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Home My WebLink AboutDIO 045DISPOSAL INJECTION ORDER 45 1. December 21, 2021 Vision Operating application class 2 UIC 2. January 7, 2022 Notice of Public Hearing, affidavit, and email list 3. February 8, 2022 Email re: porosity and permeability calculations 4. February 15, 2022 Transcript and presentation 5. February 21, 2022 Vision additional information, questions from hearing 6. March 11, 2024 Vision request for reauthorization (DIO 45.001) STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue Anchorage, Alaska 99501 Re: THE APPLICATION OF Vision Operating, LLC. for disposal of Class II oil field wastes by underground injection in the Tyonek Formation in well 23-25 located in the North Fork Unit Sections 25 and 26, T04S, R14W S.M. Disposal Injection Order 45 Docket No. DIO-21-002 North Fork Unit well 23-25 Cook Inlet Basin April 18, 2022 IT APPEARING THAT: 1. By application received December 21, 2022, Vision Operating, LLC (Vision) requested authorization for underground disposal of Class II oil field waste fluids into the existing North Fork Unit (NFU) well 23-25 (NFU 23-25). 2. Pursuant to 20 AAC 25.540, the Alaska Oil and Gas Conservation Commission (AOGCC) scheduled a public hearing for February 15, 2022. On January 7, 2022, the AOGCC published notice of that hearing on the State of Alaska’s Online Public Notice website and on the AOGCC’s website, electronically transmitted the notice to all persons on the AOGCC’s email distribution list and mailed printed copies of the Notice of Public Hearing to all persons on the AOGCC’s mailing distribution list. On January 9, 2022, the notice was published in the Anchorage Daily News. 3. At the February 15, 2022 hearing, Vision provided testimony and presented evidence in support of its application. The hearing record was left open until February 25, 2022 for Vision to respond to AOGCC’s requests for additional information. 4. On February 21, 2022, Vision submitted the requested information as well as an affidavit dated February 17, 2022 stating all surface owners within a one-quarter mile of the existing NFU 23-25 well were provided a copy of the application for disposal. The hearing record closed. 5. Vision’s application, testimony, supplemental information, and AOGCC public records for NFU wells are the basis for this order. FINDINGS: 1. Location of Adjacent Wells (20 AAC 25.252(c)(1)) The NFU central drilling and production pad lies about seven miles east and slightly north of the community of Anchor Point on the Kenai Peninsula. This pad lies also about 1-1/4 miles southwest of the Village of Nikolaevsk. The NFU currently contains eight natural gas development wells (Figure 1). Six of these wells are currently producing and two are shut in NFU 23-25 and NFU 41-35). Vision has identified one of the shut-in wells, NFU 23-25, for possible conversion to disposal injection operations. Disposal Injection Order 45 April 18, 2022 Page 2 of 11 Figure 1. Index Map – North Fork Unit Area The red circle represents a radius of ¼ mile from the planned disposal intervals; the black polygon represents the North Fork Unit boundary.) 2. Notification of Operators and Surface Owners (20 AAC 25.252(c)(2) and 20 AAC 25.252(c)(3)) Vision is the only owner and operator of properties within a one-quarter mile radius of the proposed disposal interval, which lies offshore beneath the Cook Inlet. The State of Alaska, Department of Natural Resources (DNR) is the only subsurface owner. DNR and 37 private surface owners are within a one-quarter mile radius of the proposed disposal well. Vision provided AOGCC an affidavit affirming that surface owners were provided a copy of the application. 3. Geological Information on Disposal and Confining Zones (20 AAC 25.252(c)(4)) NFU 23-25 was initially drilled during 2012 as a gas development well. This “s-shaped” directional well returns to nearly vertical form about 7,600’ measured depth (MD), which is equivalent to about -5,757’ true vertical feet subsea (TVDSS)1. At that time, three intervals were perforated and tested within the Tyonek Formation (Tyonek). The deepest perforations 10,138’ to 10,169’ MD (-8,294’ to -8,325’ TVDSS) were swabbed but produced only water. The upper two perforated intervals from 8,829’ to 8,836’ MD (-6,986’ to -6,993’ TVDSS) and from 8,950’ to 8,974’ MD (-7,107’ to -7,131’ TVDSS) were tested together but produced only 103 thousand cubic feet (MCF) cumulatively over five days scattered over six months. 1 To avoid confusion, for equivalent depths presented herein that represent true vertical depth below sea level subsea”), the footage will be preceded by a negative sign and followed by the acronym TVDSS (e.g., 5,757’ true vertical depth subsea will be depicted as -5,757’ TVDSS). 0 1 mile Disposal Injection Order 45 April 18, 2022 Page 3 of 11 Vision plans to conduct disposal injection operations through perforations into an undefined waste disposal pool comprising up to 13 separate Tyonek sandstone intervals that are divided between two separate zones that are informally termed Zone 1, the deeper disposal zone, between 8,950’ and 9,890’ MD (-7,107’ and -8,046’ TVDSS) and Zone 2, the shallower disposal zone, between 6,265’ and 7,115’ MD (-4,475’ and -5,275’ TVDSS). Within the NFU, this portion of the Tyonek consists of numerous channel- and floodplain-deposited sandstone and conglomerate layers that are interbedded with—and bound above and below by— impermeable siltstone, claystone, and scattered layers of non-reservoir coal. Vision’s porosity estimates for the reservoir sandstones and conglomerates in Zone 1 range from about 13 to 18.25 percent, and estimated permeability ranges from about 2 and 3.5 millidarcies (md) based on well log calculations. Porosity and permeability estimates for the shallower reservoirs in Zone 2 are slightly higher, ranging from about 17 to 19.5 percent and about 5 to 7.5 md, respectively. The confining intervals for both planned injection zones consist of interbedded layers of impermeable siltstone, claystone, scattered thin non-reservoir coal beds, and some sandstone. The upper confining layer for Zone 2 ranges from about 6,040’ to 6,265’ MD (-4,285’ to 4,475’ TVDSS) is 190’ true vertical thickness (“TVT”) of mostly siltstone and carbonaceous shale, with several interspersed, thin coal seams and some interbedded, very fine to coarse, poorly to moderately sorted sandstone. On the density log, the coals beds appear to range from about 1’ to 5’ TVT. The lower confining layer for Zone 2 lies from 7,115’ to 7,315’ MD (-5,275’ to -5,473’ TVDSS) is about 198’ TVT of mostly siltstone containing several interspersed, thin coal seams. The siltstone increases in clay content and becomes somewhat more fissile and laminar with depth. Thin, dispersed interbeds of sandstone also occur along with coal seams that appear to range from about 1’ to 2’ TVT. The upper confining layer for Zone 1 ranges from about 8,540’ to 8,830’ MD (-6,697’ to 6,987’ TVDSS) is 290’ true vertical thickness (“TVT”) that is mostly siltstone with interspersed beds of tuffaceous very fine to coarse, poorly to well sorted sandstone. Interbeds of coal and sandstone occur. On the density log, the coals beds appear to range from about 1’ to 2’ TVT. The lower confining layer for Zone 1 from 9,890’ to 10,140’ MD (-8,046’ to -8,296’ TVDSS) is about 250’ TVT of mostly siltstone containing several interspersed, thin coal seams. The coal seams in this confining layer appear to range from about 1’ to 3’ TVT. The NFU structure was mapped using 3D seismic and well data (Figure 2). At the top of the two confining zones, this structure is a northeast-trending anticline with four-way closure that measures roughly 2½ miles long and 1½ miles wide. The southeastern anticline limb terminates against a large, northeast-trending, high-angle reverse fault that dips about 65 degrees toward the northwest. Four northwest-trending normal faults divide the crest and southeast limb of the anticline into five blocks. These faults display greatest vertical displacement in the southeastern portion of the field where they intersect the reverse fault. Disposal Injection Order 45 April 18, 2022 Page 4 of 11 Vertical displacement along each of these faults diminishes from the crest of the structure toward the northwest to less than can be resolved on the 3D seismic dataset. Two of these normal faults may impact disposal injection. The first, termed “Bravo” and highlighted with purple on the map below, strikes northwest and dips southwest (i.e., is a down-to-the-southwest, normal fault). Vertical displacement along Bravo fault is over 200’ in the Figure 2. Structure Map – North Fork Unit Area Top of Upper Confining Formation for Injection Zone 1 Source: Vision Resources Public Testimony – February 15, 2022) southeast (where the fault intersects the high-angle reverse fault) and continues uniformly to the crest of the structure, where displacement then fades to zero about one mile to the northwest. The second fault, termed “Popeye” and highlighted with green on the map, is also a down-to-the-southwest normal fault. Vertical displacement along this fault is about 50’ from its intersection with the high-angle reverse fault to the crest of the structure, and then fades to zero about one-quarter mile to the northwest. 4. Evaluation of Fluid Confinement (20 AAC 25.252(c)(9)) The siltstone and non-reservoir coal deposits overlying the two proposed disposal zones form effective top seals for injected fluids. In addition to the confining layers described in the preceding section, the fluvial sandstones that form Vision’s 13 planned injection intervals are also separated and encapsulated by layers of siltstone containing carbonaceous shale and thin 0 0.5 mile Disposal Injection Order 45 April 18, 2022 Page 5 of 11 interbeds of coal. Layers of similar lithology beneath the proposed disposal zones will also prevent out-of-zone migration. Bravo fault appears sealing as it separates the non-commercial well NFU 23-25 from the productive main field area, located to the southwest in a separate, down-thrown fault block. The sealing capability of Popeye fault with respect to disposal injection in NFU 23-25 is uncertain as the vertical displacement of this fault diminishes below the resolution of the seismic survey data immediately north of the one-quarter-mile-radius area of review surrounding the proposed disposal intervals in NFU 23-25. 5. Aquifer Exemption (20 AAC 25.252(c)(11)); Standard Laboratory Water Analysis of the Formation (20 AAC 25.252(c)(10)) Vision’s application for this Disposal Injection Order includes a request for an Aquifer Exemption Order (AEO) under 20 AAC 25.252(c)(10) for the Tyonek below 4,929’ MD 3,418’ TVDSS) and underlying 1,920-acres within the NFU boundary. Vision separately submitted a request for freshwater exemption from the U.S. Environmental Protection Agency. Vision’s reported estimates for total dissolved solids (TDS) concentrations of the native formation fluids are greater than 3,000 mg/l for the interval between the top of the Tyonek at 4,929’ (-3,418’ TVDSS) to the top of the lower confining layer for Zone 1 at 8,766’ MD 8,046’ TVDSS). Vision provided laboratory analyses for five water samples from the Tyonek Formation within North Fork Unit. TDS concentrations in four of those samples range between more than 8,200 and 37,500 mg/l. Analytical results for the fifth sample are limited to the total concentration for cations, which exceeds 4,176 mg/l. AOGCC will provide a ruling on Vision’s requested AEO in a separate decision. 6. Well Logs (20 AAC 25.252(c)(5)) Log data from existing wells in NFU, including NFU 23-25, are on file with the AOGCC. 7. Demonstration of Mechanical Integrity and Disposal Zone Isolation (20 AAC 25.252(c)(6)) Ten and 3/4"-inch surface casing was set at 3,102’ MD (-2,023’ TVDSS), cemented to surface and tested. The 7-inch production casing was set at 10,716’ MD (-8,872’ TVDSS), cemented, and tested. A bridge plug was set and cement pumped on top to abandon lower perforations. The top of cement (TOC) was determined to be 10,094’ MD (-8,250’ TVDSS). Analysis of the cement bond logs (CBL) indicates the 7-inch casing has adequate cement behind casing to prevent vertical migration of disposal fluids. The CBL determined the TOC as 4,300’ MD 2,937’ TVDSS). A mechanical integrity test of the production casing will be performed in accordance with 20 AAC 25.412 prior to initiation of disposal operations. Vision will perform mechanical integrity tests of the tubing and tubing-casing annulus (including packer) and provide the results of those tests to the AOGCC before disposal injection commences. Additional baseline assessments and subsequent evaluations may be necessary to confirm the well has the proper mechanical integrity for disposal injection as proposed. Disposal Injection Order 45 April 18, 2022 Page 6 of 11 The operator will monitor the 7-inch casing by 2 7/8-inch tubing annulus pressure daily and report the results on the Monthly Injection Report. 8. Disposal Fluid Type, Composition, Source, Volume, and Compatibility with Disposal Zone 20 AAC 25.252(c)(7)) The majority (73.1%) of disposed fluids will be produced water from the NFU wells. Vision does intend to dispose of solids laden fluids (including drilling muds or cuttings) as additional future wells are planned for the NFU development. These solids laden fluids are estimated to only be approximately 1.1% of the total volume for disposal. Solids free workover fluids and completion brines from future workover operations could contribute up to approximately 23.4% of the total disposal volumes anticipated by Vision. Vision states that NFU 23-25 will not be used for commercial disposal (disposal of fluids generated by non-Vision operations and locations). Injected fluids derived within the NFU are expected to be compatible with the lithology and in-situ formation water of the proposed disposal injection zone. Vision has provided a table of estimated fluid volumes and types to be disposed over the expected 30-year project life. Daily disposal volumes are expected to average between 200 and 1,300 barrels per day with a total estimated volume of 15.6 million barrels. 9. Estimated Injection Pressures (20 AAC 25.252(c)(8)) Vision estimates a bottom hole injection initiation pressure of 6,976 psi for the existing Zone 1-G 1-F. This is equivalent to a maximum surface pressure of 4,170 psig when injecting water. Vision has requested an injection rate of 2.75 barrels per minute (bpm) for Zone 1-G. Injection rates and pressures for potential additional perforations have been estimated but will need to be verified by step-rate injection tests. 