shown below. NCIU A-08 Volumetric Analysis Distance to NCIU A-03A (ft) Avg Porosity of Injection Zone Avg Height of Injection Zone (ft) Volume between A-08 and A-03A (ft3)Cumulative bbls 1301 33%110 191,795,568 34,157,715 Note the following assumptions with this model: 1) Injected fluid stays within the sand layer which is perfed 2) Average effective porosity consistent throughout the entire invasion zone for each individual sand 3) Injection is evenly distributed vertically across the injection interval 4) Piston-like displacement of native reservoir fluids. Thank you, Casey Morse Well Integrity Engineer Hilcorp Alaska, LLC (907) 777-8322 (office) (603) 205-3780 (cell) 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 arenot 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 youhave received this email in error, please immediately 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 the onward transmission, opening, or use ofthis 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 outsuch virus and other checks as it considers appropriate. 5 0001 1 ALASKA OIL AND GAS CONSERVATION COMMISSION 2 In the Matter of the Application of ) 3 Hilcorp Alaska, LLC to Convert the NCIU ) A-08 Well to be Used for Class II Disposal ) 4 into the Currently Perforated Zone. ) ____________________________________________) 5 Docket No.: DIO-23-003 6 PUBLIC HEARING 7 Anchorage, Alaska October 10, 2023 8 10:00 o'clock a.m. 9 BEFORE COMMISSIONERS: 10 Brett Huber, Chairman 11 Jessie Chmielowski, Commissioner Greg Wilson, Commissioner 12 13 14 15 16 17 18 19 20 21 22 23 24 25 0002 1 TABLE OF CONTENTS 2 Opening remarks by Chair Huber 03 3 Testimony by Chris Stone 08 4 Testimony by Josh Allely 09 5 Testimony by Matthew Petrowsky 12 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 0003 1 P R O C E E D I N G S 2 (On record - 10:06 a.m.) 3 CHAIRMAN HUBER: Good morning. I'll call this 4 hearing to order. It's about 10:06 a.m. on Tuesday, 5 October 10th. This is a hearing of the Alaska Oil and 6 Gas Conservation Committee. This is a public hearing 7 on docket number DIO-23-003, an application by Hilcorp 8 Alaska, LLC to convert the NCIU A-08 well to be used 9 for class II disposal into the currently perforated 10 zone. I'm Commissioner Brett Huber and I serve as the 11 public member and Chairman of the Commission. To my 12 left is Commissioner Jessie Chmielowski, Petroleum 13 Engineer and to my right Commissioner Greg Wilson, 14 Petroleum Geologist. They occupy the seats designated 15 for their disciplines. 16 Today's hearing is being held in person and via 17 Microsoft Teams. The in person location is here at 333 18 West 7th Avenue, Anchorage, Alaska, the AOGCC offices. 19 For those on Teams please be mindful of any background 20 noise and make sure you're muted when you're not 21 testifying, please, so everybody can hear the hearing 22 properly. 23 If you require any special accommodation to 24 participate in our hearing today please contact 25 Samantha Carlisle, Special Assistant to the 0004 1 Commission. She can be reached at 907-793-1223 or send 2 her a message through the Microsoft Teams chat icon and 3 she'll do her best to keep -- get you all set. 4 Samantha will also be recording today's hearing 5 for us. Upon completion and preparation of the 6 transcript anyone desiring a copy will be able to 7 obtain it by contacting Computer Matrix. 8 This hearing is being held in accordance with 9 AS 44.62 and 20 AAC 25.540 of the Alaska Administrative 10 Code. 11 The notice of today's hearing was published on 12 the state of Alaska online notices website as well as 13 the AOGCC's website and was sent through the Commission 14 email list serve on September 7th, 2023. The AOGCC 15 also published the notice in the Anchorage Daily News 16 on September 10th, 2023 thus meeting all of the notice 17 requirements. 18 A little bit of background on disposal 19 injection orders. The disposal injection order is 20 applied for under 20 AAC 25.252 for the purpose of 21 prescribing rules that differ or are supplemental to 22 the normal statewide rules found in 20 AAC 25 for the 23 operation of class II disposal. 24 At the close of today's hearing the AOGCC will 25 review the information presented today and any 0005 1 additional written comments received before the record 2 is closed. Upon completion of that review and our 3 deliberations the Commission expects to issue a written 4 decision. 5 Questions of the presenters today will come 6 from myself or Commissioner Chmielowski and 7 Commissioner Wilson. However should a member of the 8 audience have a question that he or she feels should be 9 asked please submit that question in writing to 10 Samantha Carlisle either in person if you're in the 11 room or via Teams' chat feature. She'll provide these 12 questions to us for review and if we believe your 13 question will help assist us in making our 14 determinations we will ask it. In any regard all 15 questions recommended by the public will be included in 16 the public record. 17 I should note that we may take a break or a 18 number of breaks today to consult with Staff and confer 19 with Commissioners. These breaks help us to ensure 20 we've recovered all the relevant information and 21 subject matter to develop a complete record on which to 22 base our deliberations and decision as well as to 23 provide the best possible information to the public. 24 We will begin today's hearing with the Hilcorp 25 presentation. Representatives from Hilcorp -- perhaps 0006 1 before we do this I would just note in Hilcorp's 2 application, section 3 and then section 4 -- actually 3 it's sub (2) and some sub (3), there's a little bit of 4 a discrepancy. Sub (2) talks about the only owner 5 within the quarter mile radius being the state of 6 Alaska, yet sub (3) talks about no parties due notice 7 of this proposed disposal well. I understand that that 8 has been rectified and notice was provided an affidavit 9 is in compliance and with us at the Commission. I just 10 want to make sure that we stated that for the record 11 for clarity. 12 So representatives from Hilcorp, are you ready 13 to begin your presentation and if so please state your 14 names and job titles clearly for the record. 15 (No comments) 16 CHAIRMAN HUBER: Yes, please. And you'll need 17 to hit the button on your microphone to make sure that 18 green light is lighted when you're speaking and then 19 please hit it when you're done. I should also remind 20 you that when you transition speakers from one to the 21 next please identify yourself so the public can follow 22 along and so that we build a good complete, accurate 23 record. 24 Thank you. 25 MR. STONE: I'm Christopher Stone, I'm a 0007 1 Reservoir Engineer for Hilcorp. I've been with Hilcorp 2 for three years now. 3 (Off record comments - microphone)..... 4 MR. STONE: I'm green now. 5 CHAIRMAN HUBER: Okay. Go ahead. 6 MR. STONE: All right. My name is Christopher 7 Stone, I'm a Reservoir Engineer with Hilcorp. 8 MR. PETROWSKY: Matthew Petrowsky, Geologist 9 with Hilcorp. 10 MR. ALLELY: I'm Josh Allely, Well Integrity 11 Engineer for Hilcorp. 12 CHAIRMAN HUBER: Thank you, gentlemen. Now I 13 would like to swear you in as witnesses. Will all of 14 you please raise your right hand and respond for me. 15 (Oath administered) 16 IN UNISON: Yes. 17 CHAIRMAN HUBER: Let the record show that all 18 of them answered in the affirmative. 19 Do any of you presenting today wish to be 20 recognized as experts in your field? If you do please 21 identify your field of expertise and your credentials. 22 Up to you all, not a requirement. 23 (No comments) 24 CHAIRMAN HUBER: Okay. We will just proceed at 25 this point then. Commissioner Chmielowski and Wilson, 0008 1 are you satisfied with the proceeding so far, is there 2 anything you'd like to add before we get going with the 3 presentation? 4 COMMISSIONER CHMIELOWSKI: Nothing to add. 5 Thank you. 6 COMMISSIONER WILSON: Nothing to add. 7 CHAIRMAN HUBER: Okay. Gentlemen, who will 8 begin and please proceed. 9 CHRIS STONE 10 previously sworn, called as a witness on behalf of 11 Hilcorp Alaska, LLC, testified as follows on: 12 DIRECT EXAMINATION 13 MR. STONE: I will begin. So again Chris 14 Stone. I'll talk about some of the background here for 15 this current application. 16 So Hilcorp is here today to provide some 17 supplemental information in the request to convert 18 North Cook Inlet Unit A-8 to a class II disposal well. 19 And it should be noted for the record that we currently 20 have an aquifer exemption, aquifer exemption number 4, 21 at the Tyonek, the North Cook Inlet Unit which exempts 22 aquifers below 2,900 feet measured depth. 23 The Tyonek platform just for reference we've 24 historically had two disposal wells. Most recently 25 it's been A-13 and B-1 have been used for disposal. 0009 1 The A-13 well is currently a class I disposal well and 2 receives the bulk of the injections from the production 3 of gas on the Tyonek platform. 4 To note, we've got two wellbores here that 5 we'll be referencing predominantly today, the B-1 6 wellbore which we've abandoned our disposal into 7 recently this year and for the reason being that it was 8 non -- not ideal for disposal due to its well work 9 configuration. The well has two -- it had two side 10 smaller injection strings that were strapped to the 13 11 and three-eights inch casings and two and three-eights 12 inch pipe that was used for injection. So not idea 13 from the standpoint of monitoring annuli or doing PT 14 surveys on it. 15 COMMISSIONER CHMIELOWSKI: Excuse me. Do you 16 mean as a dual string injector, like that? 17 MR. STONE: It was a dual string injector..... 18 COMMISSIONER CHMIELOWSKI: Okay. 19 MR. STONE: .....in a -- in a certain capacity. 20 Josh is going to clarify. 21 JOSH ALLELY 22 previously sworn, called as a witness on behalf of 23 Hilcorp Alaska, LLC, testified as follows on: 24 DIRECT EXAMINATION 25 MR. ALLELY: Yeah, it really wasn't even 0010 1 considered a dual string. It had its own tubing string 2 which was a gas well. I'm Josh Allely speaking. And 3 it actually had two two and three-eights tubing strings 4 strapped to the side of the nine and five-eights and 5 they ran..... 6 CHAIRMAN HUBER: Are you using your microphone? 7 MR. ALLELY: Sorry. They had two two and 8 three-eights tubing strings strapped to the side of the 9 nine and five-eights when they ran and then they shot 10 through the nine and five-eights to perforate the two 11 and three eights strings and that's what they were 12 injecting down. And that was the backup disposal well 13 for the last 10 years or so. And they really didn't 14 make a good well, we had to log it every couple years 15 to make sure that the injection was still in zone. 16 Anyway it was just a very strange well. 17 CHAIRMAN HUBER: Perhaps I could add a quick 18 question as well. You talk about this being the backup 19 for that well that you're closing down and I believe 20 that you showed that total amount injected through that 21 well 01 to be about 830,000 barrels, yet it says your 22 type 1 disposal well receives most of the injection. 23 Can you give us an idea of what that volume is? 24 MR. ALLELY: Yeah, we actually have a slide 25 covering that so it's coming up in -- after we talk 0011 1 about the geo section if you want to hold on. 2 CHAIRMAN HUBER: Excellent. I'll hold my 3 question. Thank you. 4 MR. ALLELY: Okay. Thanks. 5 MR. STONE: All right. This is Chris again. 6 So just to finish up the bullet points there with the 7 B-1, we've identified this well to be a better 8 candidate for future gas production so the utility of 9 it has been preserved such that we will -- we'll 10 sidetrack this well at some point in time to develop 11 additional gas reserves in the North Cook Inlet Unit. 12 In terms of A-8 wellbore that we proposed converting a 13 backup injector, at this point in time there's no more 14 remaining economic value as a producer. We've tried 15 and produced the productive gas intervals, they've been 16 plugged back through time and basically they're not 17 produce -- not productive any more. So it provides a 18 better suited well from a wellbore configuration 19 standpoint for pressure monitoring, testing. It's got 20 integrity so there's no need for a variance or a waiver 21 and should be noted that the proposed sands that we 22 will be injecting into are same Sterling sands present 23 in the A-12 which was approved in DI-17 -- DIO-17 and 24 the B-01A which was approved in DIO-33. 25 So again our goal is to replace B-01A with A-08 0012 1 and utilize A-08 as a backup injector to the current 2 injector. 3 MATTHEW PETROWSKY 4 previously sworn, called as a witness on behalf of 5 Hilcorp Alaska, LLC, testified as follows on: 6 DIRECT EXAMINATION 7 MR. PETROWSKY: This is Matthew Petrowsky, the 8 Geologist. So just want to orient folks in this 9 meeting to..... 10 CHAIRMAN HUBER: One other quick housekeeping 11 measure on conduct. Just make sure as you are flipping 12 through your slides and speaking to a slide that you 13 refer to the slide number that you're on, please. That 14 also will help with the record as well as the public 15 file. 16 MR. PETROWSKY: No problem. So speaking to 17 slide number 3, this is a structure map on -- off the 18 Tyonek platform. It's a structure map on the Sterling 19 top disposal zone. On this map I'm showing all of the 20 wellbores penetrating the Tyonek structure. So well 21 names are displayed at the bottom hole location and 22 then additionally you'll see well names and TVD subsea 23 depths displayed along the wellbore. Those depths 24 correspond to the specific point that that wellbore 25 penetrates the top disposal zone that we're speaking 0013 1 to. And then also on this map is a cross-section A to 2 A prime from north to south. I'm going to be showing 3 that on the next slide, slide number 4. That cross- 4 section is a reference to sort of the four wells that 5 we -- we'll touch on throughout this presentation. A- 6 8, the well that we're here to convert, A-13, our 7 primary class I disposal well, A-12 and B-1 are the 8 sort of legacy disposal wells on the Tyonek platform. 9 So moving ahead to slide number 4. So this is 10 that same exact cross-section, A to A prime. Really 11 what I'm trying to show here, this is a structural 12 cross-section, is this interval here with -- you can 13 see my mouse highlighted in blue, this is the top 14 Sterling disposal zone so the disposal zone we are 15 talking about today. You can see these -- I have a 16 zoomed in picture of this on the corresponding slide, 17 but these green perforations here are where we plan to 18 inject into if this is approved in the A-8 wellbore. 19 You can see historically here in red on the A-12 and on 20 the B-1 wellbore that they were injecting into this 21 same exact disposal zone. And then A-13 which is our 22 class I disposal well, it is actually disposing in a 23 different sand all the way down here, the Cook Inlet 7 24 sand. So really this cross-section is just trying to 25 show both of those disposal zones across all four of 0014 1 those different wells. 2 And so moving ahead to slide number 5, I just 3 have a zoomed in portion of that upper part of the 4 cross-section. So again here's those green 5 perforations I was talking about in our A-8 well, red 6 here in our A-12 well and red here in B-1A. I guess 7 before I dive into more specifics here I'll just walk 8 everyone through what the curves and what the tracks 9 are representing on this cross-section. So each of 10 these are their own wells so A-8, A-13, A-12 and B-1A. 11 The templates are the same for all four. The first 12 track here we see is measured depth. The second depth 13 track you see is TVD. The third track -- depth track 14 is CVD subsea. In our first log track I have gamma ray 15 which is colored green, SP which is the black curve if 16 present. The middle track here that's gray is where I 17 kind of annotate perforations, any plugs, cement, et 18 cetera, sort of a poor boy well schematic. Track 19 number 2 is our resistivity, that's shaded red at about 20 eight ohmmeters and track three is our triple combo 21 track, so density, neutron and sonic curves if we have 22 them. Neutron is blue, sonic is orange which we only 23 have here in the A-13 and A-12 wells and then the black 24 curve that's shaded that yellow and kind of gray color 25 is a calculated density porosity from row B. Then 0015 1 where row B and neutron crossover is colored red and 2 then when sonic and neutron crossover in that track 3 it's colored green. That helps to orient folks here. 4 COMMISSIONER WILSON: Matthew..... 5 COMMISSIONER CHMIELOWSKI: Mr. Petrowsky -- oh, 6 go ahead. 7 COMMISSIONER WILSON: .....I was just going to 8 say and you may do it on a subsequent slide, I'm not 9 sure, but if -- for the room and those online could you 10 maybe summarize just a little bit the lithologies and 11 when you talk about the crossover what you're 12 identifying, that sort of thing. 13 MR. PETROWSKY: Sure. Yeah. 14 COMMISSIONER WILSON: Okay. 15 MR. PETROWSKY: So the picks that you see on 16 the -- on the map here are -- correspond to for the 17 most part coals that are laterally continuous across 18 the whole structure. And then so I guess I can talk -- 19 let me talk about the injection interval itself. So 20 that is represented again by this blue shading here. 21 So this -- this pick would be your top disposal zone 22 and then this pick here is your base disposal zone. 23 So, you know, within that zone we see a bunch of 24 mudstone, siltstone and sand quality, you know, we have 25 effective porosities anywhere from 23 to 27 percent, 0016 1 permeabilities range from 30 to a hundred -- 1,100 2 millidarcies. You know, the disposal zone itself is 3 comprised of roughly two 56 foot sand and siltstone 4 packages. It's sort of bisected here in the middle by 5 about a three foot coal/mudstone interval. These 6 channels or these sands are, you know, amalgamations of 7 several different channel belts stacked together. So 8 that's really what confines our specific disposal zone. 9 And then if we kind of touch on the confining layers 10 above and below us and so above us here which would be 11 everything above this pick here in the A well so really 12 honing in what I'm highlighting here with my mouse. 13 Those are stacked sequences of siltstones, mudstones 14 and coals. You can see I have the coals particularly 15 flagged here with this gray marker kind of jutting 16 across. That's really identified from not only mud log 17 cuttings, but also density values less than about 1.85 18 grams per centimeter cubed. And then subsequently 19 below us we also see very similar lithologies that 20 bracket that lower confinement. So inner limited 21 mudstones, claystones, coals, siltstones and then the 22 occasional thin interbedded sand. 23 If we go to the next slide here, this is slide 24 number 6. That same cross-section I've highlighted 25 specifically the A-13 well here, a mud log, and then 0017 1 corresponding with these red dash lines are the 2 specific disposal interval. So again this interval 3 here highlighted in blue on the cross-section. And 4 that just corroborates the lithologies within that 5 disposal zone as well as corroborates the lithologies 6 of the confining zones above and below. 7 COMMISSIONER CHMIELOWSKI: Mr. Petrowsky, where 8 is your class I well A-13 perforated, it's not 9 perforated in this same area? 10 MR. PETROWSKY: Yeah, so we're going to back up 11 to slide number 4. A-13 is perforated in this..... 12 COMMISSIONER CHMIELOWSKI: Oh. 13 MR. PETROWSKY: .....Cook Inlet 7 sand so 14 separate reservoir. 15 COMMISSIONER CHMIELOWSKI: Right. Great. 16 Thank you. 17 MR. PETROWSKY: Yeah. And then just for the 18 note, I probably should have mentioned this on the map 19 side, but, you know, at the top disposal zone, so at 20 this pick in all of these wellbores, the A-8 well is 21 about 1,760 feet from the A-12 well and then 2,456 from 22 the B-1A1. I just wanted to note that because again 23 those two wells were perforated in that same disposal 24 zone. 25 With that..... 0018 1 COMMISSIONER WILSON: Matthew, would you want 2 to comment on the cumulative thickness of the coals in 3 the upper and lower confining zones? 4 MR. PETROWSKY: Yes. So these coals here in 5 the upper confining zones are roughly five feet in 6 thickness. There's one, two, three, four, five of them 7 so it's 20ish feet, but then, you know, in addition to 8 just those coals are, you know, silts and mudstones 9 that are kind of interfingered within those confining 10 layers. And then subsequently below the disposal zone 11 is a little bit thicker coal here, it's about 10 feet 12 thick and then two additional ones in this lower 13 confining interval here, those are about, you know, one 14 to two feet thick. 15 With that, that's all the specific geology 16 slides I had presented, but hopefully the -- does 17 anyone have any questions? 18 CHAIRMAN HUBER: Additional questions, 19 Commissioners. 20 COMMISSIONER CHMIELOWSKI: Just wanted to 21 confirm that Hilcorp has or the operator of the 22 platform has been injecting into this disposal zone for 23 years, you have two wells that have injected into it 24 and you're proposing a third. Are there any -- have 25 there been any concerns about fracturing out of the 0019 1 confining layers or through them or is there any 2 evidence to show that there's a concern about fracking 3 out of zone? 4 MR. ALLELY: Josh Allely. No, based on all the 5 temperature surveys that have been conducted B-01A was 6 required to do temperature surveys every other year and 7 there showed -- we showed no signs of out of zone 8 injection. And just looking at the fracture models 9 that were submitted as part DIO-33, there's enough 10 stress contrast between the confining zones and the 11 disposal zone that the fractures -- whatever fractures 12 that are created in the disposal zone will want to move 13 outward as opposed to upward. That's covered a little 14 bit in later slides too. 15 COMMISSIONER CHMIELOWSKI: Thanks. 16 MR. ALLELY: That's where I'm going to begin. 17 COMMISSIONER WILSON: I'm good on the geology, 18 yeah. 19 MR. STONE: This is Chris Stone again. So I 20 think to answer your question that you had earlier 21 regarding the volumes of fluid injected into the 22 Sterling disposal zone, this shows the history of it 23 dating back to 1998 and approximately 1 million barrels 24 of fluid have been injected into the Sterling disposal 25 zone. I should note that the application that was 0020 1 submitted in August we quoted a volume of about 860,000 2 barrels. The discrepancy between the million and the 3 860 resides back in 1998 and the well B-01, there was 4 about 130,000 barrels that was additionally injected so 5 there's where we see that little bit of discrepancy 6 between our application and what we're illustrating 7 here on the slide. 8 MR. ALLELY: Yeah, Josh Allely. That data 9 about 130,000 barrels of slurry that was injected into 10 B-10A is really not documented anywhere other than in 11 the DIO itself. So when we pulled the injection 12 numbers they're not in any database and so it's just 13 mentioned in the DIO. And so once we saw the error we 14 corrected it indicating that in 1998 we did have that 15 big -- and to also note that was modeled in the 16 fracture modeling that they submitted with the 17 application to DIO-33. 18 COMMISSIONER CHMIELOWSKI: Was that the time 19 that most of the wells were drilled, was that what it 20 was used, disposal during drilling operations? 21 MR. ALLELY: I believe so, but I don't have a 22 lot of historical context on the utilization of that 23 well specifically. 24 MR. STONE: In terms of the historical 25 production, I mean, Tyonek has been on production since 0021 1 the '60s and '70s, right, so there might have been a 2 redevelopment program in the '90s. I can't speak with 3 confidence to answer that specifically. I can provide 4 additional information if that's necessary. 5 But to continue on with this slide..... 6 COMMISSIONER WILSON: Let me interrupt you for 7 just a quick second. Part of my question was also how 8 much -- what -- what it -- volume was like in your 9 class I disposal well. Perhaps that's not as germane 10 since that's in the C-7 sands instead of the sand 11 disposal zone? 12 MR. STONE: Correct. I believe the next slide, 13 slide number 8 should address that. 14 MR. ALLELY: Yeah, so we wanted to give a -- 15 this is Josh Allely, an overview of just what the 16 disposal into the Sterling zone specifically looks like 17 as of right now and then the next slide shows what the 18 total disposal on Tyonek platform looks like with the 19 addition of the A-13 well. And so that is more char -- 20 it's more representative of what's currently happening 21 on the platform today. 22 MR. STONE: Thank you, Josh. So again, Chris, 23 and we're on slide number 8. So this is the current 24 disposal on the Tyonek platform. We're doing about 25 four to 900 barrels a day every four to five days so 0022 1 it's batch injected into our current disposal well, the 2 A-13 into the Sterling -- Cook Inlet 7 sands. So this 3 really gives us a flavor for the volumes that we would 4 be injecting going forward. You see a spike up in 2018 5 and 2019 time frame to about a half million barrels of 6 injected water on an annual basis. At that point in 7 time Tyonek was predominantly producing from the 8 Sterling, the shallower gas sands. These shallower gas 9 sands have a water drive component so water is 10 influxing from the aquifer towards your producers and 11 hence you're getting a larger volume of water with that 12 gas that you're producing. 