10. Mechanical Condition of Wells Penetrating the Disposal Zone Within a ¼-Mile Radius of the proposed disposal wells (20 AAC 25.252(c)(12)) There are no wells within the ¼-mile radius of NFU 23-35. The well closest to the proposed disposal zone is NFU 14-25 located just over ¼-mile away. NFU 14-25 is an active gas producer that is open only to shallower zones after deeper perforations have been abandoned. The well is isolated from the proposed disposal zone and cementing records indicate the 5-1/2” casing has good cement from total depth of 11,700’ MD (-10,266’ TVDSS) to approximately 4,500’ MD (-3,326’ TVDSS), and the 10-3/4” surface and 7-5/8” intermediate casings are cemented to surface. Records documenting the drilling, casing, cementing, and testing of these wells are in the AOGCC’s files. Fracture gradients of about 0.80 psi/ft and about 0.78 psi/ft can be estimated for disposal Zones 1 and 2, respectively, from in-field Formation Integrity Test (FIT) and Leak-off Test (LOT) results obtained from the drilling records for seven of the NFU wells as shown in Figure 2. Vision estimates bottom hole injection initiation pressure for the open Zone 1-G to be 6,976 psi. Vision’s requested surface pressure of up to 4,170 psi while injecting produced water, and the normal operating parameters of 2.75 bpm, predicts that fractures will not penetrate the uppermost confining zone or breach the lowermost confining zone. Disposed waste fluids will Disposal Injection Order 45 April 18, 2022 Page 7 of 11 be contained within the receiving interval by confining lithologies, cement isolation of the well bore, and planned operating conditions. 11. Evaluation of Remaining Reserves in the NFU 23-25 well The NFU 23-25 well was initially perforated from 10,138’ to 10,169’ MD (-8,294’ to -8,325’ TVDSS), from 8,950 to 8,974’ MD (-7,107’ to -7,131’ TVDSS), and from 8,829’ to 8,836’ MD (-6,986 to -6,993’ TVDSS). Attempts over several months to get the well to flow proved unsuccessful. A bridge plug and cement plug were set above the deepest set of perforations to isolate them. The two sets of shallower perfs are still open in the well. Cumulative production over 5 days scattered across 6 months was 103 MCF. Figure 3. Leak-Off and Formation Integrity Test Results for NFU Wells Disposal Injection Order 45 April 18, 2022 Page 8 of 11 The lack of production from this well suggests that the perforated intervals do not contain appreciable gas in the area of the well and as such those intervals are good candidates for disposal injection activities. The open perfs correspond to what the applicant referred to as Zone 1-G and Zone 1-F injection intervals in its application. The deeper Zone 1-A through Zone 1-E intervals have not been tested, nor have the shallower Zone 2 sands, so no conclusions about the suitability of those zones for disposal activities can be made at this time. CONCLUSIONS: 1. The requirements of 20 AAC 25.252 for approval of underground disposal are met. 2. Vision’s request for an aquifer exemption will be addressed in a separate order. 3. Injected fluids will be confined by the laterally continuous, impermeable siltstone and coal layers that overlie and underlie the two proposed injection zones and encapsulate the individual sandstone bodies what lie within those zones. The Bravo fault will likely limit distribution of injected fluids to the southwest of NFU 23-25 in Zone 1. The impact of the Popeye fault on injection operations in Zone 1 is uncertain but will likely be minimal as the fault plane lies 1,000’ or more from the planned perforations. 4. No compatibility issues are to be expected by disposing of produced water from the Tyonek Formations within the NFU by injecting it back into the Tyonek within NFU 23-25. 5. Reviews of the mechanical integrity of NFU 23-25 and nearby well NFU 14-25 show that the wellbores are adequately cemented and cased to prevent the movement of injected fluids outside of the disposal zone. 6. Fracture gradients of 0.80 psi/ft and 0.78 psi/ft can be estimated for Zones 1 and 2, respectively, based on in-field Formation Integrity and Leak-Off Tests above the proposed Tyonek disposal zones. For the open Zone 1-G and 1-F perforations, Vision’s requested injection surface pressure of up to 4,170 psi while injecting produced water, and the normal operating parameters of 2.75 bpm, predicts that fractures will not penetrate the uppermost confining zone or breach the lowermost confining zone. Disposed waste fluids will be contained within the receiving interval by confining lithologies, cement isolation of the well bore, and planned operating conditions. 7. Supplemental mechanical integrity demonstrations and regularly scheduled surveillance of disposal injection operations—including baseline and subsequent temperature surveys, monitoring of injection performance (i.e., pressures and rates), and analyses of the data for indications of anomalous events— will ensure that waste fluids remain within the disposal interval and ensure appropriate operation of the field. 8. Future wells within 1/2-mile of the proposed disposal interval must be constructed to ensure they do not serve as a conduit for fluid migration from the disposal zone. 9. The Zone 1-G and 1-F intervals do not contain recoverable reserves in the area of the well and are suitable for disposal injection operations. The remaining Zone 1 intervals and all of Zone 2 have not been demonstrated to lack producible hydrocarbons and should be tested before injection operations commence in them. Disposal Injection Order 45 April 18, 2022 Page 9 of 11 NOW, THEREFORE, IT IS ORDERED THAT Vision’s request for authorization for underground disposal of Class II fluids into well NFU 23-25 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 Tyonek within the NFU 23-25 well. Injection operations are prohibited until AOGCC issues—and the U.S. EPA approves or does not act on — the decision regarding Vision’s requested Aquifer Exemption Order for the North Fork Unit. RULE 1: Injection Strata for Disposal Underground disposal of the Class II fluids listed below is permitted into the Tyonek Formation in what the applicant refers to as Zones 1-G (8,829’ to 8,836’ MD, which is equivalent to -6,986’ to -6,991’ TVDSS) and as 1-F 8,950’ to 8,974’ MD, equivalent to -7,107’ to -7,131’ TVDSS) in well NFU 23-25. The additional Zone 1 and Zone 2 sands identified in the application must be tested for the presence of producible hydrocarbons before injection activities can begin in them. RULE 2: Authorized Fluids This authorization is limited to Class II gas field waste fluids generated within the NFU 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. Zone 1-G and 1-F disposal injection is authorized at wellhead injection pressures that do not exceed 4,170 psig while pumping water at a maximum rate of 2.75 bpm. Other Zone 1 and Zone 2 intervals will be authorized at rates and pressures determined by the Zone 1G and 1F disposal performance and by step rate testing of the proposed new intervals. RULE 4: Demonstration of Mechanical Integrity The mechanical integrity of NFU 23-25 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 Disposal Injection Order 45 April 18, 2022 Page 10 of 11 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 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. Vision 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 April 1st. The annual report shall also include a section titled “Induced Seismicity” in which Vision shall detail its monitoring efforts and evaluate the risks. Disposal Injection Order 45 April 18, 2022 Page 11 of 11 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 April 18, 2022. Jeremy M. Price Daniel T. Seamount, Jr. Jessie L. Chmielowski Chair, Commissioner Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Dan Seamount Digitally signed by Dan Seamount Date: 2022.04.16 17:49:07 -08'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2022.04.18 09:17:47 -08'00' Jeremy Price Digitally signed by Jeremy Price Date: 2022.04.18 10:04:14 -08'00' From:Salazar, Grace (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Disposal Injection Order No. 45 Date:Monday, April 18, 2022 12:03:42 PM Attachments:DIO 45.pdf The Alaska Oil and Gas Conservation Commission has issued the attached Disposal Injection Order, granting Vision Operating, LLC’s requested authorization for underground disposal of Class II oil field waste fluids into the existing North Fork Unit 23-25. Grace Respectfully, M. Grace Salazar, Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Direct: (907) 793-1221 Email: grace.salazar@alaska.gov https://www.commerce.alaska.gov/web/aogcc/ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: grace.salazar@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/grace.salazar%40alaska.gov AOGCC 333 W 7th Avenue, Anchorage, AK 99501 TO: BERNIE KARL K&K RECLYCLING, INC. PO BOX 58055 FAIRBANKS, AK 99711 Mailed 4/18/22 gs Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVAL DISPOSAL INJECTION ORDER 45.001 Mr. Stephen Hennigan Vision Operating, LLC. 188 W. Northern Lights Blvd., Suite 515 Anchorage, AK 99503 Re: Docket Number: DIO-24-001 Request for Reauthorization of Disposal Injection Order (DIO) 45 North Fork Unit well 23-25, Tyonek Formation, Cook Inlet Basin Dear Mr. Hennigan: By emailed letter dated March 11, 2024, Vision Operating, LLC (Vision) requested an extension of the DIO 45 approval as per 20 AAC 25.252(j), which is set to expire April 16, 2024. In accordance with 20AAC 25.556(d), the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS Vision’s request and will extend the DIO 45 approval by an additional 12 months to April 16, 2025. DONE at Anchorage, Alaska and dated March 18, 2024. Brett W. Huber, Sr Jessie L. Chmielowski Gregory C. Wilson Chair, Commissioner Commissioner Commissioner Gregory Wilson Digitally signed by Gregory Wilson Date: 2024.03.18 16:13:06 -08'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.03.18 16:36:10 -08'00' Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2024.03.18 20:59:13 -05'00' DIO 45.001 March 18, 2024 Page 2 of 2 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. From:Coldiron, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Disposal Injection Order 45.001 (Vision Operating) Date:Tuesday, March 19, 2024 7:51:27 AM Attachments:dio 45.001.pdf Docket Number: DIO-24-001 Request for Reauthorization of Disposal Injection Order (DIO) 45 North Fork Unit well 23-25, Tyonek Formation, Cook Inlet Basin Samantha Coldiron Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: samantha.coldiron@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.coldiron%40alaska.go v 6 188 W. Northern Lights Blvd - Suite 515 Anchorage, AK 99503 March 11, 2024 Mr. Brett Huber, Chair Alaska Oil and Gas Conservation Commission 333 W. 7th Ave Anchorage, AK 99501 In Re: Request for Reauthorization of Disposal Injection Order (DIO) 45 Dear Commissioner Huber, Vision’s application for a Disposal Injection Order (DIO) in their North Fork Field was approved on April 16, 2022. 20 AAC 25.252 (h) (2) (j) provides “If disposal or storage operations are not begun within 24 months after the approval date, the approval will expire unless an application for extension is approved by the Commission.” Since approval, no disposal injection has been initiated as allowed by DIO 45. Vision still desires to have the ability to ultimately dispose of Class II wastes. By copy of this letter, Vision Operating makes application to extend the validity of DIO 45. Thank you in advance for consideration of this request. Please contact myself at 337-849-5345 or Tom Maunder, P.E. at 907-529-1645 if further information is needed. We both will be in Anchorage through the end of April. Sincerely, Stephen Hennigan By Samantha Coldiron at 9:23 am, Mar 11, 2024 5 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:bbritch@alaska.net To:Wallace, Chris D (OGC); Davies, Stephen F (OGC); Salazar, Grace (OGC) Cc:"Steve Hennigan"; scott@sevendog.net Subject:RE: DIO-21-002 Hearing - Additional Questions and responses Date:Monday, February 21, 2022 2:11:29 PM Attachments:022122 DIO-21-002 Hearing Question Responses TEM SFH.pdf Affidavit-2-18-2022-SFH.pdf Chris Wallace Attached is a copy of our responses to your questions as indicated in email below. I have also provided another copy of the affidavit for distribution of our application to landowners within ¼ mile; as indicated in our previous submittal, the original affidavit is being sent via mail. Please let us know if you have any more questions. Thanks Bob Britch 907-240-5830 From: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Sent: Tuesday, February 15, 2022 4:26 PM To: bbritch@alaska.net; 'Steve Hennigan' <shennigan@gardesholdings.com> Cc: Salazar, Grace (OGC) <grace.salazar@alaska.gov>; Davies, Stephen F (OGC) steve.davies@alaska.gov>; scott@sevendog.net Subject: DIO-21-002 Hearing - Additional Questions Bob, Steve, Thanks to you and the Vision team for the attendance at the DIO hearing this morning. As discussed, we would like to see any additional information that you can provide as specified in 20 AAC 25.252(c)(9)—“…support a commission finding that the proposed disposal or storage operations will not initiate or propagate fractures through the confining zones…”? Please provide the estimated fracturing gradients for the proposed injection sands in Zones 1 and 2 and for the upper and lower confining intervals for Zones 1 and 2 in units of either psi/foot or pounds per gallon equivalent mud weight. How were these values determined? What well information was used? Has Vision performed any computer simulation studies for the proposed injection operations? If so, what are the anticipated half-lengths and heights for induced fractures? Please provide the basis for the estimated surface pressure values shown on Slide 16 from the hearing today. How were the bottom-hole injection initiation pressures shown on this slide determined? Are the minimum estimated surface pressure values provided on this slide also Vision’s expected average daily surface injection pressures? If not, what are Vision’s expected average daily pressures? What I would like to see is additional rows and information on the DIO Application “Table G-1 Representative Injection Pressures”, which was Hearing Slide 16 for: Zone 2 Upper Confining 4965-5155 ft TVD Zone 2 Lower Confining Layer 5960-6155 ft TVD Zone 1 Upper Confining Layer 7378-7666 Zone 1 Lower Confining Layer 8766-8974 TVD As per 20 AAC 25.252(c)(8), in the DIO we like to establish a maximum disposal rate and a maximum disposal surface pressure (based on water density) to establish a maximum sand face pressure that will not initiate or propagate fractures through the confining zones…”. If we cannot determine this before the order is issued, we would need to establish this per interval with step rate tests as per the DIO application Attachment E. Also, 20 AAC 25.252 (c)(3) states an application must include “an affidavit showing that the operators and surface owners within a one-quarter mile radius have been provided a copy of the application for disposal or storage” I do not see such an affidavit? Has the DIO application been provided to the surface owners identified on the DIO application pages B3, B4, B5, and B6? 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. DIO-21-002 Page 1 2/21/2022 Response to DIO-21-002 Hearing – Additional Questions As of 2/15/2022 Fracture gradients for the injection zones were determined by utilizing actual data to determine a “field trend” within the Cook Inlet basin to allow a regional trend to be determined (Charles Prentice Schools) and then applied that data to confirm Eaton Frac Gradient calculations (Eaton Schools). To determine the field trend, the drilling records for the field were reviewed for formation tests. Lost return events were also looked for (none). Those formation tests available were plotted vs depth to determine a trend The data available was minimal. The Eaton formula was modified to fit the trend. Both can be seen in Figure 1 attached. Once the fit was determined to be probable, the injection table below now modified Table 1) was created knowing that the numbers would probably need to be modified after performing a step rate test where appropriate. The table below emphasizes minimum and maximum injection pressures based upon calculations but may require additional testing in the field to update. The expected average injection pressure was not considered initially, as the surface pressure would vary greatly depending on the slurry weight being injected at the time. Over time the daily injection pressure would tend to increase for the same volume. But in Figure 1 (Attached), a fracture extension pressure line is drawn which again is calculated by an Eaton formula. The extension values are listed in Table 1. Based on these numbers the average injection pressure for each zone could range from ±300-±700 lower than the max/min calculated based upon weight of the slurry. Table 1 (Modified, 02/16/2021) Zone TVD Eaton Calc Frac Grad FG) Min Max Max Min MIN Requested Rate (bpm) feet ppge Zone 2 Top Upper Confng Layer 4965 16.5 4252 3789 8.3 16 2610 630 Zone 2-F 5155 16.6 4440 3960 8.3 16 2720 660 2.5 Zone 2-E 5375 16.7 4660 4160 8.3 16 2840 690 Zone 2-D 5535 16.7 4819 4305 8.3 16 2940 720 Zone 2-B,C 5701 16.8 4986 4458 8.3 16 3030 750 Zone 2-A 5901 16.9 5188 4642 8.3 16 3150 780 Zone 2 Lower Confng Layer 5960 16.9 5247 4696 8.3 16 3180 790 Zone 1 Upper Confng Layer 7378 17.4 6688 6019 8.3 16 4010 1050 Zone 1-G 7666 17.5 6982 6291 8.3 16 4180 1110 2.75 Zone 1-F 7786 17.5 7106 6405 8.3 16 4250 1130 Zone 1-E 7866 17.6 7191 6490 8.3 16 4300 1150 Zone 1-D 8006 17.6 7334 6622 8.3 16 4380 1180 Zone 1-C 8241 17.7 7580 6864 8.3 16 4530 1230 Zone 1-B 8351 17.7 7693 6969 8.3 16 4590 1250 Zone 1-A 8726 17.8 8079 7336 8.3 16 4820 1320 3 Zone 1 Lwr Confng Layer 8766 17.8 8120 7374 8.3 16 4840 1330 Addtl 500 psi added for friction, actual pressures encountered may be higher or lower Step rate tests may be required Injectant Slurry wt (ppg) Surface PSI* EstimatedBottom hole Estimated Injection Initiation psi) Bottom hole Estimated Frac Extension psi) ppg psi DIO-21-002 Page 2 2/21/2022 Computer simulation studies were NOT run for the proposed injection operations. Prior disposal requests related to Buccaneer Kenai Loop area (DIO 38, Class II with the AOGCC) and for Blue Crest Cosmopolitan area (Class I with the EPA) were examined. Blue Crest is most similar and proximate to the proposed North Fork activity. The Blue Crest analysis ranged from 3339’TVD–/6693’ TVD in the Tyonek formation with perforations at ±6335’ TVD, see Fig 2 below. Figure 2. Note that the picture is mislabeled as MD – it is actually TVD This length shown above is considered to be the most that the proposed well might provide. Similar to that, the maximum frac height would be less than 50’. Therefore, the upper and lower confining zones are more than adequate to “confine” the injectants as designed. The cement bond log shows adequate bond therefore adding additional protection for the injectants to breach the confining zone. A picture of the bond on the uppermost confining zone is below. DIO-21-002 Page 3 2/21/2022 Figure 3. CBL over Upper Confining Zone DIO-21-002 Page 4 2/21/2022 Attached Figure 1 4 AOGCC 2/15/2022 ITMO: APPLICATION OF VISION OIL & GAS Docket No. DIO-21-002; AEO-21-00 Computer Matrix, LLC 329 F Street, Ste. 222., Anch. AK 99501 Phone: 907-227-5312 Fax: 907-243-1473 Email: sahile@gci.net ALASKA OIL AND GAS CONSERVATION COMMISSION In the Matter of the Application of ) Vision Oil and Gas for a Class II ) Underground Injection Control Well ) Permit for its North Fork Unit located ) on the Kenai Peninsula and an Aquifer ) Exemption for all Portions of Sections ) 25, 26, 35 and 36 in Township 4 South, ) Range 14 West, Seward Meridian That Lie ) Within the Boundaries of the North Fork ) Unit. ) Docket No.: DIO-21-002; AEO-21-001 PUBLIC HEARING February 15, 2022 10:00 o'clock a.m. BEFORE: Jeremy Price, Chairman Jessie Chmielowski, Commissioner Daniel T. Seamount, Commissioner AOGCC 2/15/2022 ITMO: APPLICATION OF VISION OIL & GAS Docket No. DIO-21-002; AEO-21-00 Computer Matrix, LLC 329 F Street, Ste. 222., Anch. AK 99501 Phone: 907-227-5312 Fax: 907-243-1473 Email: sahile@gci.net Page 2 1 TABLE OF CONTENTS 2 Opening remarks by Chairman Price 03 3 Testimony by Bob Britch 07 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 AOGCC 2/15/2022 ITMO: APPLICATION OF VISION OIL & GAS Docket No. DIO-21-002; AEO-21-00 Computer Matrix, LLC 329 F Street, Ste. 222., Anch. AK 99501 Phone: 907-227-5312 Fax: 907-243-1473 Email: sahile@gci.net Page 3 1 P R O C E E D I N G S 2 (On record - 10:03 a.m.) 3 CHAIRMAN PRICE: Good morning. We're now on 4 record. It's approximately 10:03 a.m., Tuesday, 5 February 15th, 2022. This is Jeremy Price, Chairman 6 and Commissioner. With me today are Commissioner Dan 7 Seamount to my left, Commissioner Jessie Chmielowski to 8 my right. 9 This is a public hearing on docket number DIO- 10 21-002 to consider Vision's application for a class II 11 underground injection control well permit for its North 12 Fork Unit located on the Kenai Peninsula and docket 13 AEO-21-001, an aquifer exemption for all portions of 14 sections 25, 25, 35 and 36, in township 4 south, range 15 14 west, Seward Meridian, that lie within the 16 boundaries of the North Fork Unit. 17 Before I proceed any further, folks on the line 18 go ahead and please mute your lines until you're ready 19 to speak. 20 I'll finish doing this intro. This hearing is 21 being held in accordance with Alaska statute 44.62, 20 22 AAC 25.252, 20 AAC 25.440 and 20 AAC 25.540 of the 23 Alaska Administrative Code. 24 For awareness purposes to the public and to the 25 media, the regulations for disposing of oil field waste AOGCC 2/15/2022 ITMO: APPLICATION OF VISION OIL & GAS Docket No. DIO-21-002; AEO-21-00 Computer Matrix, LLC 329 F Street, Ste. 222., Anch. AK 99501 Phone: 907-227-5312 Fax: 907-243-1473 Email: sahile@gci.net Page 4 1 underground are found in chapter 25, section 252 while 2 the regulations governing freshwater aquifer exemptions 3 are found in chapter 25, section 440. 4 As explained in the public notice, but I'll 5 repeat here, an aquifer is an underground body of 6 water, saturated rock or sediments that can store 7 and/or transmit water. Regulations that allow the US 8 EPA and the state of Alaska to exempt an aquifer or 9 portion of an aquifer if it does not serve as a source 10 of drinking water now or will not in the future or if 11 it meets other criteria such as natural presence of 12 hydrocarbons, existing contamination or elevated 13 dissolved solids concentration. An order granting 14 exemption allows an underground aquifer or a specified 15 portion of an aquifer to be used for oil and gas 16 related production, injection or disposal purposes in 17 compliance with EPA's requirements under the Safe 18 Drinking Water Act and state of Alaska regulations. 19 So just again a little further explanation for 20 folks on the purposes of the hearing today. 21 On December 21st, 2021, Vision filed a 72 page 22 document detailing application for a class II UIC well 23 permit on the North Fork Unit and a freshwater aquifer 24 exemption for sections 25, 26, 35 and 36 of Township 4 25 South, Range 14 West, Seward Meridian that lie within AOGCC 2/15/2022 ITMO: APPLICATION OF VISION OIL & GAS Docket No. DIO-21-002; AEO-21-00 Computer Matrix, LLC 329 F Street, Ste. 222., Anch. AK 99501 Phone: 907-227-5312 Fax: 907-243-1473 Email: sahile@gci.net Page 5 1 the boundaries of the North Fork Unit. 2 The notice of hearing for docket DIO-21-002 was 3 published in the state of Alaska online notices website 4 as well as the AOGCC's website and was sent through the 5 AOGCC email list serve on January 7th, 2022. The AOGCC 6 also published a notice on the Anchorage Daily News on 7 January 9th, 2022. The notice of hearing was published 8 on the state of Alaska online notices website and well 9 as the AOGCC's website as well as the AOGCC internal 10 list serve. To date AOGCC has not received any public 11 comments on the matter. 12 Today's hearing is being held in person, 13 telephonically and via Microsoft Teams. Again please 14 be mindful of any background noise and make sure you 15 are muted when you're not testifying or addressing the 16 Commission. 17 If you require any other special accommodation, 18 please contact Grace Salazar. She can be reached at 19 793-1221 -- sorry, 1221. She can also see the messages 20 if you post a message a Microsoft Teams she can see it 21 there in the chat icon. 22 Computer Matrix is recording the hearing today. 23 Anyone desiring a transcript of the hearing, would like 24 one, please contact Computer Matrix. 25 Before asking Vision to present their -- make AOGCC 2/15/2022 ITMO: APPLICATION OF VISION OIL & GAS Docket No. DIO-21-002; AEO-21-00 Computer Matrix, LLC 329 F Street, Ste. 222., Anch. AK 99501 Phone: 907-227-5312 Fax: 907-243-1473 Email: sahile@gci.net Page 6 1 their presentation, do either Commissioners have any 2 comments or questions to make at this time? 3 COMMISSIONER SEAMOUNT: I have none. Thank 4 you. 5 COMMISSIONER CHMIELOWSKI: I have none. 6 Thanks. 7 CHAIRMAN PRICE: Thank you. Okay. At this 8 time so, Mr. Britch, I guess we can swear all of you in 9 at the same time if that's what you'd like. How about 10 each of you who are going to speak, if you could give 11 your name and affiliation for the record. Why don't we 12 start there, we'll start with you and then go to the 13 folks on the phone and then I'll swear you all in. 14 Does that work? 15 MR. BRITCH: Hello. My name's Bob Britch, I'm 16 a consultant to Vision on permitting. 17 CHAIRMAN PRICE: Okay. And for folks on the 18 phone that are going to be testifying today, can you 19 give your name and affiliation? 20 MR. HENNIGAN: My name is Steven Hennigan, I'm 21 an officer in Vision. I do not plan on testifying, but 22 I'm available for any questions that might come up and 23 I'll turn it over to Scott and the others. Go ahead 24 and introduce yourself, please. 25 MR. DANIEL: My name is Scott Daniel, I'm a AOGCC 2/15/2022 ITMO: APPLICATION OF VISION OIL & GAS Docket No. DIO-21-002; AEO-21-00 Computer Matrix, LLC 329 F Street, Ste. 222., Anch. AK 99501 Phone: 907-227-5312 Fax: 907-243-1473 Email: sahile@gci.net Page 7 1 consulting geologist. Like Steve I am not planning on 2 testifying today, but I am available for questions and 3 if I need to expound on something I'm available. 4 MR. LAMP: My name is Mark Lamp, I'm also an 5 officer of Vision Operating and will be available for 6 questions. I do not plan to testify at this stage. 7 CHAIRMAN PRICE: Okay. Is that everybody? 8 MR. BRITCH: I believe it is. 9 CHAIRMAN PRICE: Okay. Then we'll just swear 10 you in, Mr. Britch. If you could raise your right 11 hand. 12 (Oath administered) 13 MR. BRITCH: I do. 14 CHAIRMAN PRICE: Thank you, sir. Okay. If 15 you're ready, please proceed with your presentation. 16 BOB BRITCH 17 called as a witness on behalf of Vision Oil and Gas, 18 testified as follows on: 19 DIRECT EXAMINATION 20 MR. BRITCH: Hi. I'm Bob Britch and I'll be 21 doing the presentation. The first -- or the slide on 22 your screen right now is -- shows a list of the people 23 and we've pretty much gone through those unless..... 24 Steve, did you have anything else about some of 25 the other presenters? AOGCC 2/15/2022 ITMO: APPLICATION OF VISION OIL & GAS Docket No. DIO-21-002; AEO-21-00 Computer Matrix, LLC 329 F Street, Ste. 222., Anch. AK 99501 Phone: 907-227-5312 Fax: 907-243-1473 Email: sahile@gci.net Page 8 1 MR. HENNIGAN: Just continue to proceed, Bob. 2 MR. BRITCH: Okay. Thank you. 3 CHAIRMAN PRICE: Mr. Britch, I guess I just 4 realized I kind of skipped a step. Would you mind just 5 giving some of your background, the credentials you 6 might have, work experience? 7 MR. BRITCH: Sure. I have a BS and a MS degree 8 in civil engineering from the University of Alaska, 9 Fairbanks, back in the '70s. And since then I've been 10 in a private consulting business for a number of major, 11 local, international, national consulting firms 12 primarily doing regulatory work, engineering work and 13 environmental science type work throughout Alaska. I 14 was born in Alaska and have spent most of my 15 professional career in the entire state, working mostly 16 for oil and gas companies. I think I've worked for 17 just about every major oil and gas company operating in 18 Alaska over the last 50 years. 19 CHAIRMAN PRICE: Thank you. Please proceed. 