13 In the recent years starting -- going back to 14 about 2020 Hilcorp has done a redevelopment program on 15 the Tyonek platform. We've gone in since these 16 Sterling big tanks have historically produced since the 17 '60s and they have watered out, they've bypassed some 18 deeper sands, the upper Beluga. So in 2020, '21 and 19 '22 we started to redevelop the upper Beluga sands and 20 these sands to the best of our knowledge at this point 21 in time are depletion drive reservoirs. So depletion 22 drive reservoirs do not have a water component and if 23 there is water it's a very minimal volume of water that 24 is being produced, mainly condensate water that's 25 precipitating out of the gas. So expectations going 0023 1 forward with further development of the platform we 2 would anticipate very similar volumes as we are 3 targeting these upper Beluga sand. 4 And it should be noted that the program going 5 forward we are also looking at a component of these 6 upper Beluga sands, a little bit deeper to try -- trial 7 some sands that have been overlooked in the past that 8 might have potential gas resource in them, but we're 9 uncertain as to whether or not they have a water drive 10 or depletion drive component to it. So that volume 11 that we currently have which is on the order of what, 12 about 50,000 barrels a year, could increase or it might 13 stay steady depending on what we see with the deeper 14 sands and the resources that we're going after. 15 COMMISSIONER WILSON: But at any rate that 16 volume would, I would imagine, still be handled in the 17 A-13 and not in the new well that we're talking about, 18 it's remaining more as a backup? 19 MR. STONE: Correct. That is the intention. 20 We'll predominantly inject into A-13 and if -- for the 21 event that 13 is down for whatever reason we have that 22 backup ability in A-8. 23 COMMISSIONER WILSON: So earlier you partly 24 answered a question in my mind why the need for all the 25 disposal capacity here with the -- you know, the 0024 1 multiple wells that were approved for disposal and the 2 current well. So you answered my question in part like 3 I said with the B-1A, the condition of that well. Do 4 you want to comment just a little bit on the A-12 well, 5 the condition of that and..... 6 MR. STONE: Yes, actually..... 7 COMMISSIONER WILSON: .....its status? 8 MR. STONE: Yes, actually A-12 has -- it's no 9 longer an -- has capacity to inject. We've converted 10 that well, we I think rescinded the DIO for that well 11 for purposes of gas development. Last year we 12 sidetracked a well which was a mechanical failure into 13 the upper Beluga sands. Like I said that was a 14 mechanical failure. This year -- later this year we 15 will be back, we'll have a rig on that well to 16 sidetrack it to continue developing these upper Beluga 17 sands. So that well be used as a producer moving 18 forward. 19 MR. ALLELY: Josh Allely, slide 9. I'll give 20 you a brief rundown of the A-08 well and its current 21 completion configuration. Recently as in 2020 they did 22 an uphole recomplete with a cement with packer. They 23 wanted to target some sands above the existing packer. 24 These would be the Sterling X and Y sands. And so they 25 had coil tubing recomplete perf the X and Y sands and 0025 1 test it and it did not warrant further production. 2 So looking for other opportunities, the well 3 was perfectly positioned to take over disposal capacity 4 that C-01A was currently slated for. And we isolated 5 the X and Y sands with a cast iron bridge plug, 6 pressure tested the bridge plug, perforated the 7 Sterling disposal zone that we've been referencing. 8 This was all as part of a sundry -- group sundry and 9 then did an MITIA after perforating to make sure that 10 the perforation didn't compromise the cement packer and 11 bailed 25 feet of cement on top of the cast iron bridge 12 plug, did a static survey on the zone and it came out 13 to be about a water gradient so normally pressured. 14 And then we proceeded to do an injection test into the 15 disposal zone for injection suitability and got around 16 1,460 psi at one barrel per minute and this -- these 17 results are consistent with recent injection into B-01A 18 and historical injection into A-12. And just to note 19 at the top of good cement an annulus is that 4,010 feet 20 top perf that we're injecting into is at 4,103 which 21 complies with 20 AAC 25.412(b) which says that the 22 packer must be within 200 feet measured depth of the 23 top perf. 24 So looking at the well it looks like it's got 25 integrity, it's healthy and it's all ready to go for 0026 1 disposal should it be approved to do so. 2 COMMISSIONER CHMIELOWSKI: So you did an 3 injection test at about 1,500 psi, but is that the 4 injection pressure you would expect in this well? 5 MR. ALLELY: It -- it's a little higher than 6 we'd expect, but..... 7 COMMISSIONER CHMIELOWSKI: Hmmm. 8 MR. ALLELY: .....it's also consistent with 9 previous wells. And so..... 10 COMMISSIONER CHMIELOWSKI: Okay. 11 MR. ALLELY: .....we -- there's a slide 12 discussing the injection -- injectivity test a little 13 more. I'm sure it'll -- there'll be a little more 14 discussion around it, like yeah, it is a little higher. 15 So slide 10 is an annotated bond log. This is 16 a bond log of the -- basically what we're looking at in 17 that bond log, going back to slide 9, just showing you 18 that we're looking at this cement outside. We're not 19 looking at this annular cement, we do have that bond 20 log as well, but what we're looking at is the seven 21 inch cement which is basically isolating us from the -- 22 the upper zones when we inject. And so what we see 23 from this log is good cement all through the confining 24 zone and through the disposal zone. You can see this 25 is the entire sand package of the confining zone, top 0027 1 disposal zone here, down where our perfs are at 4,103 2 roughly and here's the base of the disposal zone 3 showing you the base of the confining layer. And so 4 it's pretty cut and dry, but I thought this was a good 5 illustration of where we're at in the well and where 6 the perforations are. 7 COMMISSIONER CHMIELOWSKI: So you're showing 8 good cement across both confining zones as well as the 9 disposal? 10 MR. ALLELY: Yeah. 11 COMMISSIONER CHMIELOWSKI: Okay. 12 COMMISSIONER WILSON: And then it looks like -- 13 so the injection test at a barrel per minute, 1,271 14 barrels, so that's like a little less than a day so 15 that far exceeds the capacity that you -- your needs 16 for injection disposal right now, correct? 17 MR. ALLELY: That is correct. 18 MR. STONE: So as with all disposal 19 applications and other types of injection the AOGCC 20 likes to see an area of review where we look at a 21 quarter mile radius of any wells that penetrate through 22 the disposal zone and with the mechanical condition and 23 cement and the cementing of the casing on those wells. 24 And so we did -- I mean, this is submitted through the 25 application, not much to note here other than for the 0028 1 most part all the cement of the wells within this 2 radius were good with the exception of A-03A. So A-03 3 which is the parent well had good cement so when they 4 sidetracked A-03A they were not able to get cement all 5 the way up above the liner top packer. So there's a 6 small section of exposed openhole that doesn't have 7 cement across it, but as you can see that is kind of on 8 the fringe here and at the kind of volumes we're 9 planning on injecting, I can't see any reasonable 10 scenario where it -- disposed fluid gets over to that 11 A-03A well. 12 We're looking at all the other wells, they all 13 appear to have good cement and the -- good coverage 14 across the disposal zone. We can go over that in more 15 detail if you want, but it's all in the -- in the 16 application. That was slide 11 by the way. 17 In slide 12 we have a discussion of the 18 injection test and the injectivity results. We did a 19 recent injectivity test at around a barrel per minute, 20 1,450 psi and as noted while the injection pressure's a 21 bit high it's also consistent with injection pressures 22 into the other disposal wells. Just looking at a quick 23 comparison of A-12, this plot here was submitted as 24 part of the application for DIO-33 and it just shows 25 basically several years of injection where A-12 was 0029 1 running at about 1,400 psi at various rates. We see a 2 lot of similarities in injectivity. And then back to 3 what we're requesting as far as injection pressure and 4 injection rate, DIO-17, Rule 5 and DIO-33, Rule 3, 5 allow a max injection pressure of 2,500 psi. DIO-33 6 allowed a max injection rate of 2.4 barrels per minute. 7 These rates and pressures were based on the fracture 8 modeling submitted with the prior DIO application. And 9 so hopefully we've demonstrated that the disposal zone 10 and confining layers are very similar to the other two 11 wells. And looking at the fracture modeling was 12 submitted with DIO-33, we see no reason to update the 13 model or request any different pressure and rate limit 14 that weren't previously approved for A-12 and C-01A. 15 COMMISSIONER WILSON: Can you speak to the 16 potential of this well being a backup if your class I 17 injector is down and the rates and amount of 18 injectivity into that well if it came to this well what 19 that might equate into top pressures? 20 MR. STONE: We would be injecting far less than 21 we did during our injection test. So if for some 22 reason we do have to use this well we anticipate just 23 like in A-13 doing five to 900 barrels every five days 24 or so. And so usually just do it in a big batch. And 25 it would likely be at around a barrel per minute 0030 1 because that's what the pumps are just set up for. And 2 so I see no change. If we have to move from A-13 to A- 3 8 the injection will be almost identical. 4 COMMISSIONER WILSON: Thank you. 5 MR. STONE: So that's all our slides. I can 6 answer any questions. 7 CHAIRMAN HUBER: Questions from fellow 8 Commissioners. 9 COMMISSIONER CHMIELOWSKI: Yeah, question. How 10 will ensure that no class I waste is injected into this 11 class II well A-8? 12 MR. STONE: Well, we do have -- well, the short 13 answer is we don't inject any class I waste into A-13 14 so it makes it easy to make sure that no class II waste 15 goes into A-8. But beyond that we have -- the 16 operators know before they inject anything outside of 17 what they normally inject to always consult with the 18 Well Integrity Engineer position to make sure that what 19 they're injecting is suitable for class II disposal. 20 So I think between those two safeguards that pretty 21 much assures that there's not going to be any 22 misinjection. 23 COMMISSIONER CHMIELOWSKI: Is there a manifest 24 kept of injection into the class II well? 25 MR. STONE: We do track. I don't know to what 0031 1 extent we track. I know we track volumes, but I'm not 2 sure if we're tracking specific types of fluid. I can 3 follow-up on that. 4 COMMISSIONER CHMIELOWSKI: Why was there a 5 class I well to begin with if there's no class I waste? 6 MR. STONE: I believe that before Hilcorp 7 purchased the platforms the prior operator did not have 8 access to a class I disposal well and so they needed 9 that, but now we have plenty of class I disposal wells 10 and so there's not a huge reason that we would need to 11 utilize it for a class I disposal well. And it's -- 12 and you say well, why is it still a class I disposal 13 well, why not class II. It's very difficult to get rid 14 of a class I EPA permit once you have it because you 15 have to tell them what you want to do for the entire 16 life of the well. And as soon as you stop injecting 17 class I waste they expect you to abandon the well 18 immediately. You can't just say hey, we want to cancel 19 your permit and oh, by the way, we don't want to touch 20 the well. The EPA will then require you to see to the 21 abandonment. So you kind of have to keep that class I 22 permit until the well's done. 23 COMMISSIONER CHMIELOWSKI: Well, that answers 24 my other question I guess why you're not applying for 25 another class I well is because there's no class I 0032 1 waste on the platform? 2 MR. STONE: Correct. There's just no reason 3 for it and a class II application is sufficient for us. 4 COMMISSIONER CHMIELOWSKI: So there's been a -- 5 like a recent drilling campaign on this platform with 6 varying degrees of success. If there any well 7 integrity issues that have been introduced from some of 8 these wells that have been plugged back or for, you 9 know, sidetracks, are any of them in this area of 10 review for this disposal well? 11 MR. STONE: No, I don't believe so although I 12 think you guys did comment on that. 13 MR. PETROWSKY: This is Matt Petrowsky. I 14 think this is slide 11. Yeah, so the A-1A on this map 15 here and the A-3A are recent sidetracks of -- within 16 the last two years. The short answer is no integrity 17 issues with our wells. You know, all wells except for 18 the A-12A well were -- actually have been successes. 19 That well as Chris mentioned earlier had a mechanical 20 failure, but no integrity issues. 21 COMMISSIONER CHMIELOWSKI: Okay. And I don't 22 have it in front of me, but I'm just thinking of A-1A 23 and that well had a plugback. And just want -- just 24 trying to ensure that, you know, there wasn't a bunch 25 of open rathole, you know, below the plug or something 0033 1 if you know that at the end of that well went before 2 sidetracking again? 3 MR. PETROWSKY: Yeah, I can't quite recall, but 4 I know that, you know, once it was properly abandoned 5 and sidetracked, I mean, A-1A has been online for us 6 and is successful over the last few years. So I 7 can..... 8 COMMISSIONER CHMIELOWSKI: Okay. So that -- 9 that one is finished for..... 10 MR. PETROWSKY: Yeah. 11 COMMISSIONER CHMIELOWSKI: Okay. Great. 12 MR. PETROWSKY: I just can't -- I can't 13 recall..... 14 COMMISSIONER CHMIELOWSKI: I couldn't remember. 15 MR. PETROWSKY: .....specifically if..... 16 COMMISSIONER CHMIELOWSKI: Yeah. 17 MR. PETROWSKY: .....what that issue was. 18 COMMISSIONER CHMIELOWSKI: Okay. 19 MR. PETROWSKY: Yeah. 20 COMMISSIONER CHMIELOWSKI: Okay. Thank you. 21 And just to confirm Hilcorp is aware this is not a 22 commercial use well, it's only for use of fluids from 23 the unit? 24 MR. ALLELY: Correct. Josh Allely. Yeah, that 25 -- that is correct. 0034 1 COMMISSIONER CHMIELOWSKI: Okay. I don't have 2 any questions right now, any more. 3 CHAIRMAN HUBER: Commissioner. 4 COMMISSIONER WILSON: I have nothing 5 additional. 6 CHAIRMAN HUBER: Thank you, gentleman. We'll 7 take just a quick at ease. 8 (Off record) 9 (On record) 10 CHAIRMAN HUBER: Back on the record. We'll go 11 ahead and take a 15 minute break, give us an 12 opportunity to confer with Staff, make sure that we've 13 covered everything that we care to. 14 Thank you. Back on the record in 15. 15 (Off record) 16 (On record) 17 CHAIRMAN HUBER: Back on the record at 11:04. 18 Thank you for your patience and giving us a moment. We 19 did confer with Staff and I do believe have 20 Commissioners with a couple follow-up questions for you 21 gentlemen. 22 COMMISSIONER CHMIELOWSKI: Well, I drew the 23 short straw. I'm asking the questions. So you guys 24 talk about your injection test being up to about 1,500 25 pounds yet you're asking for 2,500 pounds like in the 0035 1 previous DIOs. So does the frack model that was used 2 as a basis for DIO-33, does that model go up to 2,500 3 pounds and if it did what did it show? 4 MR. ALLELY: Josh Allely: I -- I'll show you 5 the slide. I brought one of the frack modeling slides. 6 7 COMMISSIONER CHMIELOWSKI: Is your green light 8 on? 9 MR. ALLELY: Sorry. 10 COMMISSIONER CHMIELOWSKI: Yeah, okay. 11 MR. ALLELY: Yeah, my green light is on. I 12 know there's a lot of text here, but basically when 13 they modeled this, they modeled it with..... 14 COMMISSIONER CHMIELOWSKI: What slide are we 15 on? 16 MR. ALLELY: We're on slide 20. 17 COMMISSIONER CHMIELOWSKI: Those are your 18 backup slides? 19 MR. ALLELY: Yeah, backup slides. 20 COMMISSIONER CHMIELOWSKI: Okay. 21 MR. ALLELY: So the modeling they did -- when 22 you model something in the frack model you don't really 23 tell it what pressure to pump at, you say here's the 24 rock properties, here's the stresses, here's the pump 25 schedule and here's the viscosity of the fluid and it 0036 1 comes up with where it thinks the fracture is going to 2 go based on that model. And so -- and it really 3 doesn't look -- generally you're not looking at what's 4 happening at surface, you're having -- looking at 5 what's happening at the rock face itself, past the 6 cement, past the damage. And so based on whatever the 7 inputs -- I'm sorry. Based on the inputs, they 8 basically saw no out of zone injection, but they don't 9 tell you what we expected to see as a surface pressure. 10 Most of the literature that was put in for DIO-17 and 11 33 shows a frack gradient for that zone, a closure 12 pressure -- let me get that slide out here, a sand face 13 pressure of about 2,300 psi which would equate to a 14 surface pressure of 930 psi if water was used as a more 15 -- most likely closure pressure for the disposal zone. 16 Why we're seeing higher pressures than that, more than 17 likely it's just near wellbore tortuosity to get to the 18 rock with my -- what I would expect. We're going 19 through two strings of pipe, two annuli full of cement 20 and whatever formation damage just to get to the rock 21 itself. That's what I would explain, the higher 22 pressures. 23 And so what we've seen in the injection test 24 like I said before is very similar and we -- looking at 25 this model and the rock properties they use, they're 0037 1 well in line with what I would have used if I ran the 2 model myself. So I really don't have much to add to 3 the model. When they ran the model they modeled it 4 pumping just an extreme amount of fluid. Basically the 5 150,000 barrels of slurry followed by one barrel per 6 minute for a year then followed by another 60,000 7 barrels of slurry and those are the fractures that they 8 observed via the model. I don't have a good answer for 9 you on why we were seeing -- why we're seeing 10 historically higher -- slightly higher pressures other 11 than sometimes to get to the fracture itself you have 12 to cross quite a bit of stuff that creates friction. 13 COMMISSIONER CHMIELOWSKI: So are you saying 14 that the model that was used years ago for DIO-33 you 15 still think that that data's valid and that 2,500 psi 16 injection pressure won't be fracking? 17 MR. ALLELY: It will be fracking the zone for 18 sure..... 19 COMMISSIONER CHMIELOWSKI: But not the 20 confining layers? 21 MR. ALLELY: .....oh, but not the confining 22 layers. And so when they ran this model once again it 23 doesn't give you what -- what your anticipated surface 24 pressure is because it doesn't know what kind of near 25 wellbore tortuosity you're going to go through that 0038 1 calculate what the surface pressure is. It -- the 2 model just looks at the rock face itself. But I don't 3 see anything in the data or the model they used that I 4 would update. And they -- they modeled it using the 5 2.4 barrels per minute and like I said before it -- 6 that all looks reasonable to me. 7 COMMISSIONER CHMIELOWSKI: Okay. I just want 8 to get on the record that what has been granted and 9 what Hilcorp is asking for today hasn't been tested via 10 an injection test. So just want to ensure this older 11 model is still valid in Hilcorp's point of view to 12 ensure in zone injection. 13 MR. ALLELY: Yeah, and you'll note that they 14 said the revised fracture modeling used a 14.46 tbd 15 leak-off test and there have been subsequent leak-off 16 tests in the zone. And..... 17 You can speak to that. 18 MR. PETROWSKY: Yeah, this is Matt Petrowsky. 19 You know, over the course of the last two years via all 20 the sidetracks, roughly within a few hundred feet of a 21 disposal zone we have seven different fit tests ranging 22 from 14.7 to 15.7 pounds per gallon equivalent. So all 23 seems to be well in line with what they modeled. 24 COMMISSIONER CHMIELOWSKI: Okay. So a question 25 about the redevelopment plans out here. You say, you 0039 1 know, it's unknown what fluids you guys might receive 2 as -- you know, as a result of drilling all these 3 sidetracks. Do you have a range like a low and a high, 4 is there any chance that you get back to those really 5 high years of water injection? 6 MR. STONE: I -- this is Chris, the Reservoir 7 Engineer. So at present our development program 8 consists of the Beluga sand, predominantly the wells 9 that we drilled in the last few drill seasons have been 10 the upper Beluga A through G sand. And like I 11 mentioned before they are all depletion drive 12 reservoirs. The future development including this year 13 we are drilling deeper into some of the lower -- what 14 we consider the lower Beluga sand. Historically in the 15 past when ConocoPhillips or Conoco -- the prior 16 operators were developing this field they were not 17 successful at getting some of these deeper lower Beluga 18 sands to flow. Earlier this spring in the B-02 19 wellbore we had access to some of the lower Beluga sand 20 and we shot the Beluga L and it brought in gas. So 21 hence the future development that Matt and I have 22 proposed for this field includes some of that lower 23 Beluga. We don't have a really strong understanding of 24 what the lower Beluga entailed, if they are water drive 25 components or depletion drive so I guess there is a 0040 1 level of uncertainty associated with how much water we 2 could anticipate. Typically in a gas well if you do 3 bring in water it's going to load up the well. These 4 sands out here, they're not at virgin pressures any 5 more. We don't have a solid understanding, we will at 6 the end of this drill season as we get RFT pressures in 7 the Beluga sands to understand what the current 8 reservoir pressures are. So typically when water comes 9 in the wellbore it loads it up and we will set a plug 10 to isolate that and hope that we have sufficient 11 offtake above it to unload those wells. 12 So going forward there's a little level of 13 uncertainty associated with what that lower Beluga 14 could bring in terms of an overall water volume, but 15 when you compare that -- if you can go back in the 16 slide deck to what we see historically, I think that's 17 on slide number 8, where we've seen -- you know, this 18 has been predominantly Sterling production all the way 19 up into the 2020 time frame, 2018, 2019 is -- it 20 appears to be an anomalous data point. I don't 21 anticipate the Beluga sands competing in terms of an 22 overall volume and deliverability when you talk about 23 the Sterling sands, the big blocky, one to two darcy 24 kind of rock when we're dealing with a less permeable 25 rock so the inflow and the pressures should not be as 0041 1 great. So I can't anticipate seeing volume as high as 2 what we've historically seen. 3 COMMISSIONER CHMIELOWSKI: Okay. So just to -- 4 you're thinking really no chance of getting that high 5 this -- maybe higher than it is now? 6 MR. STONE: Maybe higher than..... 7 COMMISSIONER CHMIELOWSKI: Maybe double or 8 something like that? 9 MR. STONE: Correct. 10 COMMISSIONER CHMIELOWSKI: Yeah, okay. 11 MR. STONE: But not to the order of magnitude 12 of what we've historically seen..... 13 COMMISSIONER CHMIELOWSKI: Okay. 14 MR. STONE: .....with the Sterling production. 15 COMMISSIONER CHMIELOWSKI: Okay. Thanks. Go 16 ahead. 17 COMMISSIONER WILSON: Well, I just -- when you 18 talk about depletion drive, you know, despite being on 19 the structure you're not tapping into a deep aquifer 20 then and something limited stratigraphic extent, is 21 that what you're talking about basically or..... 22 MR. PETROWSKY: Yeah, this is Matt Petrowsky. 23 Yeah, I would agree with that. I mean, sort of the 24 gist of it in my mind is, you know, the Sterling 25 produces a lot of water, the rock quality is 0042 1 significantly greater than the Beluga sand, you know, 2 higher perms, higher porosities. Beluga sand's not 3 only atonic here, but sort of all around the Cook 4 Inlet, you know, a lot of -- more of a clay rich 5 system, tighter rock, lower perms, inevitably low 6 porosities, you know, we've been able to unlock that 7 and so that's kind of our future goal. As we go deeper 8 in the stratigraphic formation it's still the Beluga, 9 you know, with that comes, you increased tightness, 10 lower perms. So even if we were to perf into let's say 11 kind of a virgin pressure, water, as Chris alluded to 12 it would easily kill our well and we'd probably just be 13 plugging it back immediately and going to another zone. 14 So I would say, you know, if we do see water in the 15 deeper zones it would be very minimal time frame that 16 we would produce that water before we kind of move on 17 because it wouldn't benefit anything else in that well. 18 COMMISSIONER CHMIELOWSKI: Okay. So my last 19 sort of line of questions has to do with the wells in 20 the areas of review and in particular A-3, A-3A which 21 is the one you've identified as not having cement 22 across the injection interval; is that correct. 