20 MR. BRITCH: Okay. The slide up now is a 21 location map of the project that's down on the Kenai 22 Peninsula just east of Anchor Point. It's about from 23 -- its access is through a paved road about 12 miles 24 long to the site and the site is right off of the North 25 Fork pad. AOGCC 2/15/2022 ITMO: APPLICATION OF VISION OIL & GAS Docket No. DIO-21-002; AEO-21-00 Computer Matrix, LLC 329 F Street, Ste. 222., Anch. AK 99501 Phone: 907-227-5312 Fax: 907-243-1473 Email: sahile@gci.net Page 9 1 The pad itself is a five acre gravel pad that's 2 bounded by fencing and gates and controlled. There's 3 some housing, usually there's a crew of two to four 4 people on site at all times for the existing 5 production. They are right now producing natural gas 6 and they have plans for additional production on the 7 pad. The gas currently goes through two fiberglass 8 pipelines from the site over to Anchor Point where it 9 ties into Enstar pipelines. And I believe..... 10 Steve, is our current production for the 11 facility about 3 million cubic feet per day? 12 MR. HENNIGAN: Yeah, it is. Slightly greater 13 than 3 million cubic feet a day. 14 And I want to apologize, another one of our 15 consultants, Tom Launder, is also on the call. Sorry. 16 MR. BRITCH: Okay. And just one other point 17 since it was asked. There are no other existing oil 18 and gas operations that I am aware of within five miles 19 of the site and I've asked a number of people and I 20 think there's some activities that Hilcorp is doing 21 north of the site, but I don't think they're in any 22 proximity, but there's -- we're it. We have about 25 23 acres, 26 acres of property that are owned by the 24 corporation or the company. 25 This next one is -- just covers the aquifer AOGCC 2/15/2022 ITMO: APPLICATION OF VISION OIL & GAS Docket No. DIO-21-002; AEO-21-00 Computer Matrix, LLC 329 F Street, Ste. 222., Anch. AK 99501 Phone: 907-227-5312 Fax: 907-243-1473 Email: sahile@gci.net Page 10 1 exemption request. We submitted a request for aquifer 2 exemption to EPA on 12/7 of this -- of last year and 3 basically the area include -- or the area requested for 4 aquifer exemption is indicated by a dotted blue line 5 which you can -- I think it kind of fades away, but the 6 horizontal extent is those areas of sections 25, 26, 35 7 an 36 within township 4 south, range 14 west, Seward 8 Meridian, that lie within the boundaries of the North 9 Fork Unit which is the outer red line. So it's just 10 those portions of the sections that are within the 11 boundaries of the North Fork Unit. 12 The vertical extent of the aquifer exemption is 13 primarily or is the Tyonek formation, the upper, middle 14 and lower units. And that -- this area extends at the 15 -- at the wellsite from about 4,900 feet down to about 16 8,900 feet. And it's -- and it varies, the Tyonek 17 formation bends over and it -- it goes up and down. 18 But anyway the -- all the existing gas production is 19 contained within the boundaries of the Tyonek formation 20 and all the planned injection operations are also going 21 to be in the Tyonek formation. 22 This one is a little bit hard to see on the 23 slide, but the inner red line which is the wellbore, 24 the west end is at the North Fork pad and the 25 bottomhole is at the northeast end of the pad. And the AOGCC 2/15/2022 ITMO: APPLICATION OF VISION OIL & GAS Docket No. DIO-21-002; AEO-21-00 Computer Matrix, LLC 329 F Street, Ste. 222., Anch. AK 99501 Phone: 907-227-5312 Fax: 907-243-1473 Email: sahile@gci.net Page 11 1 red circle or oblong shape around that is a distance of 2 a quarter mile from the wellbore horizontally and just 3 shows what is in the general area. 4 There are a number of mostly residential 5 property, the yellow lines are lot lines and they 6 typically range from about four acres in size to maybe 7 about 20 acres in size. And there's also a number of 8 property that's owned by both the state of Alaska down 9 in the southeast corner and the Kenai Peninsula Borough 10 up there in the center top and they have various 11 acreage down throughout the property. 12 The intent of this slide is also to show water 13 wells in the general area. There are no water wells 14 within the one-quarter mile of the wellbore, but there 15 are eight in the general area. All of them are private 16 and they're all pretty shallow, the deepest is 143 feet 17 and goes down following the list down to about seven 18 feet. And the wells are all in -- we'll assume that 19 they all have potable water. The proximity to the 20 wellbore, horizontally they range from about 1,720 feet 21 to 4,960 feet horizontally. And vertically they're all 22 over 4,700 feet vertical separation from where we're 23 injecting and to where the well -- the water wells are. 24 And we're at present looking at the -- and 25 probably final, we had a wellbore that -- the NFU well AOGCC 2/15/2022 ITMO: APPLICATION OF VISION OIL & GAS Docket No. DIO-21-002; AEO-21-00 Computer Matrix, LLC 329 F Street, Ste. 222., Anch. AK 99501 Phone: 907-227-5312 Fax: 907-243-1473 Email: sahile@gci.net Page 12 1 2325, which was drilled a while back and it had some 2 gas and I -- and it really was a very low producer. So 3 we're going to be using the area now as two major zones 4 for injection. The lower one is in the lower Tyonek 5 formation and there are seven different zones from A to 6 G and they're at the various depths indicated on the -- 7 on the table with the top and the bottom elevations. 8 It's all in true vertical depth. 9 We also have some upper and lower confining 10 layer in both zone one and zone two and that typically 11 has up to about 200 feet of vertical height where -- 12 which are shales and maybe some coals that are 13 impermeable and those are the confining layers. Oh, 14 the upper zone, zone two, that has six zones and 15 they're just -- we have a log that shows how they're 16 organized. 17 One other key point here is the total dissolved 18 solids which indicate the water quality in the 19 surficial soils down to the Sterling formation, it's 20 all less than 3,000 milligrams per liter of total 21 dissolved solids so it's considered somewhat potable. 22 Within a lot of the Beluga and all of the Tyonek it all 23 ranges from 30,000 to 20,000 or 3,000 to 20,000 24 milligrams per liter. 25 If anybody has any questions would it -- is it AOGCC 2/15/2022 ITMO: APPLICATION OF VISION OIL & GAS Docket No. DIO-21-002; AEO-21-00 Computer Matrix, LLC 329 F Street, Ste. 222., Anch. AK 99501 Phone: 907-227-5312 Fax: 907-243-1473 Email: sahile@gci.net Page 13 1 appropriate to just interrupt me? 2 CHAIRMAN PRICE: Will do. Yeah, appreciate it. 3 MR. BRITCH: Okay. These are some of the logs. 4 The brown area -- this starts in zone one and the brown 5 area is the upper confining layer. And the yellow 6 areas are areas of sands. And in this -- in zone one 7 there was seven sandy areas in there where we're going 8 to be injecting. 9 And the next slide shows the rest of the 10 formation. 11 This is the bottom of the -- the brown is the 12 bottom of the area one or zone one and here too there's 13 a confining layer down at the bottom. And there's a -- 14 only several of these things that are in this slide 15 that are used. Only the two sections on the left-hand 16 side are zones, I think one and 1A and 1B. 17 This is zone two, this is on top. And here 18 again we have an upper confining layer and then the -- 19 in brown and the six zones in yellow going from B1 to B 20 -- E or F. And they're all the same sands. And 21 they're -- the top and bottom of all these zones is 22 typically some sort of a shale. 23 COMMISSIONER CHMIELOWSKI: Mr. Britch. 24 MR. BRITCH: Yes. 25 COMMISSIONER CHMIELOWSKI: Has Vision confirmed AOGCC 2/15/2022 ITMO: APPLICATION OF VISION OIL & GAS Docket No. DIO-21-002; AEO-21-00 Computer Matrix, LLC 329 F Street, Ste. 222., Anch. AK 99501 Phone: 907-227-5312 Fax: 907-243-1473 Email: sahile@gci.net Page 14 1 the lateral continuity of these confining layers? 2 MR. BRITCH: Scott, is that your question 3 or..... 4 MR. DANIEL: Say the question again, ma'am. 5 COMMISSIONER CHMIELOWSKI: I was asking whether 6 Vision has confirmed the lateral continuity of the 7 confining layers? 8 MR. DANIEL: If you notice all of the TU, C11, 9 C12, C13A, et cetera, we have correlated about 60 coals 10 through there that gives us definition of correlations 11 and ties. The nature of the sands is that of fluvial 12 sand. These are deposited as channel and we have tied 13 all of them to the coal. We have evidence of some of 14 these channels looking like the same sand and not being 15 connected, but, you know, they're going to have good 16 porosity and permeability at the location where they 17 are being injected into and yes, they should have 18 continuity. If it is exactly the same sand from one 19 well to the next, that has not been determined and it's 20 the nature of the deposition of the sands. 21 Does that answer your question? 22 COMMISSIONER CHMIELOWSKI: Yes. Thank you. 23 Can you also speak to the continuity of the confining 24 layers other than the shales, the upper and lower 25 confining layers? AOGCC 2/15/2022 ITMO: APPLICATION OF VISION OIL & GAS Docket No. DIO-21-002; AEO-21-00 Computer Matrix, LLC 329 F Street, Ste. 222., Anch. AK 99501 Phone: 907-227-5312 Fax: 907-243-1473 Email: sahile@gci.net Page 15 1 MR. DANIEL: Well, the confining layers are 2 quite continuous. They -- like I said we're defining 3 the sand -- the coals and the shales within -- between 4 the coals have good extent. It's the sands that tend 5 to meander and move about because they're being 6 deposited in the channel at the time. So those have 7 good continuity, yes. 8 COMMISSIONER CHMIELOWSKI: Thank you. 9 MR. DANIEL: Okay. Does that answer it? 10 MR. BRITCH: We have an example of a couple of 11 the zones, just to show you a little bit about how it 12 looks horizontally. Okay. And this is just a 13 confining layer for the -- is that the upper -- oh, 14 lower confining layer. This is below the zone two. So 15 we have a confining layer both on the top and bottom 16 for each of these two zones. 17 Okay. This next slide is some of the 18 information that shows you kind of a horizontal display 19 of the formations. This is the map of the top of the 20 upper confining -- no, it's -- yeah, upper confining 21 formation for injection zone one. And something you'll 22 notice is that the injection zone is currently between 23 two faults, the purple one is the Bravo fault and the 24 green one is the Popeye fault. And the basically the 25 Bravo fault, the purple one seems to provide a barrier AOGCC 2/15/2022 ITMO: APPLICATION OF VISION OIL & GAS Docket No. DIO-21-002; AEO-21-00 Computer Matrix, LLC 329 F Street, Ste. 222., Anch. AK 99501 Phone: 907-227-5312 Fax: 907-243-1473 Email: sahile@gci.net Page 16 1 to vertical or excuse me, horizontal movement of the 2 gasses. There tends to be gas on the southwest side, 3 but the gas is a lot more or a lot lower on the eastern 4 or northeastern side of that fault. The Popeye fault 5 is probably a little bit more permeable, but the Bravo 6 fault seems to stop a lot of stuff. 7 COMMISSIONER CHMIELOWSKI: And just to confirm 8 the Bravo fault is that larger purple one? 9 MR. BRITCH: Large purple one. 10 COMMISSIONER CHMIELOWSKI: And so it's a 11 sealing fault, you don't have to have fluids or gas 12 migrate across it? 13 MR. BRITCH: I would have to say yes. Scott, 14 do you want to..... 15 MR. DANIEL: No, we would not expect to have 16 gas migrating across that. It actually separates down 17 throne gas production and up throne it tends to be wet. 18 Okay? 19 MR. BRITCH: Thank you. The next slide just 20 shows higher up in the formation and here the faults 21 are a little bit further away from us. And this is 22 upper in the formation, this is the top -- contour for 23 the top confining formation for zone two. And as 24 you'll see it's a fairly uniform formation and we have 25 confidence that the confining layer is there and it AOGCC 2/15/2022 ITMO: APPLICATION OF VISION OIL & GAS Docket No. DIO-21-002; AEO-21-00 Computer Matrix, LLC 329 F Street, Ste. 222., Anch. AK 99501 Phone: 907-227-5312 Fax: 907-243-1473 Email: sahile@gci.net Page 17 1 will seal. 2 CHAIRMAN PRICE: Try and get closer to that 3 microphone when you talk, Mr. Britch. 4 MR. BRITCH: Okay. 5 CHAIRMAN PRICE: Thank you. 6 MR. BRITCH: Is that better? Okay. This next 7 slide is a estimate of what we plan on discharging. 8 And 75 or 73 percent of the fluids that we're going to 9 be discharging are the produced water. And basically 10 this is produced water which comes up from the Tyonek 11 formation and is separated from the gas and then being 12 reinjected back into the Tyonek formation. So it's the 13 same -- they're the same fluids. 14 Next largest volume is the well workover fluids 15 and that's about 23 percent of the volume. And it's 16 primarily brines and with some erosion inhibitors or 17 corrosion inhibitors. 18 The other exempt fluids, fairly small amount, 19 about 2 percent. And then drilling muds and cuttings, 20 they're planning on drilling wells the first seven or 21 the next seven years. And that will only include about 22 1.1 percent of the total volume discharged. And that 23 will stop after about the seventh year. Total we 24 expect to be discharging about 15.6 million barrels of 25 effluents. AOGCC 2/15/2022 ITMO: APPLICATION OF VISION OIL & GAS Docket No. DIO-21-002; AEO-21-00 Computer Matrix, LLC 329 F Street, Ste. 222., Anch. AK 99501 Phone: 907-227-5312 Fax: 907-243-1473 Email: sahile@gci.net Page 18 1 CHAIRMAN PRICE: I missed that. Did you say -- 2 did you specify the number of wells they're planning on 3 drilling in the next seven years, did you say a number 4 of wells? 5 MR. BRITCH: I'd have to ask Steve Hennigan 6 about the number of wells for the next seven years. 7 CHAIRMAN PRICE: I didn't mean to put you on 8 the spot, I thought you just mentioned how many wells 9 you're going to drill over the next seven years. Maybe 10 I misheard you. 11 MR. BRITCH: No, I didn't. 12 CHAIRMAN PRICE: Okay. Understood. Thanks. 13 MR. BRITCH: Steve Hennigan, are you there? 14 MR. HENNIGAN: It's still being geologically or 15 geophysically reviewed, but we've identified up to 23 16 prospects in the area. 17 CHAIRMAN PRICE: Thank you. 18 MR. BRITCH: Okay. This next slide -- okay. 19 One of the things we wanted to try to figure out is we 20 have a volume which is about 15.6 million barrels and 21 we're trying to estimate some -- estimate about how 22 much floor space that would require. Our geologist did 23 calculations to come up with the effective porosity 24 that's basically how much fluids can fit into the 25 formation and we had -- we subtracted some space for AOGCC 2/15/2022 ITMO: APPLICATION OF VISION OIL & GAS Docket No. DIO-21-002; AEO-21-00 Computer Matrix, LLC 329 F Street, Ste. 222., Anch. AK 99501 Phone: 907-227-5312 Fax: 907-243-1473 Email: sahile@gci.net Page 19 1 fluids that can't be removed or replaced in the 2 formation. We looked at average permeabilities and 3 from that we just calculated how much core volume we 4 had within a 1,200 foot radius of the injection or the 5 perforation point. And we know how thick the injection 6 layer is and the general features of the zones. We had 7 a comment from AOGCC on how we calculated that and we 8 sent Steve a copy of our calculations. I'd just like 9 to ask him if he got them. 10 COMMISSIONER SEAMOUNT: Mr. Britch. 