23 MR. ALLELY: Josh Allely. Yes, that's correct. 24 COMMISSIONER CHMIELOWSKI: Okay. So the 25 question is just say the injection plume reached A-3A 0043 1 or A-3, the parent, is there a way to monitor that, 2 does it have a monitorable annulus? 3 MR. ALLELY: No, because they kicked out -- out 4 of the casing in cement and they tied that back. And 5 so whatever would be going on in that section of 6 uncemented pipe would just be crossflow and you have no 7 way of monitoring it per se. 8 COMMISSIONER CHMIELOWSKI: Okay. 9 MR. ALLELY: I don't have a good picture I 10 could show you, but it's just the way the sidetrack was 11 completed and the way they tied back the liner. Up 12 above that is the liner top packer so you really can't 13 monitor it. 14 COMMISSIONER CHMIELOWSKI: Right. So when the 15 -- in the parent well where it was sidetracked was in 16 -- had good cement outside? 17 MR. ALLELY: Correct. 18 COMMISSIONER CHMIELOWSKI: Okay. And so can 19 you estimate and probably can't do this today, but 20 estimate how many barrels it would take for a plume to 21 reach that well A-3A or A-3? 22 MR. ALLELY: Yeah, I actually meant to do that 23 calculation. Doing it off the top of my head I figure 24 it's..... 25 COMMISSIONER CHMIELOWSKI: Yeah. 0044 1 MR. ALLELY: .....quite high. 2 COMMISSIONER CHMIELOWSKI: That's what we 3 thought too, but we would like to have that figure just 4 so we knew..... 5 MR. ALLELY: Probably should..... 6 COMMISSIONER CHMIELOWSKI: .....how many 7 barrels would it take for the plume to reach that well 8 considering it's not monitorable and it's not covered 9 in the area of review. 10 MR. ALLELY: We can get that. 11 COMMISSIONER CHMIELOWSKI: And you can take as 12 much time as you need, we'll just leave the record 13 open. So we can do that before we close out the 14 hearing. I think that's all the questions we have; is 15 that correct, you guys? 16 COMMISSIONER WILSON: Just one other curiosity. 17 What do you do with your class I only waste at the 18 platform? 19 COMMISSIONER CHMIELOWSKI: Oh, right. We were 20 thinking is it -- is it a camp, like is it a manned 21 platform so there must be some waste associated with a 22 camp, is there an overboarding permit? 23 MR. ALLELY: Yeah, there's a lot of platform so 24 I just think I'm confused. But the class I waste 25 generated would just be black and gray water and for 0045 1 that I'd had to look up exactly what Tyonek does with 2 that, their waste stream. So I apologize for not 3 having that off the top of my head. I can add that to 4 the list. 5 COMMISSIONER CHMIELOWSKI: Yeah, that would be 6 great if we knew if there's a man camp where does that 7 class I waste go. Yeah. 8 Sorry to interrupt you, Commissioner Wilson. 9 COMMISSIONER WILSON: That's all for me, 10 thanks. 11 COMMISSIONER CHMIELOWSKI: So I guess before we 12 close out this line of questioning, how much time would 13 you guys like to get that information back to us? 14 MR. STONE: I think we can get that data to you 15 within two weeks, probably even sooner. I don't want 16 to..... 17 COMMISSIONER CHMIELOWSKI: Sure. 18 MR. STONE: .....commit people to things they 19 can't do though. 20 COMMISSIONER CHMIELOWSKI: Yeah, we can just 21 set a time. We just -- it's about keeping the record 22 open. So two weeks from today is October 24th or we 23 could just go to the Friday, close of business October 24 27th, that's a Friday. 25 MR. STONE: Sounds good. 0046 1 COMMISSIONER CHMIELOWSKI: Sure. Okay. And 2 you can always give it earlier, but we'll keep the 3 record open. 4 MR. STONE: More than likely we'll give it to 5 you earlier..... 6 COMMISSIONER CHMIELOWSKI: Okay. 7 MR. STONE: .....it should be pretty quick to 8 get these numbers to you. 9 COMMISSIONER CHMIELOWSKI: Okay. So we'll do 10 close of business Friday, October 27th. 11 Thank you. 12 CHAIRMAN HUBER: Additional questions from the 13 Commissioners. 14 (No comments) 15 CHAIRMAN HUBER: Seeing none, we move to the 16 important part of today's proceedings which is the 17 opportunity for the public to provide testimony and 18 share comments with the Commission. It should be noted 19 that there's a varying level of participation by the 20 public in our hearings often dependent on topic or 21 subject matter or the area that operations are taking 22 place. But regardless the Commission takes it very 23 seriously and wants to provide every opportunity we can 24 to have the public interface with this Commission as we 25 are doing their bidding within our tasks and our 0047 1 underlying statutes and regulations. 2 So, I believe, Samantha, we have nobody in the 3 room set to testify that has not been heard from. 4 MS. CARLISLE: That's correct. 5 CHAIRMAN HUBER: Okay. And but we do have some 6 people monitoring online. So what we'll do for this 7 portion is allow an opportunity for anybody that wishes 8 to comment online remotely on Teams the code to unmute 9 if you're listening along is star, six. If you have 10 any technical difficulties while unmuting you can call 11 907-793-1223 or send a chat message via the Teams. And 12 it sometimes takes a minute for folks at home to figure 13 out how to unmute and get online. So we're going to 14 pause for about 60 seconds. This is the first call for 15 those online for today's AOGCC hearing on this DIO to 16 provide public testimony and we'll wait for you to 17 identify yourself and then ask you to speak to the 18 topic. 19 (No comments) 20 CHAIRMAN HUBER: Again this is a call for 21 public testimony for those online for the AOGCC hearing 22 today and the star, six option will unmute you so 23 you're able to speak with the Commission if you're 24 interested in testifying. 25 (No comments) 0048 1 CHAIRMAN HUBER: Hearing nobody interested in 2 testifying today I will note that we do -- have been -- 3 have not received yet, but will continue to accept 4 written testimony as long as the record is open. We 5 did talk about the record remaining open today for some 6 answers to a couple of the Commission's questions and 7 follow-up from the operator. We will remain open for 8 the record on this issue until the 27th, close of 9 business, that's Friday the 27th, close of business. 10 Anything further, comments from either of the 11 Commissioners. 12 COMMISSIONER CHMIELOWSKI: No, thank you. 13 COMMISSIONER WILSON: Nothing from me. 14 CHAIRMAN HUBER: So I'd like to thank everybody 15 for their interest in the AOGCC's business and the 16 hearing today. I thank you to the three 17 representatives from Hilcorp, appreciate your 18 presentation, following along with the slides, the 19 questions and answers to the questions that we had. 20 Do we have any other business to come before 21 the Commission today? 22 (No comments) 23 CHAIRMAN HUBER: Seeing none, it is now 10:23 24 and..... 25 COMMISSIONER CHMIELOWSKI: 11:23. 0049 1 CHAIRMAN HUBER: I'm sorry, it is now 11:23, 2 thank you, Jessie, and we will adjourn the meeting. 3 (Hearing adjourned - 11:23 a.m.) 4 (END OF PROCEEDINGS) 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 0050 1 TRANSCRIBER'S CERTIFICATE 2 I, Salena A. Hile, hereby certify that the 3 foregoing pages numbered 02 through 50 are a true, 4 accurate, and complete transcript of proceedings in 5 Docket No.: DIO-23-003, transcribed under my direction 6 from a copy of an electronic sound recording to the 7 best of our knowledge and ability. 8 9 _______________ _______________________________ 10 DATE SALENA A. HILE, (Transcriber) 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Hilcorp Christopher Stone (Reservoir Engineer) Matt Petrowsky (Geologist) Josh Allely, PE (Integrity Engineer) Application to Convert NCIU A-08 to Disposal 2 Background •Application request to convert NCIU A-08 to a Class II disposal well •Current AEO #4 exempts aquifers below 2900’ MD (NCIU A-12 reference) •Tyonek Platform has historically had two disposal wells •Most recently A-13 & B-01A have been used for disposal •A-13 (Class I Disposal Well) receives most of the injection which is produced water •B-01A Wellbore •Non-ideal well for disposal due to wellbore configuration •Better utility as a future gas producer via a sidetrack •A-08 Wellbore •No remaining economic value as a producer •More conventional configuration for pressure monitoring and testing (no need for variance or waiver) •Same sand as A-12 (DIO 17) and B-01A (DIO 33) •Our goal is to replace B-01A with A-08 and utilize A-08 as the backup to A-13 3 Sterling Top Disposal Zone - Structure Map A A’ 4 Historic Injection Wells Cross Section A A’ 5 Historic Injection Wells Cross Section A A’ 6 Historic Injection Wells Cross Section A A’Disposal Zone 7 Sterling Disposal Zone History ~1,002,080 bbls of fluid have been injected into Sterling disposal zone (since 1998) 0 20,000 40,000 60,000 80,000 100,000 120,000 140,000 160,000 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023BBLS OF WATER (ANNUAL)Annual Disposal Injection into Sterling Disposal Zone N COOK INLET UNIT A-12 N COOK INLET UNIT B-01A 8 Tyonek Platform Disposal History 0 100,000 200,000 300,000 400,000 500,000 600,000 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023BBLS OF WATER (ANNUAL)Total Annual Disposal for the Tyonek Platform N COOK INLET UNIT A-12 N COOK INLET UNIT B-01A N COOK INLET UNIT A-13 Current disposal on the Tyonek platform is 400-900 bbls every 4-5 days, all into A-13 9 Recent A-08 History Recent Work for Disposal Operations 7/3/20: Uphole recomplete with cement packer 7/10/20: Sterling X and Y sands perf’d and tested 3/9/23: Set CIBP at 4231’ MD (isolated Sterling X & Y sands) 3/14/23: MIT CIBP to 1745 psi. 3/18/23: Perf 4103-4121 MD & 4126-4180’ MD 3/20/23: MIT-IA to 1500 psi 3/20/23: Dump bailed 25’ of cement on CIBP 3/28/23: SBHPS – 1446 psi at 3348 TVD 0.43 psi/ft & 8.3 ppg. 3/29/23: Injection test 1460 psi at ~1.0 bpm for 1271 bbls (consistent with recent injection into B- 01A and historical injection into A-12) Top of good cement in annulus at 4010’ MD Top perf at 4103’ MD Complies with 20 AAC 25.412 (b) 10 A-08 Annotated Bond Log (23-JUL-69) 11 Area of Review 12 A-08 Injection Test 0.00 0.20 0.40 0.60 0.80 1.00 1.20 0 200 400 600 800 1000 1200 1400 1600 1800 0 200 400 600 800 1000 1200 1400 Rate [BPM]Pressure [psi]Minutes NCIU A-08 Disposal Injection Test Injection Pressure IA Pressure Pump Rate [BPM] Injectivity Test Results •A recent injectivity test was performed at a rate of ~1.0 bpm with a resulting injection pressure of 1450 psi. •These results were consistent with recent injection results in B-01A as well as the findings and conclusions in DIO 17 and DIO 33 •Both DIO 17 [Rule 5] and DIO 33 [Rule 3] allowed a max injection pressure of 2500 psi. •DIO 33 [Rule 3] allowed a max injection rate of 2.4 bpm •Rates and pressures based on the fracture modeling submitted with the prior DIO applications •Hilcorp is requesting these same limits and finds the fracture modeling on B-01A to be applicable to A-08 13 Backup Slides 14 NCIU A-01A – 12 Month TIO Plot 15 NCIU A-03A - 12 Month TIO Plot 16 NCIU A-13 – 12 Month TIO Plot 17 NCIU A-16 - 12 Month TIO Plot 18 NCIU B-02 – 12 Month TIO Plot 19 A-08 4-1/2” x 7” Annulus Cement RCBL 20 Fracture Modeling for B-01A 21 A-08 Perofration History 4 From:Wallace, Chris D (OGC) To:Carlisle, Samantha J (OGC); Roby, David S (OGC); McLellan, Bryan J (OGC); Davies, Stephen F (OGC); Dewhurst, Andrew D (OGC); Chmielowski, Jessie L C (OGC); Huber, Brett W (OGC); Wilson, Greg C (OGC); Guhl, Meredith D (OGC) Subject:FW: [EXTERNAL] FW: Public Hearing Notice, Docket Number: DIO-23-003 (NCIU) Date:Monday, October 9, 2023 9:10:02 AM Attachments:NCIU A-08 DIO Application_Signed_CRR(8-18-23).pdf For the meeting today, and the DIO hearing tomorrow, I sent this email to remind Hilcorp last week. Regards Chris From: Wallace, Chris D (OGC) Sent: Thursday, October 5, 2023 4:26 PM To: Ryan Rupert <Ryan.Rupert@hilcorp.com> Cc: Dan Marlowe <dmarlowe@hilcorp.com>; Josh Allely - (C) <Josh.Allely@hilcorp.com>; Casey Morse <Casey.Morse@hilcorp.com>; Trudi Hallett <thallett@hilcorp.com>; Matthew Petrowsky <mpetrowsky@hilcorp.com>; Christopher Stone <Christopher.Stone@hilcorp.com>; Juanita Lovett <jlovett@hilcorp.com>; Cody Terrell <cterrell@hilcorp.com> Subject: RE: [EXTERNAL] FW: Public Hearing Notice, Docket Number: DIO-23-003 (NCIU) Ryan, As far as I know we have not received comments from the public. The commissioners may ask why this isn’t being permitted as a Class I well - and anything else they feel relevant (like why apply now, what activity prompted this, ongoing plans and activity in general… etc)??? I would like to see Hilcorp prepared to show the maps with the nearby wells and other disposal wells location within the disposal zone (to reiterate that the A-08 well (as completed for disposal) will be into an existing established disposal zone…Any problems with the zone, volumes disposed of to date, etc. I would like to hear a bit more about 20 AAC 25.252(c)(8) estimated injection pressures as recent DIO’s have tried to establish a surface pressure and rate to represent a permissible sandface pressure (for different fluid densities but primarily based on water) to ensure the sandface pressure is below the fracture gradient/ or is unable to propagate fractures as required by (9) is met…Maybe the injectivity testing performed shows/confirms fracture gradient. I would like to have some additional operator friendly guide like maximum surface injection pressure is ???psi with a maximum injection (water) of ?? bbl/min. If you have reviewed the last few DIO’s and if you want to propose the disposal A-08 rules that is appropriate – or if you are requesting waivers/variances from the regulations (I didn’t see any) then you could request/clarify during the hearing. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 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. Regards Chris From: Ryan Rupert <Ryan.Rupert@hilcorp.com> Sent: Thursday, October 5, 2023 2:25 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Dan Marlowe <dmarlowe@hilcorp.com>; Josh Allely - (C) <Josh.Allely@hilcorp.com>; Casey Morse <Casey.Morse@hilcorp.com>; Trudi Hallett <thallett@hilcorp.com>; Matthew Petrowsky <mpetrowsky@hilcorp.com>; Christopher Stone <Christopher.Stone@hilcorp.com>; Juanita Lovett <jlovett@hilcorp.com>; Cody Terrell <cterrell@hilcorp.com> Subject: RE: [EXTERNAL] FW: Public Hearing Notice, Docket Number: DIO-23-003 (NCIU) Thanks Chris. Any public comments received yet? If so, is there anything in particular that we should prepare for? Ryan Rupert CIO Ops Engineer (#13088) 907-301-1736 (Cell) 907-777-8503 (Office) From: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Sent: Thursday, October 5, 2023 8:46 AM To: Ryan Rupert <Ryan.Rupert@hilcorp.com> Subject: [EXTERNAL] FW: Public Hearing Notice, Docket Number: DIO-23-003 (NCIU) Ryan, AOGCC has the hearing for this application scheduled for next week. The commissioners will be interested in an overview of the request, potential rules, variance requests etc, well condition, and how this fits into Hilcorp’s overall plans. If you need examples of previous DIO applications, our website has DIOs at http://aogweb.state.ak.us/WebLinkSearch with the last one being DIO 45 issued April 18, 2022 or from aogcc.customer.svc@alaska.gov which can give you access to the previous DIO hearing presentations and testimony. Thanks and Regards, Chris Wallace, Sr. Petroleum Engineer, Alaska Oil and Gas Conservation Commission, 333 West 7th Avenue, Anchorage, AK 99501, (907) 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: Carlisle, Samantha J (OGC) <samantha.carlisle@alaska.gov> Sent: Thursday, September 7, 2023 3:20 PM To: AOGCC_Public_Notices <AOGCC_Public_Notices@list.state.ak.us> Subject: [AOGCC_Public_Notices] Public Hearing Notice, Docket Number: DIO-23-003 (NCIU) Hilcorp Alaska, LLC (Hilcorp), by letter dated August 9, 2023, filed an application to the Alaska Oil and Gas Conservation Commission (AOGCC) for a Class II Underground Injection Control Disposal Injection Order for well A-08 on the Tyonek Platform in the North Cook Inlet Unit (NCIU). Samantha Carlisle Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: chris.wallace@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/chris.wallace%40alaska.gov 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 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 the onward 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 CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. You don't often get email from jlovett@hilcorp.com. Learn why this is important From:Wallace, Chris D (OGC) To:Carlisle, Samantha J (OGC) Cc:Huber, Brett W (OGC); Roby, David S (OGC); Davies, Stephen F (OGC) Subject:FW: [EXTERNAL] FW: N Cook Inlet Unit A-08 PTD: 169-063 - DIO Application Date:Monday, October 9, 2023 10:25:27 AM Attachments:NCIU A-08 Affidavit_2023-08-25.pdf NCIU A-08 DIO Application_Signed_CRR(8-18-23).pdf From: Juanita Lovett <jlovett@hilcorp.com> Sent: Friday, August 25, 2023 11:21 AM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Ryan Rupert <Ryan.Rupert@hilcorp.com> Subject: RE: [EXTERNAL] FW: N Cook Inlet Unit A-08 PTD: 169-063 - DIO Application Mr. Wallace, Please see attached signed affidavit. Feel free to contact us if you have additional questions. Thank you, Juanita L Lovett Sr. Operations/Regulatory Tech Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 | Anchorage | AK | 99503 (907) 777-8332 | jlovett@hilcorp.com From: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Sent: Tuesday, August 22, 2023 3:56 PM To: Juanita Lovett <jlovett@hilcorp.com> Cc: Ryan Rupert <Ryan.Rupert@hilcorp.com> Subject: [EXTERNAL] FW: N Cook Inlet Unit A-08 PTD: 169-063 - DIO Application Juanita, Ryan, AOGCC has received this DIO application and, upon initial review, it appears that your response to 20 AAC 25.252(c)(3) is deficient. 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. Please provide the signed affidavit showing that DNR has been provided a copy of the application. We will add it to the application and continue our processing. Thanks and Regards, Chris Wallace, Sr. Petroleum Engineer, Alaska Oil and Gas Conservation Commission, 333 West 7th Avenue, Anchorage, AK 99501, (907) 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: Juanita Lovett <jlovett@hilcorp.com> Sent: Friday, August 18, 2023 11:19 AM To: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov> Cc: Ryan Rupert <Ryan.Rupert@hilcorp.com> Subject: N Cook Inlet Unit A-08 PTD: 169-063 - DIO Application For processing. Thank you, Juanita L Lovett Sr. Operations/Regulatory Tech Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 | Anchorage | AK | 99503 (907) 777-8332 | jlovett@hilcorp.com 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 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 the onward 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. 2 Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RE: Docket Number: DIO-23-003 Hilcorp Alaska, LLC (Hilcorp), by letter dated August 9, 2023, filed an application to the Alaska Oil and Gas Conservation Commission (AOGCC) for a Class II Underground Injection Control Disposal Injection Order for well A-08 on the Tyonek Platform in the North Cook Inlet Unit (NCIU). 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. This notice does not contain all the information filed by Hilcorp. To obtain more information, contact the AOGCC’s Special Assistant, Samantha Carlisle, at (907) 793-1223 or samantha.carlisle@alaska.gov. A public hearing on the matter has been scheduled for October 10, 2023, 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: 973 667 593#. Anyone who wishes to participate remotely using MS Teams video conference should contact Ms. Carlisle at least two business days before the scheduled public hearing to request an invitation for the MS Teams. In addition, written comments regarding this application may be submitted to the AOGCC, at 333 west 7th Avenue, Anchorage, AK 99501 or samantha.carlisle@alaska.gov. Comments must be received no later than the conclusion of the October 10, 2023, hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact Samantha Carlisle, at (907) 793-1223, no later than October 4, 2023. Brett W. Huber, Sr. Chair, Commissioner Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.09.07 13:41:39 -08'00' From:Carlisle, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Public Hearing Notice, Docket Number: DIO-23-003 (NCIU) Date:Thursday, September 7, 2023 3:20:55 PM Attachments:DIO-23-003 Public Hearing Notice.pdf Hilcorp Alaska, LLC (Hilcorp), by letter dated August 9, 2023, filed an application to the Alaska Oil and Gas Conservation Commission (AOGCC) for a Class II Underground Injection Control Disposal Injection Order for well A-08 on the Tyonek Platform in the North Cook Inlet Unit (NCIU). Samantha Carlisle Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: samantha.carlisle@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.carlisle%40alaska.gov 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 ______________________________________ 09/10/2023 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 this 11th day of September 2023. Account #: 100869 ST OF AK/AK OIL AND GAS CONSERVATION COMMISSION333 W. 7TH AVE STE 100, ANCHORAGE, AK 99501 Order #: W0040498 Cost: $275.2 Notice of Public HearingSTATE OF ALASKAALASKA OIL AND GAS CONSERVATION COMMISSION RE: Docket Number: DIO-23-003 Hilcorp Alaska, LLC (Hilcorp), by letter dated August 9, 2023, filed an application to the Alaska Oil and Gas Conservation Commission (AOGCC) for a Class II Underground Injection Control Disposal Injection Order for well A-08 on the Tyonek Platform in the North Cook Inlet Unit (NCIU). 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. This notice does not contain all the information filed by Hilcorp. To obtain more information, contact the AOGCC’s Special Assistant, Samantha Carlisle, at (907) 793-1223 or samantha.carlisle@alaska.gov. A public hearing on the matter has been scheduled for October 10, 2023, 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: 973 667 593#. Anyone who wishes to participate remotely using MS Teams video conference should contact Ms. Carlisle at least two business days before the scheduled public hearing to request an invitation for the MS Teams. In addition, written comments regarding this application may be submitted to the AOGCC, at 333 west 7th Avenue, Anchorage, AK 99501 or samantha.carlisle@alaska.gov. Comments must be received no later than the conclusion of the October 10, 2023, hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact Samantha Carlisle, at (907) 793-1223, no later than October 4, 2023. Brett W. Huber, Sr. Chair, Commissioner Pub: Sept. 10, 2023 STATE OF ALASKA THIRD JUDICIAL DISTRICT 2024-07-14 Document Ref: PJPOG-UKQTS-QF6I5-T3O7T Page 40 of 46 1 Hilcorp Alaska, LLC Ryan Rupert 3800 Centerpoint Dr., Suite 1400 Anchorage, Alaska 99503 August 9th, 2023 Chairman Brett Huber, Sr. Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Subject: Application to convert NCIU A-08 (PTD 169063) to a Class II Disposal Well Dear Chairman Huber, Hilcorp Alaska, LLC submits application for NCIU A-08 to be used for Class II disposal into the currently perforated zone, which is the exempt aquifer below 2900’ MD in NCIU A-12 cited in Aquifer Exemption Order #4. This document covers the information required in 20 AAC 25.252 (c) as well as provides a brief overview of NCIU A-08 and the intended disposal zone. The intended disposal zone, an undefined sterling sand, was first sanctioned for disposal operations in 1998 via Aquifer Exemption Order (AEO) #4 and Disposal Injection Order (DIO) #17, which authorized Class II disposal in well NCIU A-12. NCIU A-12 was replaced by NCIU B- 01A in 2008 via DIO #33. Since 1998 approximately 860,000 bbls of fluid has been injected into this zone, the majority going into A-12. NCIU A-08 was drilled in 1969 as a multi-zone gas producer tapping the Beluga and Cook Inlet Sands. In 2020, the Sterling X and Y sands were identified for development and, because these sands were above the shallowest production packer, a cement packer was placed across these sands up to a depth of 3895’ MD (TOC verified with a CBL). After unsuccessfully producing the Sterling X and Y sands, it was determined that this well would make an ideal Class II disposal well to replace B-01A. The cement packer extends sufficiently above the intended injection zone to be a barrier while also allowing for a fully monitorable tubing / casing annulus. Recent work, authorized by Sundry 323-110, plugged back the Sterling X and Y sands followed by perforating the disposal interval to demonstrate injectivity into the proposed disposal zone and to verify annular isolation with an extended injectivity test. The majority of the disposal on the Tyonek platform is currently injected into NCIU A-13, a Class I disposal well. NCIU A-08 is intended to be a backup to NCIU A-13, albeit for Class II waste only, should NCIU A-13 ever require intervention or if additional injection capacity is required. By Samantha Carlisle at 11:34 am, Aug 24, 2023 The following sections cover the information required by 20 AAC 25.252 (c). The italics print are the regulations, the regular font is the operator’s response. Sincerely, Ryan Rupert Cook Inlet Offshore Operations