11 MR. BRITCH: Yes. 12 COMMISSIONER SEAMOUNT: The field's currently 13 making 3 million cubic feet a day, how much water does 14 it make? 15 MR. BRITCH: Right now I -- it's pretty low. 16 My own personal understanding is it's -- Steve, is it -- 17 I'm pretty sure it's less than 50 barrels a day. Is 18 that correct, Steve? 19 MR. HENNIGAN: It probably averages two barrels 20 a day. The point -- you know, I've been involved with 21 this field since Armstrong tested and drilled their 22 first well. A lot of the zones have been left because 23 they started to produce water. And there's still 24 significant amounts of gas remaining in those zones. 25 Our hope is that if we can find a way to dispose of AOGCC 2/15/2022 ITMO: APPLICATION OF VISION OIL & GAS Docket No. DIO-21-002; AEO-21-00 Computer Matrix, LLC 329 F Street, Ste. 222., Anch. AK 99501 Phone: 907-227-5312 Fax: 907-243-1473 Email: sahile@gci.net Page 20 1 produced water we can go back to those zones that were 2 producing significant gas with significant water and be 3 able to optimize the hydrocarbon recovery. So that -- 4 that's the general plan. 5 COMMISSIONER SEAMOUNT: Okay. Thank you. 6 MR. BRITCH: Okay. Next slide kind of shows 7 the capacities from each of the zones. And zone one 8 would probably be -- we have some wellbores, but zone 9 one could be perfed. All the perfs perfed at one time. 10 There's two perfs already in the deal, the top -- the 11 top two, I think one G and one F and those are at two 12 of the injection points. And all the other five perfs 13 would have to be redone. We don't know if we'll inject 14 first off the two perfs, that'll get us through a 15 couple of years, but or they may perf all at once. But 16 they'll start perfing down in zone one first and then 17 when that's filled up here we're saying it will reach 18 capacity somewhere around year 24. And then we'll perf 19 zone two and that'll bring us up to a capacity of about 20 47 million barrels. 21 When we actually looked at the capacity we also 22 made some corrections for zone one and zone two. Zone 23 one corrections were primarily because of zone one lies 24 between the Popeye and the Bravo fault and basically 25 the spacing on that is about 2,500 feet. And if we AOGCC 2/15/2022 ITMO: APPLICATION OF VISION OIL & GAS Docket No. DIO-21-002; AEO-21-00 Computer Matrix, LLC 329 F Street, Ste. 222., Anch. AK 99501 Phone: 907-227-5312 Fax: 907-243-1473 Email: sahile@gci.net Page 21 1 have a 2,800 diameter radius for injection, that's 2 1,400 per -- no, I'm sorry, 2,400, but we'll still come 3 up and come against some of those faults. And assuming 4 that both of them are barriers, we won't be able to use 5 the total volume within that circle and realistically 6 you probably actually gain a lot of that area back by 7 having oblong shaped injection zones between the two 8 faults. But just to be conservative with assume that 9 only 50 percent of the area between the two faults in 10 zone one would be available for injection. So that's 11 that zone one at the bottom. 12 And then zone two -- zone one would be shut in 13 and zone two would be added onto the top. And here 14 again we're not -- I'm not sure that they have plans 15 for how many of the zones they'll perf, but I assume 16 they'll start at the bottom and kind of as needed. I 17 think they also need to see what happens with zone one 18 to see -- given them a little bit of guidance of how 19 it's going to work. 20 This shows an estimate of the typical injection 21 pressures. The -- to initiate it we'll need to have 22 slightly higher injection pressures and the estimated 23 bottomhole and surface pressures are indicated there. 24 The injection rates will run from about three barrels 25 per minute for the lower zone to about 2.5 at the top. AOGCC 2/15/2022 ITMO: APPLICATION OF VISION OIL & GAS Docket No. DIO-21-002; AEO-21-00 Computer Matrix, LLC 329 F Street, Ste. 222., Anch. AK 99501 Phone: 907-227-5312 Fax: 907-243-1473 Email: sahile@gci.net Page 22 1 COMMISSIONER CHMIELOWSKI: Mr. Britch. 2 MR. BRITCH: Yes. 3 COMMISSIONER CHMIELOWSKI: What are the frack 4 pressures for the confining layers, you know, the upper 5 and lower for each of these zones? 6 MR. BRITCH: I would have to turn that over to 7 Steve Hennigan to answer that. 8 MR. HENNIGAN: Off the top of my head those -- 9 the maximum pressure is the frack -- the frack pressure 10 and psi plus 500 pounds estimated for frictional loss. 11 So you could say roughly 4,300 pounds. That's on top 12 of an 8.3 pound per gallon fluid. So 8.3 times 8,077 13 times .052 plus 4,820. I hope I explained that 14 correct. If sounded out to maximum is 500 pounds over 15 the frack pressured. 16 COMMISSIONER CHMIELOWSKI: Five hundred pounds 17 over the frack pressure of the sands? 18 MR. HENNIGAN: Yes. 19 COMMISSIONER CHMIELOWSKI: And is the pressure 20 the same for each of the sands? 21 MR. HENNIGAN: The 500 -- ma'am? 22 COMMISSIONER CHMIELOWSKI: Is the frack 23 pressure the same for each of these zones, zones one 24 and two? 25 MR. HENNIGAN: All the zones will be variable AOGCC 2/15/2022 ITMO: APPLICATION OF VISION OIL & GAS Docket No. DIO-21-002; AEO-21-00 Computer Matrix, LLC 329 F Street, Ste. 222., Anch. AK 99501 Phone: 907-227-5312 Fax: 907-243-1473 Email: sahile@gci.net Page 23 1 and our estimate on frack pressure's an estimate only 2 based on a modified eaton. We can give you the numbers 3 for each of them, but they're pretty much kind of on 4 the straight line so you could interpellate between 5 those numbers and it would be very close. The -- like 6 I said the frack was calculated on a modified eaton and 7 the maximum psi there is that number plus 500 pounds 8 for frictional loss in the injection stream. And it's 9 all estimated. 10 COMMISSIONER CHMIELOWSKI: Okay. We'll review 11 and see if we have any more questions. That's good for 12 now. Thanks. 13 MR. BRITCH: The next several diagrams just 14 show some of the wellbores. The first one on the left 15 is -- just shows the configuration for zone one. And 16 here again we had a couple of the -- we had the one G 17 and one F, those are existing perfs and they'd be used 18 as it. And we'd add the other perfs, one A to E, 19 either before we start injecting into G and F or at 20 some other point after we start injection operations. 21 The existing two areas, F and G, those are ready to go. 22 23 And after we finish zone one with -- isolate it 24 from zone two and abandon zone one and we'd start with 25 perforations in zone two. And there again we have six AOGCC 2/15/2022 ITMO: APPLICATION OF VISION OIL & GAS Docket No. DIO-21-002; AEO-21-00 Computer Matrix, LLC 329 F Street, Ste. 222., Anch. AK 99501 Phone: 907-227-5312 Fax: 907-243-1473 Email: sahile@gci.net Page 24 1 different perf areas or injection zones for that. 2 And then the last slide just shows a well at 3 completion after we had -- we'd abandoned it. 4 COMMISSIONER CHMIELOWSKI: Mr. Britch, could 5 you go back to slide 17, those two schematics side by 6 side? 7 MR. BRITCH: Yes, ma'am. 8 COMMISSIONER CHMIELOWSKI: Those are the same 9 well; is that correct? 10 MR. BRITCH: Yes. These are all in the 23-25 11 well. 12 COMMISSIONER CHMIELOWSKI: Okay. I think one 13 of them might be labeled 23-35 which is fine, just for 14 your information. 15 Could you talk a little bit about this history 16 of this well, it was drilled as a gas producer and was 17 any gas found, just curious why this well is being 18 converted to a disposal well? 19 MR. BRITCH: My understanding -- actually I'd 20 better let Steve answer that. 21 Steve. 22 MR. HENNIGAN: This is the one of the wells 23 that Armstrong drilled and did a variety of testing on 24 the well and was never able to get anything to really 25 flow in the entire well. It's one of those strange AOGCC 2/15/2022 ITMO: APPLICATION OF VISION OIL & GAS Docket No. DIO-21-002; AEO-21-00 Computer Matrix, LLC 329 F Street, Ste. 222., Anch. AK 99501 Phone: 907-227-5312 Fax: 907-243-1473 Email: sahile@gci.net Page 25 1 things. And they went in and tried to do things 2 several different times and nothing worked. And that's 3 why it was never hooked up to the production facilities 4 for that reason, they didn't think that there was 5 anything in the well. And we had a couple of 6 independent G and G contractors look at it and they 7 came to the same conclusion that the well test 8 performance showed for Armstrong. 9 MR. BRITCH: I have a comment, Steve, in 10 response to her comment about the label on the second 11 and third wellbores. At the top of them it lists them 12 as NFU 23-35. Is that just a typo? 13 MR. HENNIGAN: That's a typo. 14 MR. BRITCH: So they all should be 23-25? 15 MR. HENNIGAN: Yes. 16 COMMISSIONER CHMIELOWSKI: Thank you. 17 MR. BRITCH: I didn't notice it. 18 COMMISSIONER CHMIELOWSKI: I wasn't sure if I 19 was seeing it right, it's so small. So I wanted to 20 double check. 21 MR. BRITCH: No, you were seeing right. 22 COMMISSIONER CHMIELOWSKI: Okay. 23 COMMISSIONER SEAMOUNT: It also says 23-35 on 24 slide number 4. 25 MR. BRITCH: Yeah, both those -- both those AOGCC 2/15/2022 ITMO: APPLICATION OF VISION OIL & GAS Docket No. DIO-21-002; AEO-21-00 Computer Matrix, LLC 329 F Street, Ste. 222., Anch. AK 99501 Phone: 907-227-5312 Fax: 907-243-1473 Email: sahile@gci.net Page 26 1 two. I think that's all the formal presentation. If 2 you have any questions feel free to ask them. 3 CHAIRMAN PRICE: Any questions from 4 Commissioners at this point? 5 COMMISSIONER SEAMOUNT: Not from me. Thank 6 you. 7 COMMISSIONER CHMIELOWSKI: No. 8 CHAIRMAN PRICE: At this time, Mr. Britch, 9 we're going to take a 15 minute break and talk through 10 some of these issues. 11 Before I break I just want to check to see if 12 there is anyone from the public on the phone that 13 wishes to provide testimony at this time. I'd prefer 14 to do that before we break so they can take care of 15 that now. 16 If anybody is on the phone that would like to 17 testify, present some public testimony, please state 18 your name and affiliation at this time. Take your 19 phone off mute. 20 (No comments) 21 CHAIRMAN PRICE: Hearing no comments then we 22 will take a 15 minute break. Be back at five after 23 11:00. Thanks. 24 (Off record) 25 (On record) AOGCC 2/15/2022 ITMO: APPLICATION OF VISION OIL & GAS Docket No. DIO-21-002; AEO-21-00 Computer Matrix, LLC 329 F Street, Ste. 222., Anch. AK 99501 Phone: 907-227-5312 Fax: 907-243-1473 Email: sahile@gci.net Page 27 1 CHAIRMAN PRICE: We're back on record. The 2 time is 11:12. Sorry for the delay. 3 We're going to ask Mr. Britch to go to the land 4 use section of the application. I see he's looking 5 through that. The question is about ownership within 6 the affected area. We're aware of the -- we are aware 7 of the state of Alaska, just want to verify if there's 8 any other additional property owners in the affected 9 area, subsurface property owners? 10 MR. BRITCH: I -- the ones that are listed are 11 everybody that are within a quarter mile. And actually 12 we have a lot -- a lot more people than just that. We -- 13 if you have the original map, it's at slide -- kind of 14 hard to see on the slide, but if you look at the 15 original slide five any of the lots that have a yellow 16 number within it, those are indicated in the -- in the 17 list in the application. So this fills out quite a 18 ways. 19 CHAIRMAN PRICE: If that's covered in your 20 application we can review that later. I just wanted to 21 verify that while we're talking. 22 MR. BRITCH: Yeah, but the numbers -- the 23 numbers in those squares correspond to that list. 24 CHAIRMAN PRICE: Okay. 25 MR. BRITCH: Each lot is listed and the numbers AOGCC 2/15/2022 ITMO: APPLICATION OF VISION OIL & GAS Docket No. DIO-21-002; AEO-21-00 Computer Matrix, LLC 329 F Street, Ste. 222., Anch. AK 99501 Phone: 907-227-5312 Fax: 907-243-1473 Email: sahile@gci.net Page 28 1 should correspond. 2 CHAIRMAN PRICE: Okay. 3 COMMISSIONER CHMIELOWSKI: That's great. And 4 the surface and subsurface ownership are both 5 identified? We were thinking about subsurface 6 ownership and whether it's all state of Alaska or 7 whether there are private..... 8 MR. BRITCH: We are..... 9 COMMISSIONER CHMIELOWSKI: .....mineral owners? 10 MR. BRITCH: .....we are unaware of any. 11 COMMISSIONER CHMIELOWSKI: Okay. 12 MR. BRITCH: Wait a second. 13 MR. LAMP: Yeah, this is Mark. We're not aware 14 of any. All the subsurface ownership within the North 15 Fork Unit is all state of Alaska. 16 COMMISSIONER CHMIELOWSKI: Okay. Great. Thank 17 you. 18 CHAIRMAN PRICE: Thanks for clarifying. Can 19 you speak to a potential second disposal well, your 20 plans for another well? 21 MR. BRITCH: I -- yes. We have a second 22 disposal well and that's just a contingency. We wanted 23 to see how the original one went and if it -- if it 24 worked out we should be -- we should have a lot of 25 capacity. But if it doesn't we have a second well. If AOGCC 2/15/2022 ITMO: APPLICATION OF VISION OIL & GAS Docket No. DIO-21-002; AEO-21-00 Computer Matrix, LLC 329 F Street, Ste. 222., Anch. AK 99501 Phone: 907-227-5312 Fax: 907-243-1473 Email: sahile@gci.net Page 29 1 you see the map there, the red line, the surface -- the 2 second one is -- almost goes due east from the -- from 3 the pad. The surface hole or the surface location is I 4 think about 20 or 30 feet from the 25 or the 23-25 5 well, the ones that's proposed. 6 CHAIRMAN PRICE: Is another existing well or is 7 it a new well? 8 MR. BRITCH: It would be a new well. 9 CHAIRMAN PRICE: Okay. 10 MR. DANIEL: Bob, if you'll go to slide four 11 they can see the proposed second disposal well 12 location. 13 MR. BRITCH: I -- oh. 14 COMMISSIONER CHMIELOWSKI: It's in black I 15 think, is that the one? 16 MR. BRITCH: Yeah. Yeah. 17 COMMISSIONER CHMIELOWSKI: Yeah. Okay. 18 MR. HENNIGAN: Yes. 19 MR. BRITCH: That's why we didn't take it off 20 there. It's one listed at 34-25. 21 CHAIRMAN PRICE: Yeah, Mr. Hennigan, was that 22 you speaking? 23 MR. BRITCH: That was Scott wasn't it or was 24 it..... 25 MR. HENNIGAN: Yes, that was Scott. AOGCC 2/15/2022 ITMO: APPLICATION OF VISION OIL & GAS Docket No. DIO-21-002; AEO-21-00 Computer Matrix, LLC 329 F Street, Ste. 222., Anch. AK 99501 Phone: 907-227-5312 Fax: 907-243-1473 Email: sahile@gci.net Page 30 1 MR. BRITCH: Yeah. 2 CHAIRMAN PRICE: Yeah, when you jump in just 3 state your name so our..... 4 MR. DANIEL: Oh, I'm sorry. 5 CHAIRMAN PRICE: Thanks. 6 MR. BRITCH: Yeah. But anyway that's it 7 located and it hasn't been drilled. 8 COMMISSIONER CHMIELOWSKI: If at anytime that 9 well is needed or wanted the disposal order could 10 potentially be modified administratively to include 11 another well. At this time we're just considering the 12 one proposed well, 23-25? 13 MR. BRITCH: Yeah. 14 COMMISSIONER CHMIELOWSKI: Okay. 15 MR. BRITCH: That's correct. Looks like we 16 have adequate capacity, but if not this is a 17 contingency. 18 COMMISSIONER CHMIELOWSKI: Sounds good. 19 COMMISSIONER SEAMOUNT: Okay. This is 20 Seamount. I've got a question probably Scott would -- 21 I've got a few questions, but Scott might be able to 22 answer my questions on the first part. On slides 11 23 and 12, they're structure maps, did -- was 3D seismic 24 run across this field and did that contribute to the 25 structure maps? AOGCC 2/15/2022 ITMO: APPLICATION OF VISION OIL & GAS Docket No. DIO-21-002; AEO-21-00 Computer Matrix, LLC 329 F Street, Ste. 222., Anch. AK 99501 Phone: 907-227-5312 Fax: 907-243-1473 Email: sahile@gci.net Page 31 1 MR. DANIEL: Right. The structure map was..... 2 CHAIRMAN PRICE: Can you state your name? 3 MR. DANIEL: .....using the subsurface tops of 4 the TLC-11 coal which is very close to the top of the 5 upper confinement zone. And then you used the contours 6 of the 3D seismic structure map as guidelines to 7 constructing the map in depth. 8 Is that your question? 9 COMMISSIONER SEAMOUNT: Yes, thank you. Now on 10 the application you showed those structure maps and 11 they were diagonal lines going across the structure 12 map. Is that where the 3D seismic shot points were 13 located, along those lines? 14 MR. DANIEL: Probably. Shot points and 15 receiver points, that was probably a seismic map that 16 was done and these maps are subsurface map not in 17 depth. Those would have been in time. 18 COMMISSIONER SEAMOUNT: Okay. But the diagonal 19 lines on the application, were they seismic -- where 20 the seismic lines were located? 21 MR. DANIEL: I'm assuming so. I don't have 22 that right in front of me. If you have it and you can 23 show it I can answer that question. But my -- I'm 24 thinking it probably was the shot point and receiver 25 points for the 3D seismic.j AOGCC 2/15/2022 ITMO: APPLICATION OF VISION OIL & GAS Docket No. DIO-21-002; AEO-21-00 Computer Matrix, LLC 329 F Street, Ste. 222., Anch. AK 99501 Phone: 907-227-5312 Fax: 907-243-1473 Email: sahile@gci.net Page 32 1 COMMISSIONER SEAMOUNT: Okay. Yeah, I think 2 that's what it was, but I'll get our geologist, Steve 3 Davies, to get back with you to..... 4 MR. DANIEL: Yeah, he's..... 5 COMMISSIONER SEAMOUNT: .....answer that 6 question. 7 MR. DANIEL: Let's do it this way. Did it have 8 a lot of color on the map? 9 COMMISSIONER SEAMOUNT: No, it looked just like 10 slide 11 and 12. Oh, wait. Yes, it did have a lot of 11 color and it looks like the shot points..... 12 MR. DANIEL: Yeah, that was the seismic 13 structure map and that is -- I constructed these maps 14 picking a top that we had in all the wells that was 15 very close to the top of the confinement zone of zone 16 one, the lower zone, and zone two, the upper zone. 17 COMMISSIONER SEAMOUNT: Okay. For your 18 reference it's figure A-1 in your application and Steve 19 will get back to you on that. 20 The next question..... 21 MR. DANIEL: I'm not sure I have the 22 application right in front of me here. Let's see. 23 COMMISSIONER SEAMOUNT: We'll get that figured 24 out. We'll give you some time. We'll take time 25 and..... AOGCC 2/15/2022 ITMO: APPLICATION OF VISION OIL & GAS Docket No. DIO-21-002; AEO-21-00 Computer Matrix, LLC 329 F Street, Ste. 222., Anch. AK 99501 Phone: 907-227-5312 Fax: 907-243-1473 Email: sahile@gci.net Page 33 1 MR. DANIEL: I'm thinking that those probably 2 ran northeast, southwest and northwest, southeast. 3 MR. BRITCH: Correct. 4 COMMISSIONER SEAMOUNT: Yes, that's correct. 5 And it looks like pretty tight spacing on the lines. 6 MR. DANIEL: Yeah. Yeah, that was the 3D 7 seismic grid. 8 COMMISSIONER SEAMOUNT: Okay. I think you're 9 most likely right. I think we're communicating. 10 MR. BRITCH: Yeah, it looks like it's about 11 a..... 12 MR. DANIEL: Okay. 13 MR. BRITCH: .....quarter to a fifth of a mile 14 separation or something like that. 15 COMMISSIONER SEAMOUNT: Okay. Okay. My next 16 question is -- I'm going to ask it like a geologist 17 would ask it I guess. And I think Commissioner 18 Chmielowski already asked this question and we were 19 kind of confused about the answer, but my question is 20 what pressure would it take to breakthrough the 21 confining layers and does your -- can your equipment 22 get to those pressures. 23 Is that right, Commissioner? 24 COMMISSIONER CHMIELOWSKI: Yes. 25 MR. DANIEL: I think that's a Steve Hennigan AOGCC 2/15/2022 ITMO: APPLICATION OF VISION OIL & GAS Docket No. DIO-21-002; AEO-21-00 Computer Matrix, LLC 329 F Street, Ste. 222., Anch. AK 99501 Phone: 907-227-5312 Fax: 907-243-1473 Email: sahile@gci.net Page 34 1 question. 2 MR. BRITCH: Yeah, I was just going to say you 3 asked that. 4 MR. HENNIGAN: To be frank with you I don't 5 know exactly how to answer that question. I'll just 6 answer it with experiences on a couple of wells where 7 we -- where we actually perfed and fracked wells and we 8 had radioactive tracers and we pumped like 300,000 9 pounds of frack property in each well. When we ran the 10 radioactive tracers we found out that the frack only 11 went up about 50 feet and then went out whatever. And 12 so and that's -- the frack was designed for that point 13 in the wells. So I can go back and I'll do some sort 14 of calculations, but I think it would be a pretty 15 healthy number to frack through the 200 foot of 16 confining layer. Fifty feet I can see, but 200 feet I 17 can't. 18 COMMISSIONER SEAMOUNT: What are your maximum 19 injection pressures do you anticipate? 20 MR. HENNIGAN: Forty-nine hundred pounds. 21 COMMISSIONER CHMIELOWSKI: Is that the limit of 22 your pump? 23 MR. HENNIGAN: No, ma'am. Our pump is limited 24 to 10,000. 25 COMMISSIONER CHMIELOWSKI: AOGCC will follow-up AOGCC 2/15/2022 ITMO: APPLICATION OF VISION OIL & GAS Docket No. DIO-21-002; AEO-21-00 Computer Matrix, LLC 329 F Street, Ste. 222., Anch. AK 99501 Phone: 907-227-5312 Fax: 907-243-1473 Email: sahile@gci.net Page 35 1 with Vision in a written email just to make sure 2 there's no confusion and we can keep the record open 3 for a few days. 4 MR. HENNIGAN: I really do appreciate that. 5 COMMISSIONER SEAMOUNT: Okay. I got one last 6 question probably for you, Mr. Hennigan. And that is 7 you mentioned that you want to get this approval so 8 that you can go back in and produce zone that made too 9 much water for you to handle. How much water do those 10 zones typically make before you -- before they're shut 11 in? 12 MR. HENNIGAN: I'd have to go back and look at 13 the numbers, but when Glacier was fully operating when 14 they would hit 20 barrels a day they would shut the 15 well in and it seemed like they went and plugged it off 16 and went to another zone. We have a dehydrator out 17 there that can handle about 40 barrels a day. And 18 we're kind of monitoring because of the weather 19 conditions and the works less efficiently in the 20 wintertime obviously. But I know that in testing from 21 the wells with Armstrong there was some of the zones 22 that tested with a million and a half, two million a 23 day and 50, 60, 100 barrels of water. And they just 24 didn't have the capability of handling that kind of 25 water. They tried a little bit of remediation which AOGCC 2/15/2022 ITMO: APPLICATION OF VISION OIL & GAS Docket No. DIO-21-002; AEO-21-00 Computer Matrix, LLC 329 F Street, Ste. 222., Anch. AK 99501 Phone: 907-227-5312 Fax: 907-243-1473 Email: sahile@gci.net Page 36 1 didn't work and they went on and plugged the zone and 2 went to other zones. And we feel like there's a lot of 3 left reserves out there that we can tap. 4 COMMISSIONER SEAMOUNT: How many of these zones 5 are there? 6 MR. HENNIGAN: Well, I'm going to have to turn 7 that over to Scott. We're doing -- we're doing 8 something that's -- I've been on Scott and the 9 geophysics and myself and a couple others, we're doing 10 what we call a wellbore utility chart that shows what 11 zones were completed, how much was produced, trying to 12 find out when it was plugged, what -- what was the 13 final tubing pressure and what was the gas and water, 14 et cetera. That -- that chart is not quite yet 15 complete so I can't give you a number. Scott can maybe 16 give you a better idea. 17 COMMISSIONER SEAMOUNT: Yeah. 18 MR. DANIEL: Well, there's going to be some 19 main sands that have been plugged back kind of early in 20 the lower Tyonek. A good example is what Vision calls 21 the LT-S22A sand which was productive in a number of 22 wells, but it's been plugged out of all of them and 23 indications are that it has had good pressure on it 24 when it was plugged and abandoned and should have 25 additional reserves on it. It's probably one of the AOGCC 2/15/2022 ITMO: APPLICATION OF VISION OIL & GAS Docket No. DIO-21-002; AEO-21-00 Computer Matrix, LLC 329 F Street, Ste. 222., Anch. AK 99501 Phone: 907-227-5312 Fax: 907-243-1473 Email: sahile@gci.net Page 37 1 thickest sands out there. So we would think that that 2 would have good reserves. There are others, but you 3 got to remember that we've got about 60 holes that 4 we're carrying and probably that many sands. Not all 5 the sands are productive, but a lot of them have been 6 abandoned especially in the lower Tyonek. 7 Does that answer the question? 8 COMMISSIONER SEAMOUNT: That sounds pretty 9 exciting to go back and redo some of these zones. 10 I've got one final question. On slide seven to 11 10 you're showing the injection zones for one and two 12 and looking at the resistivity log looks like they've 13 got some pretty good resistivities. I don't know, does 14 that indicate gas and if so have they been -- have any 15 of these zones been tested? I think it was mentioned 16 that three zones had been tested in well 25. Have any 17 of these zones..... 18 MR. DANIEL: In the -- go ahead. 19 COMMISSIONER SEAMOUNT: I'm just asking if any 20 of these zones within the injection zones been tested? 21 MR. DANIEL: Yes. The top two sands in the 22 lower zone did test. The total gas was 103 mcf. 23 Totally uneconomic. As Steve mentioned Armstrong 24 tested them, tried all kinds of things to get them to 25 produce in economic quantities, that was not -- didn't AOGCC 2/15/2022 ITMO: APPLICATION OF VISION OIL & GAS Docket No. DIO-21-002; AEO-21-00 Computer Matrix, LLC 329 F Street, Ste. 222., Anch. AK 99501 Phone: 907-227-5312 Fax: 907-243-1473 Email: sahile@gci.net Page 38 1 happen. So we do not anticipate making any gas out of 2 this well, but we have open perforations that we can 3 already inject into so we thought we'd take advantage 4 of them. 5 COMMISSIONER SEAMOUNT: Okay. Thank you. I'm 6 done. 7 COMMISSIONER CHMIELOWSKI: This is Jessie 8 Chmielowski. I had some questions for you about your 9 applications with the EPA. I understand you're doing 10 the aquifer exemption with both AOGCC and the EPA and 11 you've submitted a class I application to EPA and 12 you're pursuing this disposal order with the AOGCC. 13 Have you heard anything back from the EPA on your 14 application over there? 15 MR. BRITCH: We submitted the application I 16 believe November 16th or something and we within about 17 a week and a half got a response back to EPA -- from 18 EPA on additions to that permit. We recently committed 19 or completed responding to all those comments and we 20 resubmitted the application to EPA about a week ago. 21 COMMISSIONER CHMIELOWSKI: Okay. The AOGCC is 22 treating your application as a noncommercial disposal 23 well as in Vision only operated. Are there plans to 24 make this well a commercial well? 25 MR. BRITCH: That would be a Steve AOGCC 2/15/2022 ITMO: APPLICATION OF VISION OIL & GAS Docket No. DIO-21-002; AEO-21-00 Computer Matrix, LLC 329 F Street, Ste. 222., Anch. AK 99501 Phone: 907-227-5312 Fax: 907-243-1473 Email: sahile@gci.net Page 39 1 Hennigan..... 2 MR. HENNIGAN: There are no plans at this time. 3 COMMISSIONER CHMIELOWSKI: No plans. Okay. 4 CHAIRMAN PRICE: Can you clarify for our 5 recorder who just said that? 6 MR. BRITCH: Steve. 7 CHAIRMAN PRICE: Who just spoke? 8 MR. BRITCH: That was Steve. 9 COMMISSIONER CHMIELOWSKI: I just wanted to 10 follow-up on Commissioner Seamount questions about gas 11 potential and correct me if I'm wrong, but I believe 12 there's gas potential uphole. Now those have not been 13 tested in this well. Do you plan to test those zones 14 at any point, are you testing them in another well or 15 are there seven zones in the upper area and maybe seven 16 zones in the lower area that have potential? 17 MR. DANIEL: As far as I know in the upper 18 zone, zone two -- this is Scott Daniel. All of those 19 zones -- I don't think I seen anything that has 20 potential, they look like they're all wet sands. If 21 there is a little bit of gas in them it's dissolved in 22 the water and it's not an economic well. 23 COMMISSIONER CHMIELOWSKI: Okay. So this 24 entire well as you understand it has no gas potential 25 in any of the zones whether or not they're perfed? AOGCC 2/15/2022 ITMO: APPLICATION OF VISION OIL & GAS Docket No. DIO-21-002; AEO-21-00 Computer Matrix, LLC 329 F Street, Ste. 222., Anch. AK 99501 Phone: 907-227-5312 Fax: 907-243-1473 Email: sahile@gci.net Page 40 1 MR. DANIEL: The best zones at this time have 2 been perforated and it only made 103 mcf of gas. So it 3 has no economic value at this time for gas production. 4 COMMISSIONER CHMIELOWSKI: Okay. Thank you. 5 CHAIRMAN PRICE: Do you want to leave the 6 record open to the end of the week, until Friday? 7 COMMISSIONER CHMIELOWSKI: Right. So we could 8 leave that up to Vision. We talked about sending a 9 written follow-up request to you about some questions 10 about the strength of the confining layers and how much 11 time would Vision like to keep the record open, it's 12 really up to you how much time you'd want? 13 MR. HENNIGAN: We want to make sure that we 14 answer all your questions completely. What do you 15 suggest? 16 COMMISSIONER CHMIELOWSKI: Well, if you are 17 amenable to this we could plan for close of business on 18 Friday, February 25th. Would that be enough time for 19 you, it should be hopefully. We'll get the request out 20 to you today. 