Engineer Hilcorp Alaska, LLC Attachments 1) Area map of the North Cook Inlet Unit showing all wells with ¼ mile of the proposed injection zone. 2) Cross section comparing NCIU A-12 to NCIU A-08 3) 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 4) NCIU A-08 Wellbore Schematic Digitally signed by Ryan Rupert (4447) DN: cn=Ryan Rupert (4447) Date: 2023.08.18 09:03:22 - 08'00' Ryan Rupert (4447) (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; Attachment 1 is a map of the North Cook Inlet Unit showing all wells with ¼ mile 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 within a ¼ mile radius of the proposed disposal well. The sole surface owner within a ¼-mile radius of NCIU A-08 is the State of Alaska. (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; There are no parties due notice of the proposed disposal well. (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 proposed disposal injection interval in NCIU A-08 lies within the Sterling Formation, and it consists of a series of coarse-grained sand beds interspersed with relatively thin layers of carbonaceous mudstone. This interval, which lies between 3274’ TVD (4015’ MD) and 3382’ TVD (4207’ MD) was previously used for disposal injection in offset wells NCIU B-01A (DIO 33) and NCIU A-12 (DIO 17). Lithologic units are correlative throughout the unit and a cross section comparing NCIU A-12 to NCIU A- 08 is provided as Attachment 2 showing the similarities between the two zones [confirmed by the AOGCC in approved sundry 323-110]. Upper confinement is provided by a stacked sequence of siltstones, mudstones, and coals interbedded with scattered sands. This sequence extends from approximately 3,092’ TVD to 3,274’ TVD, and it contains an aggregate thickness of about 68’ TVD of mudstone and coal. Lower confinement is provided by a sequence of interlaminated mudstones, claystone, coal, and siltstone interbedded with occasional sand intervals. This sequence extends from approximately 3,387’ TVD to 3,465’ TVD, and it contains an aggregate thickness of about 42’ TVD of mudstone and coal. (5) logs of the disposal or storage wells, if not already on file, or other similar information; All relevant well logs of NCIU A-08 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 disposal zone is 7” 26# J-55. Cement across the disposal zone and confining layers was placed using a DV collar at 6031 where 860sxs (168 bbls) of 15.6ppg class G was placed as the 2nd stage of a 2 stage cement job. A subsequent CBL run on 7/23/69 showed TOC at 3012’ MD and sufficient cement across the disposal zone and confining layers for zonal isolation. The tubing is isolated from the casing with a cement packer placed by Coiled Tubing on 7/3/20 using a cement retainer. 12 bbls of 15.3 ppg cement was pumped through the retainer at 4500’ MD and tubing punch holes at 4516’ MD. A RCBL, run on 7/4/20, shows great cement below 4010’ MD, and patchy cement up to 3895’ [confirmed by the AOGCC in approved sundry 323-110]. The annulus was pressure tested to 1500 psi, before and after perforating the disposal zone. An injection test of 1271 bbls at ~1.0 bpm showed no annular communication [results detailed in the submitted 10-404 for sundry 323-110] The Sterling X and Y sands have been isolated with a pressure tested CIBP (4232’ MD), and 25’ of cement [results detailed in the submitted 10-404 for sundry 323-110]. This testing meets the requirements of 20 AAC 25.412. (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; Waste disposal injection will consist of drilling mud, drill cuttings, reserve pit fluids, rig wash fluids, formation material, completion fluids, produced water, stimulation fluids, deck drainage, and other fluids eligible for injection into a Class II disposal well. The average daily disposal volume will depend on whether NCIU A-13 remains the primary disposal well for the Tyonek platform. In this case, disposal will only occur if additional disposal capacity is required or if A-13 ceases to be the primary disposal well. The maximum daily volume to be disposed of is 3500 bbls and corresponds to an average injection rate of 2.4 bpm. This rate and daily disposal volume is consistent with DIO 33 and the fracture modeling used to validate confinement of injected fluids. Given the historical disposal activities into this zone, no fluid compatibility issues are anticipated [DIO 33 finding 8]. (8) the estimated average and maximum injection pressure; The estimated maximum injection pressure will be 2500 psig. A recent injectivity test was performed at a rate of ~1.0 bpm with a resulting injection pressure of 1450 psig. These results were consistent with recent injection results in B-01A as well as the findings and conclusions in DIO 17 and DIO 33 [specifically DIO 33 – Finding 9]. (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; Hilcorp believes the effectiveness of the confining intervals – both upper and lower – has been demonstrated by the past injection in the proposed disposal zone in NCIU A-12 and NCIU B-01A. Fracture model results for the proposed disposal zone, using a third-party fracture model, were submitted as part of DIO 17. This modeling was also used for DIO 33. DIO 17 found that the planned disposal operations, as outlined in this application, into the proposed disposal zone, will not propagate fractures through the confining zones. [DIO 33 – Finding 8]. Based on the geologic similarities of NCIU A-08 to A-12 and B-01A, Hilcorp is requesting that the fracture modeling submitted with the application for DIO 17 (and by extension to DIO 33) be considered applicable to NCIU A-08. The previously proposed injection rates, volumes, and pressures are in line with the fracture modeling results presented in DIO 17 and DIO 33. (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; A standard laboratory water analysis was submitted with the application for Aquifer Exemption Order #4 and for Disposal Injection Order 17. (11) a reference to any applicable freshwater exemption issued in accordance with 20 AAC 25.440; and Aquifer Exemption Order #4 concluded that freshwater aquifers underlying NCIU do not serve as a source of drinking water. The Commission also concluded that freshwater exists at a depth and location that makes its recovery for drinking purposes economically impractical [DIO 33 – Finding 5]. (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. Six wells penetrate the Sterling within a 1/4-mile radius of NCIU A-08. Construction information for each well, including cement tops for casing set across the Sterling is summarized in Attachment 3. Detailed well construction information is in the Commission well files; this information includes cementing records that indicate cement has been circulated to surface in the surface casing annulus for each of the six wells. In addition,Attachment 3 has summarized the results of the Cement Bond Logs run for five of the six wells (no bond log was run in A-16, however cement was circulated to surface). 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80880808080808080808008880800008808880888800000808008880800808080008008088080800080800808088808080080808088888880888888808088800000000000000000000008800000088800088800888880000888000008888888800000000088880000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000 1010110010000010000110100100010000011000000001110010001000000101001001100011100000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000000ftftftttttffttftfffftttftfffftfffttttttftfttttttttttttt 1:111:11111111111111::11:1111111111111 262226262626226266666622626626262666266266222626262626222666266262226262626262666262626222622622666666662626262622222626266666222222222666662222226666666666666626666666226666262626626226666222266622626662626666226662929222292922292999999922292992929292922929929929292922929222929229999992922922222229299999929222922299292999992222299992992222222299999992222229992929999922999992222929299999999292229999299929999292929222929992922299299 Remarks Well symbols at Top Disposal Interval as correlated from A-12's disposal zone. Black circle represents a 1/4 mile (1320') radius from the Top Disposal zone in A-08. North Cook Inlet Tyonek Platform BasBasBasBaBBasBasBaBaBasBaBasBaBasBasasBasBasaasasassasaBaBasBasBBBasBBaaBaBaaasssssssBasBBasaaasaBaaassBasasssssasasaassBBassBasBassssBasBasaaaBasssssBBBaasaaassssBBaaaassssBasBasaaasBBsssssBaasssBBBaaaBBaaaasse_DeDeDe_DDeDDDeDeDDeDDeDeDe_DeeeeDeDeeeeDeeDeDeeDDeeeeeeeDeDeeeeeeDeDeDeDeeeDeeeeeDeDDeDDDDDDe_DDDeeDDeeeDDeee_ispispispispssspspspppspsppppssppppsssspspsspppsssspspspppsppsppspsspppppspsspsppssssssspspsssppssssppsspsspsspppsppposaosaosaosaoosaosassaosaaaososaosaooosaooooosasosaosasaaaosaososaooooosaosaaaosaosososaosasaososaososaosaosaosaoososaaosaosasaosasoosassaasasaaaoaaaalll TOPTOPTTOOTOOPPPPOPTOPTOOOOOPOOPOPOPOPPOOOOOOPOOOPOPTOOOPPPOPPTTOPOOOTOOOOOPOPPOOOOOOPPOPOOOOOPOPOPOOOOOOOO_STSTST_STSSTTSTS_SSTST_STSSSTTSTSSSSSSSSSSSTSTSSSSSSSSSSSTSSSSSSSSSSSSSSSS_SS_SSSSSSSS_ERLERLEERLERLRLRLRRRLRLEEERLERERRLRLERRRERLRLRRERRRRERRRRRRRRERRRRRRRRRRINGINIINGNGNGNNNNGNGINGGGGGIIINGNGNGNNNNNGINGGGGNGGGNNGGGNGNNGGGGNGNNNGNGGGGGGNGNNNGGGNGGGNNGNGGGGGGGNNGGGNNNNGGGNGNNGNGNNGNNNNNGNNGGNGNNGGGGGGG_YYY_YYY_YYYY_YYYYYYYYYYYYYYYYYYY_YYYYYYYYYYYYYYYYYYYYYYYY_YYY TopToTopTToToTopToToTopTopTopTooopToppppppopoopopToopopppppopoooppppoppoooopoppopoopooopopopopopopopopopopopopopoppppoppppp DiDDDiDiiDD_DiDDDiDiDDDDDDDDDDD_DDDDDDDDDDDDDDDDDDDDDDD___spospossposspopoppspospoppspooospossposposposspoppppspopspopooooooospospospppspopoopoosposspospoppooooooospospospspopospooossspospospospspospospspsppoooopppppppsalsalsalsalsalsalsalsasaaasassasasasaaaasasasassaaaaasasssasasaaaaaaaasssasaaasasaasasasssaasaaasasasaaaaas PPPPPPPPPPPPPPPPPPPPPPPPPPPPPPPPPPPPPPP_NCNCNC_NCNNNCNNC_NC_NCNNCNCCCNCNCNCNCNCNCCCCCCCCCCNCCCCCNNCNCCCCCNNCNNNCCNNCNNNCNCNNNNNNCNNNNNCCNNCNNNCCCCCNCCCNNCCCCCNNNNCNCCCCCCNNCCCCNCNIU_IUIU_IIU_U_UUUUUUUUUUUUUUUUUUUUUUUUUUUUUUUUUUUUUUUUUUU STRSTRSTRSTRSTRSTRTRSTRSTRRRSTRSTRSRRSSTRSSTRSTRSTRSTRRSTRSTRSSTRRSSSSTRSSTRRSTRRSSSSSSRRRRRSSSTRSSRRSTRSSSSRRSTRSSSSSSSTRSSSSSSSSSSSSSSSRRSSSSSRRSTRSSSSRSSRRSSRRRRSRRRAY_AYAY_AYYAYYAYY_YAYAYAYAYAYAYAYYAAAYAYAYAYYAYAYAYAYYAYAYAYAYAAYAYAAY_Y_AYAAYAYAAAAAYAYYYYYAAYAAYYAYYYAYYAAYYAYYAAAYYAYYYYAAAAAAYAAAAAAAAYAAAAAAAAAAYAAY 222222222222222222222222222222222222222222222222 PPPPPPPPPPPPPPPPPPPPPPPPPPPPPPPPPPPPPPP_NCNC_NCNNNCNNC_NC_NCNNCNCCCNCNCNCNCNCNCCCCCCCCCCNCNNCCNCNCCCNCCCCNNCCCCCNNCNNNCCNNCNNNCNCNNNNNNNNNNCCNNNCCCCCNCCNNCCCCCNNNNCNCCCCCCNNCCCCNCNIU_IUIU_IIU_U_UUUUUUUUUUUUUUUUUUUUUUUUUUUUUUUUUUUUUUUUUUU STRSTRSTRSTRSTRSTRTRSTRSTRRRSTRSTRSRRSSTRSSTRSTRSTRSTRRSSSTRSSSTRSTRRRRSSSSSTRRSTRRSSSSSRRRRSSSTRSSRRSTRSSSSRRSTRSSSSSSSTRSSSSRSSSSSRSSSSRRSSSSSRRSTRSSSSRSSRRSSRRRRSRRRAY_AYAY_AYYAYYAYY_YAYAYAYAYAYAYAYYAYAAYAYYAYYAYAYAYAYYAYAYAYAYAAYAYAAAAAYYAYAYYYYYAYYAYAAYAAAAAYAYYYYAY_YAAYAAYYAYYYAYYYYAYYAAAYYAYYAAAAAAYAAYAAAAYAAAYAAAAAAAYAAY 3333333333333333333333333333333333333333333333333333333 NCICNCINNNCNNCNCNCNCCNCIINNCNCCNCNCNCNCCCCCCCNCCCNCCNCCNCNNCNNNNCNNNCNNNNCCCCNNNNCCCCCNCCCCCCCCCCNNCNCNCCCNCICNCCCCNNCCCU_TU_TU_U_TUUTUTTTUTUTUUUUUUUTUUTUUUUUUUUUUUUUUUUUTUUUUUUUUUUU_OP_OOOP_OPOPOPOPOPOPOPOPOPOPOPOPOOPOOPPOOOOP_OOOOOOOOP_OP_OOOOOOOPPOPPOPOPOPOOOPOOOPOPOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOPOOOOO POOPOOPOOPOOPOOPPOOOOOOOOPOOPOOOOOOPOOOOPOOPOOOOPOOPOOPOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOPOOOOOOPOOOOPOOPPOOPPOOPOOPOOPPOOPPOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOPOOOOPOOOOOOOOLLLLLLLLLLLLLLL TOPTOPTOTOPOOTOPOOPOPPOPOPOOOPOPOOOOOOPOPPOOOOPOOOOOOOOOOPOPOOPTOPOOOOPOOPPOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOPOOOOOOO_STSST_STSST_S_SS_SSSSSSTSTSSSSSSSSSTSSSSSSSSSSTSSSSSTSSSSSSSSSSSSSSSSSSSSSSSSSSSSSSSSSSSSS_ERLEREERERLERLERERRLRRERLRLERRRRRRRRRERERLREERLRLRRRRRRRRRERRRRRRRRRRINGIIINGNGNGNNNINNGINGGNGNGGNNNGGNGNGNGNGNGGNGNGGGNGNGGGGNNNNGNGNNGNNGGNNNGNNNNNGNNGGNNNNGGGNGGINGGGNNGGGNNNGGGGGGNNGGGGNNGGGGGGG_AA_AAAAAA_AAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAA_AAAAAAAAAAAA ASASASASASASASASSASASASASASAAAASSASSAAAASASASAAAAAASSSSAASAAASSSSSAASSASSSAASASSSAAASASSAASASSSSAAAASSSSASSSSSSSAAAASE_SEEE_SESESE_SSSSS_S_SSSSSESE_SSESSSSSSSESSSSSSSEEESESSSSSESESSSSSSSSSSSSSSSSSSSSSSSSSSSSSSSSSSSSSSSESSSSSSSSSSTERTERTERTERTEEREREEERRRRERRRERTERERRRRRRRRRREERERRRRRERRRRRRRRERRRRRRRRRLINLINLINLINLINLINIINNINNNNNNNNNNNLINNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNLLNNNNNNG_XGGXGXG_XGXGGXGXGXGXG_XXXGXGXGXGXGXGXGXXGXGXXGXXXGXXXXG_XGGGXGXGGGGGGGXXXGXXGGGGXGGGXXGGXGGGGXGGGGGGGGGXGXXXGGGGGGXXXGGGGXXXGG_XXX PPPPPPPPPPPPPPPPPPPPPPPPPPP_NCNCNC_NCNNNCNNC_NC_NCNCNCNCCCNCNCCNCNCNCCCNCCCCNCCCNCCCCCCC_NCNNNNCNCNNNCNNNNCNNNNNCCCCNNCNNNCCCCCCCNCCCCCNNCCCCCNNNNCNCCNCCCNNCCCCNCNNCCIU_IUIU_IIU_U_UUUUUUUUUUUUUUUUUUUUUIUUUUUUUUUIUUUUUUUUUUUUU