21 MR. HENNIGAN: That would be great. 22 COMMISSIONER CHMIELOWSKI: Okay. So close of 23 business, 5:00 p.m. on Friday, February 25th. We'll 24 keep the record open until then. 25 MR. HENNIGAN: Sounds good. AOGCC 2/15/2022 ITMO: APPLICATION OF VISION OIL & GAS Docket No. DIO-21-002; AEO-21-00 Computer Matrix, LLC 329 F Street, Ste. 222., Anch. AK 99501 Phone: 907-227-5312 Fax: 907-243-1473 Email: sahile@gci.net Page 41 1 CHAIRMAN PRICE: I think that's everything. 2 Any other questions from Commissioners? 3 (No comments) 4 CHAIRMAN PRICE: Any final comments from 5 Vision? 6 MR. BRITCH: Not at this point. 7 CHAIRMAN PRICE: Okay. Then we are adjourned. 8 The time is 11:35. 9 (Hearing adjourned - 11:35 a.m.) 10 (END OF PROCEEDINGS) 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 AOGCC 2/15/2022 ITMO: APPLICATION OF VISION OIL & GAS Docket No. DIO-21-002; AEO-21-00 Computer Matrix, LLC 329 F Street, Ste. 222., Anch. AK 99501 Phone: 907-227-5312 Fax: 907-243-1473 Email: sahile@gci.net Page 42 1 TRANSCRIBER'S CERTIFICATE 2 I, Salena A. Hile, hereby certify that the 3 foregoing pages numbered 02 through 42 are a true, 4 accurate, and complete transcript of proceedings in 5 Docket No.: DIO-21-002, AEO-21-001, transcribed under 6 my direction from a copy of an electronic sound 7 recording to the 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 3 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:bbritch@alaska.net To:Davies, Stephen F (OGC); Wallace, Chris D (OGC); scott@sevendog.net Cc:"Steve Hennigan" Subject:DIO-21-002 Porosity and Permeability Date:Tuesday, February 8, 2022 8:29:23 AM Attachments:012122 Porosity and Permeability Calculations for DIO -21-002.pdf This sender might be impersonating a domain that's associated with your organization. Learnwhythiscouldbearisk All Steve Davies had a comment on the calculation of porosity and permeability for injection and containment layers for Vision’s proposed Class 2 UIC. This analysis was conducted by Scott Daniel PG who is working with us, and he has a one-page description on the procedures he used which is attached. If you have any specific questions, feel free to contact him by phone at 713-299-4665 or at Scott’s email above. Sincerely Bob Britch PE 907-240-5830 Explanation from Scott Daniel PG who calculated the Porosities and Permeabilities 1/21/22 Porosities and permeabilities for each of the sands to be injected into were calculated from the open hole well logs in the Armstrong #23-25 NFU well that is to be converted into a disposal well. The logs used were the induction log (Rt), gamma ray (GR), density porosity (d) and neutron porosity (n). The porosities and shale volumes calculations were made using the Simoneaux variation of Archie equation used in the Ryder-Scott log analysis programming. Vsh= n - d/ Nsh – Dsh Vsh=volume of shale, n neutron porosity, d= density porosity, Nsh =neutron porosity of shale, Dsh=density porosity of shale t=eff+Vshtsh t=total porosity, eff=effective porosity, Vsh=volume shale, tsh=porosity total shale Permeabilities were calculated using a modified Timor relationship. K=0.136(4.4/Swir2) K=permeability in mD, porosity, Swir=irreducible water saturation Swir=(xSw)/eff Below is the graphic representation taken from the Analysis Summary for the Tyonek Formation in the North Fork Unit Wells done by Mike Mullen with Stimulation Petrophysics Consulting, LLC. 2 Notice of Public Hearing and Comment Period STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RE: Docket No. D1O-21-002 Vision Operating, LLC (Vision), by letter dated December 21, 2021, filed an application to the Alaska Oil and Gas Conservation Commission (AOGCC) for a Class 2 Underground Injection Control Well Permit for its North Fork Unit on the Kenai Peninsula. 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 ofhydrocarbons. 1This notice does not contain all the information filed by Vision. You may obtain more information about this filing by contacting the AOGCC's Special Assistant, Grace Salazar, at (907) 793-1221 or grace.salazar@alaska.gov. The AOGCC has scheduled a public hearing on this application for February 15, 2022, at 10:00 a.m. in the AOGCC hearing room located at 333 West 7th Avenue, Anchorage, AK 99501. In the event of an extended telework due to COVID-19 health and safety concerns, the hearing may be changed from an in-person to remote using MS Teams. The audio call-in information is 907) 202-7104 conference ID no. 705 044 624#. Anyone who wishes to participate remotely using MS Teams video conference should contact Ms. Salazar at least two business days before the scheduled public hearing to request an invitation forthe MS Teams. To comment on Vision's application, please file your comments by 4:30 p.m., February 10, 2022, atthe AOGCC address given above or via: Email: aogcc.customer.svc@alaska.gov Fax: (907) 276-7542 Online: State of Alaska Public Notices System (use the "comment" link). Individuals or groups ofpeople with disabilities who require special accommodations to comment or participate in the hearing should contact Ms. Salazar at (907) 793-1221, no later than February 11, 2022. 1 20 AAC 25.252 Jeremy Price Jeremy M. Price Chair, Commissioner From:Salazar, Grace (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] AOGCC Notice of Public Hearing and Comment Period Date:Friday, January 7, 2022 7:26:46 AM Attachments:AOGCC Notice of Public Hearing and Comment Period.pdf The Alaska Oil and Gas Conservation Commission has issued the attached Notice of Public Hearing and Comment Period regarding Docket DIO 21-002, Application for Class 2 UIC Injection Well Permit filed by Vision Operating, LLC. Grace Respectfully, M. Grace Salazar, Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Direct: (907) 793-1221 Email: grace.salazar@alaska.gov https://www.commerce.alaska.gov/web/aogcc/ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: grace.salazar@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/grace.salazar%40alaska.gov 1 188 W. Northern Lights Blvd - Suite 515 Anchorage, AK 99503 December 21, 2021 Mr. Chris Wallace, Sr. Petroleum Engineer Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Re: Application for AOGCC Class 2 UIC Vision Operating, LLC North Fork Unit Production Operations Kenai Peninsula, Alaska Dear Mr. Wallace: Enclosed is our Application for Application for Class 2 UIC Injection Well Permit for the ongoing drilling program at the North Fork Unit on the Kenai Peninsula. Attached are all support documents for the application that describes the project and all activities in accordance with 20 AAC 25.252. Should you have any questions, please call me at (337) 849-5345. You may also call Bob Britch at (907) 240-5830. Mr. Britch has full authority to discuss this project on my behalf. Sincerely, Stephen F. Hennigan President By Samantha Carlisle at 2:50 pm, Dec 21, 2021 Application for UIC Class 2 Injection Well Permit Submitted to Alaska Oil & Gas Conservation Commission Submitted by Vision Operating, LLC North Fork Development December 20, 2021 North Fork Unit i 12/20/21 TABLE OF CONTENTS Introduction ................................................................................................................................................. 2 Attachment A. Well Locations (20 AAC 25.252 (c)(1)) ...................................................................... A-1 Attachment B. Surface Owners and Operators, Notice (20 AAC 25.252 (c)(2)&(3)) .................... B-1 Attachment C. Geologic Details (20 AAC 25.252 (c)(4)) ................................................................... C-1 Attachment D. Well Logs (20 AAC 25.252 (c)(5)) .............................................................................. D-1 Attachment E. Well Construction and Mechanical Integrity (20 AAC 25.252 (c)(6)) ........................ E-1 Attachment F. Waste Sources, Types and Volumes; Compatability (20 AAC 25.252 (c)(7)) ..... F-1 Attachment G. Average and Maximum Pressures (20 AAC 25.252 (c)(8)) .................................... G-1 Attachment H. Waste Confinement and Fracture Studies (20 AAC 25.252 (c)(9)) ....................... H-1 Attachment I. Formation Water Salinity and Aquifer Exemption (20 AAC 25.252 (c)(10) 11)) .......................................................................................................................................................... I-1 Attachment J. Reporting of Mechanical Integrity of Wells Nearby (20 AAC 25.252 (c)(12)) ........ J-1 North Fork Unit ii 12/20/21 LIST OF FIGURES Figure A-1. General Location Map ................................................................................................... 2 Figure A-1. Surface And Bottom Hole Locations for North Fork Unit Wells .................. A-2 Figure A-2. Location and Topography of the North Fork Production Pad ...................... A-3 Figure B-1. North Fork Unit Boundary Map ............................................................................... A-3 Figure B-2. Land Ownership Map in the vicinity of the North Fork Unit Production Pad ................................................................................................................................... B-7 Figure B-3. Location of Water Wells in the Vicinity of the Proposed Injection Well ....... B-8 Figure D-1 Summary of Major Confining and Injection Zones ............................................ D-2 Figure-E-1 Vertical Profile for the NFU 23-25 Well ................................................................. E-5 Figure E-2 Current Schematic for the NFU 23-25 Well ......................................................... E-6 Figure-E-3 Proposed Modifications for the NFU 23-25 Well Injection Zone 1 ................ E-7 Figure-E-4 Proposed Abandonment for the NFU 23-25 Well Zone 1 ................................ E-8 Figure-E-5 Proposed Schematic for the NFU 23-25 Well Injection Zone 2 ..................... E-9 Figure-E-6. Proposed Schematic for the NFU 23-25 Well at Abandonment ................. E-10 Figure H-1. Contour Map for the Top of the Upper Confining Formation for Injection Zone 1 .................................................................................................................................. H-2 Figure H-2. Contour Map for the Top of the Upper Confining Formation for Injection Zone 2 .................................................................................................................................. H-3 Figure I-1 Calculated NaCl (or TDS in mg/l) Values for NFU 23-25 Well ............................. I-4 North Fork Unit iii 12/20/21 LIST OF TABLES Table B-1. Wells Currently Within the North Fork Unit .......................................................... B-9 Table C-1 Formation Elevations in the Disposal Well Area ............................................. C-1 Table C-2 Summary of Major Confining and Injection Zones ......................................... C-3 Table F-1 General Waste Types and Volumes Over 30 Year Time .................................... F-1 Table F-2 Representative Produced Water from Tyonek Formtion in North Fork Unit ......................................................................................................................................................... F-3 Table G-1. Representative Injection Pressures ....................................................................... G-2 North Fork Unit iv 12/20/21 BLANK PAGE North Fork Unit 1 12/20/21 Introduction Unit History The North Fork Unit (NFU) is a gas discovery located in lower Cook Inlet, Alaska. The leases are onshore east northeast of Anchor Point, Alaska (see Figure 1). Oil and gas development activities completed for development of the North Fork Unit (NFU) are as follow: Time Approved Activities 1965 Construction of NFU 41-35 Pad and drilling NFU 41-35 well by Standard Oil of California 2008 Construction of the NFU Pad for developing the NFU by Armstrong on Armstrong lands. 2008 Drilling the NFU 24-36 Well on the NFU Pad. Early 2010 Initiated permitting and construction natural gas pipelines by Anchor Point Energy, LLC from the NFU Pad to the Anchor Point area in early 2010. Pipeline construction was completed in March 2011. Summer 2010 Initiate general pad work and drilling/workover operations including Minor pad upgrades to accommodate new operations Work-over and recompletion of the original well at the NFU 41-35 Pad Drilling an additional gas well from the NFU Pad Drilling an oil well from the NFU Pad 2013 Sale of the NFU and pipelines to Cook Inlet Energy 2021 Sale of the NFU and pipelines to Vision Operating, LLC The onshore drill site and production facility on the North Fork Unit Pad will consist of: Existing NFU wells (#23-25, #14-25, #34-26, #24-26, 42-35, # 32-35 & #22-35) Up to 22 producing and pressure maintenance wells, Up to 2 disposal wells and ancillary equipment, and Production processing and handling facilities for oil, gas and water. North Fork Unit 2 12/20/21 Figure 1. General Location Map. North Fork Unit N North Fork Unit 3 12/20/21 Project Overview. The NFU is currently producing +/- 3 mmcfd. With planned activities, producing and processing capacity is projected to be up to 60 mmcfd, and 5,000 bwpd. Other equipment and/or wells maybe added on an as-needed basis. This application is for permitting for one Class 2 underground disposal (injection) well in the North Fork Field on the Kenai Peninsula about 9 miles east of Anchor Point. This application has been prepared according to requirements specified in Alaska 20 AAC 25.252(c) and are contained in the following attachments. The proposed disposal well uses the existing NFU 23-25 Well with appropriate conversions. Vision Operating, LLC (Vision) is proposing to utilize the Tyonek Formation for a range of disposal intervals in the well. These intervals are expected to receive the injection of drilling fluids, cuttings, completion fluids, cement and rinsate, and produced fluids, and other approved non-hazardous and exempt waste streams. The following pages contain 10 attachments to discuss various items require in the regulations. Attachment A provides additional information on gas wells drilled in the NFU to date, Attachment B discusses land ownership and water wells in the immediate area. Attachment C discusses the geology of the NFU 23-25 Well with the proposed injection intervals and Attachment D contains a log for the well. The conversion of this well to an injection well is designed to be executed in two phases. The first phase will perforate Zone 1 sands in