STRSTRSTRSTRSTRSTRTRSTRSTRRRSTRSTRSRRSSTRSRRSTRSTRRSTRSTRSSTRRRSTRSTRSSTRSSSSTRSTRRRRSSSTRSSSSTRSSSSSSRSSSSSRSTRSSSTRRRRSSSSSRRRSTRSTRSSSSRRRSSRRSSRRRRSSSRRAY_AYAY_AYAYAYYAYY_AYAYAYAYAYAYAYAYYYAYAYAYAYAYAYYAYAYAYAYYAYAYAYAYAAYAYAAY_Y_AAAYYAYYAAAAAYYAYYAAAYYYYYYAAAAYAAYYAAAAAYAAAYAAAAAYAAAAAAYAAA 1111111111111111 ASAASAASSAAASSSAAASAAASASASASASAAASASSSSASASAAASAASASASAAAAASSSSAAASASSAASASASSSAAAASSAASSASSASAASAAASASSSSSSASSSSAASSSE_SEEE_SESEESSSSS_S_SSSSSSSESE_SSSESSSSESESSSSSSSSSSSSSSESSSSEEEESSSSSSSSSSSSSSSSSSSSSESSSSSSSSSSSSSSSTERTERTERTERTEEREEREERRRRRERRRERTERTERERRRRRRERERRTERREEERRRRRRRRRTETEERRRRRRRRRLINLINLINLINLINLINLINIINNINNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNLINNNNNNLLLINNNNNNNNG_ZG_ZGZGZGGZGGGZGZGZGZGZGZGZGZG_ZGZGZGGGZGZGZGZGGGZZZGG_ZGG_ZZGZGGZGZZZZZGGZZGZGGGGGGZZZZGGGGZGZGGGGGGZGZZGZZGZGGGGZZGZGGGGGGGGGG ASASASASASASASSSSASASASASASASASAAAASSSASASAASAASASAASASASASSASSSSAASAASASSAASAAAASASSSAASSSSAASSSSSSSSAASSSSAASSE_SESEE_SESSSSSSEEE_SEE_S_S_SSSSSSSE_SSSSSSSSSESESSSSSSSSSSSSSSSSSEESSSSSSSS_SSSSSSSSSSS_TERTERTEREERERERRRTERTERTERTETERERERRTERRTERTERTERTERTERRRRRTERTERRRRRTERTRRRERRRRRRLINLINLINLINLLINNNNLINLINLINLINLINLINILINLINNNNNLINNNLINNNNNNNNINNNNNNNNNNNNNNNNLLNNNNNNNNLNG_YGYG_YGGGGYGYGYYG_YGYG_YGYGYGGGYYYYGYYYGYGYYGYGYY_YGYGYGYYYYG_YGGYGYGYGYYGYGYGY_YGYYGGGGGGGGGGGGGGGGGGGGGGGGY TOPTOPTOTOPOTOPOOPOPPOPOOOOPOPOOPTOOOOPOPPPOOOOOOOOOOOOPOPPOPOPOOOPOOOPPOOOOOOOOOOOOOOOOOOOOOOOOOOOOOO_STSTST_STSTSTSTS_SSSSSSSSSSSSSSSSSSSSSSSSSSSSSTSSSSTSTSSSSSSSSSSSSSSSSSSSSSSSSSSSSSSSS_ERLEEERLERERRLRLRLRRERLRLERRRRRRRRRERERRRERLREEERLRLRRRRRRRRRRRRRRRRRINGIIINGNGNGNNNNINNGINGGGNGNGGGNGNNGNGNGGGNGNGNGNGGNGNGGGNGGNGGNNGNNNNGGGNGNNGNNNNNGNNNNNGGNNNGGGGGGNNGGGGNNGGGGGGNGGGGGNGNGGGGNGGG_XXXX_XXXXXXXXXXXXXXXXXXXXXXXXXXX_XXXXXXXXXXXXXXXXX_XXXXXXX_XXXXXXX 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BASBASBASBASBASAASASASASBABASBASASBAASASBBASASBASASBASBBABBBASASAAAASBBBBASAAAAAAASSBASSSBBBAAAAAAASASASBASASBABBBASBAASASASASASSBASSBASASSSSSAASSSAASASASSSBBAAASASASBAASSABASBBASBASBAAASSSBAAASAAE_SESEESE_SEESSSSSESESE_SSSSSESSSSS_SESSSSESSSSSSEESESSSSSSSEESSSSSSSSSESSSSSESESSSSESSSSSSSSSSSSESSSSESSS_TERTERTERTTEEEERERTERRRERRTERRTTERERERRRRRRRRERERERERRRRERRRRRRRRRRRRRRRRRRRRRRRRRRRLINLINLINLINLINLINIINNNININNNNLINLINNNNNNNNNNNNINNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNLLNNNNNNNNG_XGG_XGXGGXGXGXGXGXG_XGXGXGXGGXGXXXXGXGGXGXGXXGXGXXXXGXXXXGXG_X_XXXGGGGGXGGXXXXXXGXGGGGXGGGXXXXGGXGXXGGXXXXXGGGGGXGGGXXXXGGGGGXXXXGGXXXXGGXXXXG TOPTOTOTOPTOTOOOTOPOOPOPPOPOPOPOOPOPOOOOPOPOOOOPOOOOOOOOOOPOOPOPOOOPOOPPOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOOO_NCNCNC_NCNNNCNCNCNCN_NCNCCNCNCNCCNCNCNCCCCNCNCCNCCCC_NC_NCNNNNCCNNNNNCNNNNNNNNCCNCCCNNNNNCCCCCCCNCNNCCNCNCCNCNNCCCCCCNNCCCCNCCCCCCCCCNNNCCCCCCC_IU_IIUIU_IUU_U_UUUUUUUUUUUUUUUUUUUUUUUUUUUUUUUUUUUUUIUUUUUUUUUUUUUU 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RHOBRHOBRHOBRHOBRHOBRRHORHORHOHHOBHOBHOOOOOBOOBBRHOBRHOBRHOBRRHORROBOOOOHOOOOORHOBBBBRHOBRHOBRRORHOBHOOOOOOBBRHOBRHORRHOBRHOBRHOBORHOBOOBOOOBOBOBORHOOBBRRHORHOROOOBOBBBRHOBRRRHHOOORHOBBBBRHOBROOBBRHORHOBBBBRHOBBBRRRRHORHOBRHOBO-NPHNPHNPH-NPHN-NNPHPH-N-N-NPHNPNPNP-NP-NPH-NPHNPPHPH-NPH-NPNPHNP-NP-NPHNPN-NPNPPHNPHNNNNPH-NPNNNPH-----NP--NN I CrIICrCrICrCCCCrCCCICCCCrCCCCCCCCCCCrCrrCCCCCrCrrrCCCCCCCCCCCCCrCCCrCrrCrrCCrCCossoossoossoossossoossossoossossossoossoossossosossoossoossoooossoossoossooossssossossossossssooooossoossoooooossoossssossossssssoossssssosoossooossooosoossoossosssssssoossosssoooossoossooooooossssossosossoossossssoooossosssssoossoooossssssooooossoooosssssosssssossosoosssososvererververveeveeverververververvvvveveveveveevereevevevevervvverveveeveeerrvvvveveveveeveveeverververeeervevevervvveeverrvverveerereerreeeveeeveerveerveeeveer CoalCoaCoaCCoalCCCoalCoalCCCCCoalCCCCCoaoalCoalCoaCCCCoCCCCCoCoCoaCoaCoaCoaCoaCoaCoaCoaCooCoaCoaCCoaoaaCoaCoCoCoCoaCoaCoaCoaCoaCoaaooaCCooaoaCCoaCoaCCooaaaaaaaCoaCoaCoaooaaa_LogLogLogLogLL_LogLogLogLLoLogo_Logogogogogogggog_Log_Log_Lo_LoggLLoogoooogLogogLogLogoooooggoogLoogooo_LoogggggL_Logooooggogoggggggggg_ggggggg <= <<<<=<<<<<==<<<<<<<<<2.182.182.182.18218182.12.182.18.18882.182.182.182.182.182182182.182.12.188888.1882.182182182888888822.18182.12.182.18.18.18.1821821181818182182188821888221888888882.182885 RH5 RH5 5 R55 R5 RHR5 RRHHHHH5RH5R55R5R5RRH5RH5RH5RH5RHH5RH5RH5RRR5RH5RH5RH5RH5RH5RH5RH5RH5RH55RH5RH5 R5R5RR5RRR OBOOOBOOOBOOOOBOOOOOOOBBBOOOOOOBBBBBOBOBOBOOOOBBOBOBOBOBOOOBOOBOBOBOBOBOOOBOBBOOBOBB 0.000.000.00.000.000.000.00.000.000.000.000.0000000000.00000.000000.000000000000.00.0000000000000000000000000000000000000000000000000000000000.0000000000000000000000000000000.00.000.000000000.00.00.00.00.000.000..0.0000000.000000.0000 20.020 020 020.020 020.020.020.020.020.020.00.0.020 020 020.020.020.020 020.020 020 020 020.000020.020.000020 020.0020 02000020.020 0000220 020000000000020020000020.000000.020.20000000000002200000000000.000.0000.00.00.002220.20000.00.00.00.00.00.00.00000.00.0000000000000000000000000000000000000000000000000000000000000000000000000000000mVmVmVmVmVmVmVmVmVmVmVVVmVmVVmVVVmVVmVVmVVVmVmVVmVVmVVVVVVmVmmmmVmmmmmmVVVVmVmVmmmmmmVVVVVmmVVVVVVVVVVVVVVVVVVV AMAMAMAMAMAMAMAMAMAMAMAMAMAMAAMAMAAMAMAMAMAAMAMAMAMAMAMAAMMMAMMAAMAMMMAMAAMAMMMMMMMAMMMAMAMAMAMMAAAMAAAMAMAAMAMAMAMAAAAMAMAMAAMAMAMAAAMAMMAMAMAAAAMAAAMAMAAAAAAAMMAAAMAP3P3P3P3P3P33P3P3P3P3P3P3P3P3PP3P3P3P3333PPP333P3P33333P3PP33PPP3PP3P33P3333P3PP3P33333PPPPP333PPPP3P3PP333P3PP3PP333PPPP3333PP333333333333333333333FTFTFFFFFFTFTFFTTTFFFFF WellName PTD API StatusTop ofdisposalzone (MD)Top ofdisposalzone(TVD)Top ofCmt(MD)Top ofCmt(TVD) CommentsA-16208098 508832012700GasProducer4263 3289 Surface Surface9-5/8” Casing in 12-1/4" hole: Pumped 524 bbls of 12.0 ppg Cement from casingshoe at 4,536'. Observed 70 bbls cement returns. ToC at surface.A-13192106 508832008700Disposalinjector3735 3277 3450 305713-3/8" Casing in 17-1/2” hole (3 stage job):1st stage: Pumped 1000 sxs. Cement returns observed at surface aftercirculating through lower DV.2nd stage (DV collar at 7524'): Pumped 4400 sxs Class G cement at 15.8 ppg and1.17 ft3/sx. Lost returns after 561 bbls pumped and pumped remainder of jobwithout returns. Est TOC with 40% washout is 5318'.3rd stage (DV collar at 4308'): Pumped 1000 sxs of Class G cement at 15.8 ppgand 1.17 ft3/sx. Returns decreased throughout the job with no returns at theend.1/23/93 CBL shows patchy cement from shoe up past lower DV with free pipefrom 4950’ up to upper DV at 4308’. Log shows patchy cement above upper DVwith free pipe above 3450’.A-03168099 508832002000 Abandoned 3585 3248 2518 23297" casing in 9-5/8” hole: In A-03 parentbore (1969) Pumped 515sxs (191bbls)12.9ppg class G cement. Stage collar at 5114’ failed to open. Multiple squeezeswere performed at 3,930’, 4,100’, 4,178, and 4,793’. 91 total bbls placedbehind pipe with squeezes. 11/13/19 RCBL showed good cement from at leastto 3,988’ (PBTD at the time) up to 3,260’. Free pipe above 2,518’.A-03A221051 508832002001GasProducer3647 3265 4184 35977" casing in 9-5/8” hole: See A-03 parentbore above4-1/2" liner in 6-1/8” hole: Pumped 90bbls of 15.3ppg cement. 54bbls lossesduring cement job. 10/22/21 CBL logged ToC at 4,184’. (KOP from 7" casing at3,209'.) WellName PTD API StatusTop ofdisposalzone (MD)Top ofdisposalzone(TVD)Top ofCmt(MD)Top ofCmt(TVD) CommentsA-01168072 508832001600 Abandoned 3665 3286 2552 23997" casing in 9-5/8” hole:First stage: Casing landed at 7449’ and pumped 546sxs (131bbls) 13.2ppg classG cement. Cement seen back to surface when circulating through DV collarbefore 2nd stage pumped.2nd stage through DV collar at 5,094’. Pumped 552sxs (122bbls) 15.4ppg classG. Full circulation throughout. 9/22/92 USIT shows free pipe above 2552’.A-01A221071 508832001601GasProducer3831 3293 2552 23997" casing in 9-5/8” hole:See A-01 parentbore above4-1/2" casing in 6-1/8” hole: Pumped 123bbls 15.3ppg cement. Saw 1bblcement circulated off the liner top. 10/26/21 CBL shows cement up to Liner Toppacker at 2950’.A-08169063 508832002800GasProducer4015 3274 3012 26387" casing in 9-5/8" hole: 2nd stage through DV collar at 6031' pumped 860sxs(168 bbls) of 15.6ppg class G. 7/23/69 CBL showed ToC at 3,012'. _____________________________________________________________________________________ Updated By: JLL 04/21/23 SCHEMATIC North Cook Inlet Unit Well: NCIU A-08 PTD: 169-063 API: 50-883-20028-00 No Depth (MD) Depth (TVD)ID Item 38.9' 39' 4.500 FMC Tubing Hanger 1 291' 291' 3.813 Otis SCSSV Landing Nipple (No valve installed as of 3/9/23) 2 4,232’ 3,401’ CIBP w/25’ cement – Calc TOC 4,181’ (3/20/23) 3 4,400’ 3,265’ CIBP w/5’ of cmt TOC 4,395’ (7/8/20) 4 4,487’ 3,547’ Cement Retainer (7/3/20) 5 4,512’ 3,561’ 3.375 Permanent patch from 4512’ – 4534’ MD 6 4,545' 3,580' 3.880 Halliburton VSR Packer (Retrievable w/tubing adapter) 7 4,560 3,588’ CIBP w/5’ of cmt TOC 4,554’ (6/29/20) 8 4,613' 3,619' 3.813 Halliburton X Nipple 9 4,850’ 3,758’ - 4-1/2” CIBP w/5’ cmt. TOC at 4,840’ 10 4,891' 3,783' 3.970 Halliburton MHR Packer (Permanent) 11 5,361' 4,072' 3.970 Halliburton MHR Packer (Permanent) 12 5,496' 4,158' 3.970 Halliburton MHR Packer (Permanent) 13 5,699' 4,287' 3.970 Halliburton MHR Packer (Permanent) 14 5,892’ 4,412’ 3.958” WLEG 15 6,031’ 4,503’ >6.276 7” cement stage collar OPEN HOLE / CEMENT DETAIL 16”22” Hole: Pumped 462sxs (220bbls) 11.5ppg type G lead followed by 125sxs (24bbls) 15.6ppg class G tail. Volumetric ToC suggests at surface (no notes) 10-3/4" 15” hole: 700sxs (330bbls) of 11.5ppg class G lead followed by 125sxs (24bbls) of 15.0ppg class G tail. Found cement inside casing at 2800’ MD.Volumetric annular ToC assuming 30% washout = 525’ MD 7" 9-5/8" hole: Pumped 545sxs (132bbls) of 13.3ppg Class G primary cement job. Volumetrics using OH caliper put ToC at ~7700’ MD. 2nd stage through DV collar at 6031' pumped 860sxs (168 bbls) of 15.6ppg class G. 7/23/69 CBL showed ToC at 3,012’ 4-1/2” x 7” annulus 7/3/20: CT pumped 12bbls of 15.3ppg cement through cement retainer at 4500’ MD. Worst case ToC volumetrically should be 3950’ MD.7/4/2020 RCBL shows great cement below 4010’ MD, and patchy cement up to 3895’PBTD: 4,148’ TD: 9,222’ 2 30” RKB: MSL = 96’ 7” 8 9 14 15 Tubing Punch through patch 4,516’ – 4,518’ (6/30/20) 10-3/4” 16” 1 Parted Casing below EZSV @ 7,182’ Tubing Punch 4,635’ Sterling Y Sterling X 4 6 7 10 11 12 13 5 Sterling X X 3 2 CASING DETAIL Size Wt Grade Conn ID Top Btm 30” H-40 STC 28.000 Surf 386’ 16” 65 H-40 STC 15.250 Surf 623’ 10-3/4” 45.5 J-55 BTC 9.794 Surf 2,985’ 7” 26 J-55 BTC 6.276 Surf 9,222’ TUBING DETAIL 4-1/2” 12.75 J-55 EUE 8rd 3.958 Surf 5,892’ Updated By: JLL 04/21/23 SCHEMATIC North Cook Inlet Unit Well: NCI A-08 Last Completed: 06/17/1994 PTD: 169-063 API: 50-883-20028-00 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Sterling 4,103’ 4,121’ 3326 3336 18’ 03/19/23 Open Sterling 4,126’ 4,144’ 3339 3350 18’ 03/20/23 Open Sterling 4,144’ 4,162’ 3350 3360 18’ 03/19/23 Open Sterling 4,162’ 4,180’ 3359 3371 18’ 03/18/23 Open Sterling X 4,344 4,362 3,465 3,476 18' 07/10/20 Isolated (3/9/23) Sterling Y 4,425 4,439 3,511 3,519 14’ 07/05/20 Isolated (7/8/20) B 4,635’ 4,650’ 3,631’ 3,640’ 15’ 06/29/20 Isolated B 4,635' 4,735' 3,631' 3,690' 100' 6/2/1994 CMT SQZD CI-1 4,979' 5,036' 3,836' 3,870' 57' 05/05/20 Isolated CI-2 5,061' 5,161' 3,885' 3,947' 100' 05/05/20 Isolated CI-3 5,191' 5,211' 3,965' 3,977' 20' 05/05/20 Isolated CI-3.1 5,240' 5,250' 3,996' 4,002' 10' 05/05/20 Isolated CI-4 5,266' 5,283' 4,012' 4,023' 17' 05/05/20 Isolated CI-4 5,288' 5,325' 4,026' 4,049' 37' 05/05/20 Isolated CI-5 5,388' 5,438' 4,089' 4,121' 50' 05/05/20 Isolated CI-6.2 5,563' 5,570' 4,200' 4,204' 7' 05/05/20 Isolated CI-7 5,580' 5,596' 4,211' 4,221' 16' 05/05/20 Isolated CI-7 5,600' 5,624' 4,227' 4,242' 24' 05/05/20 Isolated CI-8.2 5,743' 5,753' 4,315' 4,322' 10' 05/05/20 Isolated CI-9.1 5,837' 5,845' 4,376' 4,381' 8' 05/05/20 Isolated CI-10 5,855' 5,885' 4,387' 4,407' 30' 05/05/20 Isolated A-3 6,014' 6,015' 4,492' 4,493' 1'8/3/1969 CMT SQZD B-6 6,302' 6,310' 4,679' 4,684' 8'8/3/1969 CMT SQZD E-8, E-9 7,030' 7,067' 5,113' 5,135' 37'8/4/1969 ISOLATED F-4, F-5 7,197' 7,214' 5,211' 5,221' 17'8/4/1969 ISOLATED F-6 7,218' 7,238' 5,224' 5,235' 20'8/4/1969 ISOLATED G-1 7,309' 7,326' 5,280' 5,290' 17'8/4/1969 ISOLATED G-4 7,388' 7,398' 5,330' 5,336' 10'7/30/1969 ISOLATED H-1 7,478' 7,488' 5,386' 5,392' 10'8/4/1969 ISOLATED H-3 7,513' 7,538' 5,408' 5,424' 25'8/4/1969 ISOLATED H-6 7,583' 7,598' 5,452' 5,461' 15'8/4/1969 ISOLATED I-7 7,822' 7,828' 5,601' 5,605' 6'7/27/1969 ISOLATED K-2 8,008' 8,018' 5,719' 5,725' 10'8/4/1969 ISOLATED M-2 8,180' 8,185' 5,826' 5,829' 5'8/4/1969 ISOLATED M-10 8,307' 8,314' 5,906' 5,910' 7'8/4/1969 ISOLATED N-2 8,375' 8,425' 5,949' 5,982' 50'7/24/1969 ISOLATED