the Lower Tyonek and has seven intervals identified for injection. All of these zones are porous sands capable of receiving injected fluids. In the event that additional injection capacity needs to be added, Zone 2 will be perforated for injection. Zone 2 has six intervals identified for injection and all of these zones are porous sands capable of receiving injected fluids. The upper confining layer for the Zone 2 injection interval consists of +/-220 feet of low permeability shales and coals confining the injected fluids to the perforated intervals. In the event that additional injection capacity needs to be added, Zone 2 will be perforated for injection. Zone 2 has six intervals identified for injection and all of these zones are porous sands capable of receiving injected fluids. The upper confining layer for the Zone 2 injection to the perforated intervals. Attachments E through H and J discuss various operational aspects for the injection well. Information for an aquifer exemption is discussed in Attachment I of this document. North Fork Unit 4 12/20/21 BLANK PAGE North Fork Unit A-1 12/20/21 Attachment A. Well Locations ( (1)) Well Summary A total of 8 wells have been drilled at the North Fork Unit and these are summarized on Table A-1 below; there are no other wells known to exist within this table. Well surface and bottom hole locations of these wells are indicated on Figure A-1. The NFU 23-25 Well is the designated primary well to convert to a Class 2 disposal well. All wells are currently owned/controlled by Vision. An alternate disposal well is the NFU 34-25 Well, and it is a new well to be drilled if required; this well is also indicated as a black line on Figure A-1. The surface location of the proposed disposal well (NFU 23-25) is located on a 5-acre gravel pad as shown on Figure A-2. Table A-1. Wells Currently Within the North Fork Unit. Well Name Year Drilled Depth Operators/Comments Status NFU 14-25 2010 11,002’ TVD Armstrong, Cook Inlet Energy Producing NFU 23-25 2012 9,621’ TVD Armstrong, Cook Inlet Energy Shut in NFU 24-26 2014 9,404’ TVD Cook Inlet Energy Producing NFU 32-35 2014 11,267’ TVD Armstrong, Cook Inlet Energy Producing NFU 22-35 2010 9,488’ TVD Armstrong, Cook Inlet Energy Producing NFU 34-26 2008 9,016’ TVD Armstrong, Cook Inlet Energy Producing NFU 41-35 1965 12,812’ TVD Standard Oi of Calif.., Armstrong, Cook Inlet Energy, On separate pad-) Shut in NFU 42-35 2015 9,046 TVD Cook Inlet Energy Producing Regulatory Requirements for 20 AAC 25.252 (c)(1) 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… North Fork Unit A-2 12/20/21 Figure A-1. Surface And Bottom Hole Locations for North Fork Unit Wells. North Fork Unit A-3 12/20/21 Figure A-2. Location and Topography of the North Fork Production Pad. North Fork Unit A-4 12/20/21 BLANK PAGE North Fork Unit B-1 12/20/21 Attachment B. Surface Owners and Operators (20 AAC 25.252 (c)(2)&(3)) Operators Vision Operating, LLC is the only surface or subsurface operator within ¼ mile of the proposed disposal well. Vision is the designated operator for the North Fork Unit as shown on Figure B-1. Regulatory Requirements for 20 AAC 25.252 (c)(2) & (3) c) An application for underground disposal or storage must include 2) a list of all operators and surface owners within a one-quarter mile radius of each proposed disposal or storage well; 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… North Fork Unit B-2 12/20/21 Figure B-1. North Fork Unit Boundary Map. North Fork Unit B-3 12/20/21 Surface Owners Below is a list of all surface owners within a one-quarter mile radius of the existing NFU Production Pad (see Figure B-2) or the Injection Well (see Figure B-3). The lot/owner number is shown on these figures and the number indicated correspond to the land owner in the list below. The last entry in the list below is the Kenai Peninsula Borough parcel number. 1. BOYCE ALISON RABICH 148 KOOL VIEW DR PICKENS, SC 29671 16559016 2. TANGMAN STARLET F PO BOX 743 ANCHOR POINT, AK 99556 16527021 3. DUBOIS LARRY PO BOX 221026 ANCHORAGE, AK 99522 16527022 4. WELLS MICHAEL 33185 ALEX SHADELL ST ANCHOR POINT, AK 99556 16559007 5. COLLINS FLINT GREGORY PO BOX 1303 ANCHOR POINT, AK 99556 E Production Pad16528014 6. PAULSRUD J RICKY D & LORI PO BOX 535 ANCHOR POINT, AK 99556 16528015 7. VISION RESOURCES, LLC P.O. BOX 92593 LAYFAYETTE, LA 16528016 8. VISION RESOURCES, LLC P.O. BOX 92593 LAYFAYETTE, LA 16528017 9. MCCONNELL MARK SHANE PO BOX 1125 ANCHOR POINT, AK 99556 16528012 10. SELAN KRISTA MARIE PO BOX 234 HOMER, AK 99603 16527031 11. KENAI PENINSULA BOROUGH 144 N BINKLEY ST SOLDOTNA, AK 16520049 12. OTT KENNIE 24725 ROCKY PEAK RD ROMOLAND, CA 92585 16527025 14. FOLKESTAD QUINLAN PO BOX 5004 NIKOLAEVSK, AK 99556 16528011 15. BURNETT ADAM WAYNE 7990 HAWKINSMITH RD JUNCTION CITY, KS 66441 16528005 16. FOLKESTAD QUINLAN PO BOX 5004 NIKOLAEVSK, AK 99556 16528010 North Fork Unit B-4 12/20/21 17. BURNETT CASEY 7990 HAWKINSMITH RD JUNCTION CITY, KS 66441 16528006 18. MISCHLER TERRI D PO BOX 756 ANCHOR POINT, AK 99556 16528009 19. GRIFFITH MARY L PO BOX 1266 ANCHOR POINT, AK 99556 16528007 20. LADD SHANNA E 35555 KENAI SPUR HWY SOLDOTNA, AK 99669 16528008 21. GRIFFITH MARY L PO BOX 1266 ANCHOR POINT, AK 99556 16528025 22. WILL JACK ALAN 120 HENRICH ST SOLDOTNA, AK 99669 16559013 23. STAR FRANCINE E 20 NE FERN CT TAHUYA, WA 98588 16559009 24. BOYCE DENNIS 148 KOOL VIEW DR PICKENS, SC 29671 16559008 25. KENAI PENINSULA BOROUGH 144 N BINKLEY ST SOLDOTNA, AK 16520016 26. KENAI PENINSULA BOROUGH 144 N BINKLEY ST SOLDOTNA, AK 16520154 27. KENAI PENINSULA BOROUGH 144 N BINKLEY ST SOLDOTNA, AK 16520155 28. KENAI PENINSULA BOROUGH 144 N BINKLEY ST SOLDOTNA, AK 16520156 32. DIXON GREGORY PO BOX 297 ESTER, AK 99725 16559015 33. DIXON SASHA MICHELLE PO BOX 297 ESTER, AK 99725 16559014 34. MOHN CHARLES D PO BOX 122 ANCHOR POINT, AK 99556 16520372 35 THOMAS CRAIG PO BOX 3619 HOMER, AK 99603 16520366 36 SMITH TINA 12110 WOODWAY CIRCLE ANCHORAGE, AK 99516 165200365 North Fork Unit B-5 12/20/21 37. EHMAN ROBERT L REVOCABLE TRUST 2323 ANN ST MISSOURI VALLEY, IA 51555 16520364 38. EHMAN ROBERT L REVOCABLE TRUST 2323 ANN ST MISSOURI VALLEY, IA 51555 16520363 39. GROTFEND SABRINA PO BOX 5075 NIKOLAEVSK, AK 99556 16529361 40. GROTFEND SABRINA PO BOX 5075 NIKOLAEVSK, AK 99556 16520361 41. MURRAY GREGORY D PO BOX 555 ANCHOR POINT, AK 99556 165203533 42. KUZMIN MAVRICK 38295 GREER RD APT4 HOMER, AK 99603 16520352 43. LANZ TIMOTHY N PO BOX 1432 H0MER, AK 99603 16520351 44. LANZ TIMOTHY N PO BOX 1432 H0MER, AK 99603 16520350 45. SMITH RICHARD A PO BOX 5032 NIKOLAEVSK, AK 99556 16520308 46. HEINTZELMAN ROSS W 6314 HIGHVIEW RD GREENSBORO, NC 27410 16520309 47. BAILY EDNA F 4801 SHELIKOF ST ANCHORAGE, AK 99507 16520310 48. BERNHARDT DANIEL PO BOX 1936 HOMER, AK 99603 16520354 49. EX SETH & WINKLER LINDSAY A 4516 LAWRENCE LN LAPORTE, CO 80535 16520349 50. SPERLING TIMOTHY M PO BOX 5101NIKOLAEVSK, AK 99556 16520323 51. O’CONNELL KAREN B PO BOX 706 SAN JUAN BAUTIST, CA 95045 16520355 52. JAMES COLBEN 4072 WATERMAN RD HOMER, AK 99603 16520356 53. PYATT LISA PO BOX 5106 NIKOLAEVSK, AK 99556 16520348 54. HAKKINEN JAMES E & CAROL 202410 E TERRIL RD KENNEWICLE, WA 99337 16520322 North Fork Unit B-6 12/20/21 55. SMITH BRAD 66215 NIKOLAEVSK RD NIKOLAEVSK, AK 99556 16520328 56. SMITH BRAD 66215 NIKOLAEVSK RD NIKOLAEVSK, AK 99556 16520329 57. SMITH BRAD 66215 NIKOLAEVSK RD NIKOLAEVSK, AK 99556 16520330 58. WILLIAMS LYNNE S PO BOX 874 ANCHOR POINT, AK 99556 16520332 59. SMITH BRADLEY DAVID 66215 NIKOLAEVSK RD NIKOLAEVSK, AK 99556 16520328 60. JAMES THOMAS PO BOX 5106 NIKOLAEVSK, AK 99556 16520333 61. CONKEL EDNA GABRIEL & MORIAH 4801 SHELIKOF ST ANCHORAGE, AK 99507 16520311 63. WHITESHIELD STEVE PO BOX 220 CHEVAK, AK 99563 16520313 63. LOUGHLIN CHANTAL L 33127 COYOTE RUN RD ANCHOR POINT, AK 99556 16520313 64. MCGILL JOSEPH A 136 DANA POINTE NICEVILLE, FL 32578 16520314 65. DONOVAN STEPHEN PO BOX 15312 FRITZ CREEK, AK 99603 16520359 66. DIVIAK JULIE 425 W MAIN ST MENDON, MI 49072 16520360 67. STOLL BRETT PO BOX 2526 HOMER, AK 99603 16520315 68. BENSON DANIEL PO BOX 3597 SOLDOTNA, AK 99669 16520301 69. STAPLETON DUTCHESS K PO BOX 246 SEWARD, AK 99664 16520316 70. ALASKA STATE D N R 550 W 7TH AVE STE 650 ANCHORAGE, AK 99501 1652001 71. KENAI PENINSULA BOROUGH 144 BRINKLEY ST SOLDOTNA, AK 99669 16520050 North Fork Unit B-7 12/20/21 North Fork Unit B-8 12/20/21 North Fork Unit B-9 12/20/21 Potable Water Well Data in the General Area A total of eight water wells were identified in the immediate area of the injection well by examining information available from the Alaska Department of Natural Resource Water Well Log Tracking System WELTS). These are indicated in Table B-1 and locations are shown previously on Figure B-2 (in blue); the red line indicates the existing location of the NFU 23-25 Well and the ¼ mile distance from the proposed injection well. All water wells were for residential use and all were over mile from the proposed injection well. The maximum well depth of the wells was 143 feet and while no water quality was available, it was assumed all water would be classified as being potable. Table B-1 Summary of Water Wells in the Area. Well ID Owner Location Water Depth feet) Total Depth feet) Distance to Injection feet) 15221 D. Scheer T 4S R 14W Sec 25 59.8074°N, 151.6180°W 31 2,950 27840 LAS21436 Loughlin T 4S R14 W Sec 25 59.7959°N, 151.6023°W 94 15 gpm) 143 2,180 20206 P. Roderick T 4S R14 W Sec 26 59.7998°N, 151.6494°W 28 3,500 20136 J&L Schopp T 4S R 14W Sec 27 59.8016°N, 151.6567°W 7 4,960 1579 E. Dersham T 4S R 14 W Sec 35 59.7912°N, 151.6280°W 48 64 1,720 9807 Hague T 4S R 14 W Sec 35 59.7853°N, 151.6332°W 25 50 4,000 25603 Hatch T 4S R 14 W Sec 35 59.7872°N, 151.6368°W 25 45 3,310 27316 M. Crumine T 4S R 14 W Sec 35 59.7858N, 151.6323W 64 5 gpm) 100 3,660 North Fork Unit B-10 12/20/21 BLANK PAGE North Fork Unit C-1 12/20/21 Attachment C. Geologic Details (20 AAC 25.252 (c)(4)) Geological Formations General geologic formations that consist of, in descending stratigraphic order: Sterling, Beluga, and Tyonek Formations and Hemlock Conglomerate. Individual formations are typically estuarine and nonmarine clastic sedimentary rocks. These formations in the general area are at least 25,000 ft thick. Table C-1 below describes the depth of these formations in depths of various injection operations. Table C-1 Formation Elevations in the Disposal Well Area. Zones Top feet TVD) Bottom feet TVD) Well Operations in Zone Surface Soils 0 10 Surface operations and upper well bore Sterling Formation 10 1,542 Well bore Beluga Formation 1,542 4,929 Well bore Upper Tyonek Formation 4,929 5,901 Upper confining layer, disposal zones Middle Tyonek Formation 5,901 7,098 Disposal zone, lower confining layer Lower Tyonek Formation 7,908 Not Recorded Plugged/abandoned portion of old well bore Hemlock Conglomerate Not Recorded Not Recorded Below area of operations The surface soil varies and include organic topsoil, sand, gravel, clays and some coals. The Sterling Formation is interbedded, weakly lithified sandstone, siltstone, mudstone, carbonaceous shale, lignite coal, and minor volcanic ash. The Beluga Formation is similarly nonmarine, interbedded, weakly lithified sandstone, siltstone, mudstone, carbonaceous shale, coal, and minor volcanic ash. Various groups reported that a distinctive feature of the Beluga Formation is its lack of massive sandstone beds and massive coal seams that characterize the underlying Tyonek Formation; however, lignitic to subbituminous coal seams can be as much as 12-13 ft thick, though more typically are 6 ft or less thick in the upper part of Beluga Formation. The contact between Beluga and overlying Sterling Formation may be difficult to define. Regulatory Requirements for 20 AAC 25.252 (c)(4) c) An application for underground disposal or storage must include 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; North Fork Unit C-2 12/20/21 Tyonek Formation is carbonaceous nonmarine conglomerate and subordinate sandstone, siltstone, and coal and is identified by massive sandstone beds and lignitic to subbituminous coal beds as much as 30 ft thick. The Hemlock Conglomerate consists of fluvial conglomeratic sandstone and conglomerate that contains minor interbeds of siltstone, shale, and coal and is lithologically transitional with Tyonek Formation In particular. Geological Data on the Surface and Base of the Injection Zone for Injection Well NFU 23-25 General Information The proposed disposal well is located within surficial soils and the Tyonek formations. The surficial soils extend from the ground surface to the top of the Tyonek formation located at about varying depths. These soils organic topsoil, sand, gravel, clays and some coals. Water is mostly near the surface soils or in the upper Sterling Formation layers but can reach chloride levels of 3,000 to 6,000 mg/l in the Beluga Formation. The Beluga Formation extends from 1,542 to 4,929 ft TVD. Water in this formation have chloride levels of 3,000 to 7,000 mg/l. The Tyonek Formation extends from about 4,929 to 10,785 ft TVD. Water in this formation have chloride levels of 3,000 to 20,000 mg/l. Most disposal operations will occur in the Upper Tyonek and Lower Tyonek where TDS levels are typically between 4,000 and 6,000 mg/l. There are two major formations where injection operations will occur. Initially operations in the Lower Tyonek Formation in 7 zones labeled Zone 1-A to Zone 1-G. Injection operations will be initiated first at the lowest zone (Zone 1-A) and continue upwards toward Zone 1-G as required. There are also an additional 6 injection zones (labeled Zone 2-A to Zone 2-F) located in the Upper Tyonek Formation that would be used as necessary. Table C-2 provides a summary of depths (TVD) and likely TDS of the various zones. It is planned to have separate upper and lower confining layers in for both the Upper and Lower Tyonek Formations: elevations for these ate also summarized in Table C-2. The location and elevation of both the confining layers and injection zones were chosen to avoid potential areas where potable water may be present. In addition, seismic data showed areas of major faulting within the Tyonek Formation which could be avoided by having disposal operations higher up in the Beluga Formation which has very few sands that would be suitable for disposal. North Fork Unit C-3 12/20/21 Table C-2. Summary of Major Confining and Injection Zones. Structural Feature/Zone Top feet, TVD) Bottom feet, TVD) Total Dissolved Solids (TDS) mg/l) Surficial Soils 0 10 est. <1,000 est. Sterling Formation 10 est. 1,542 <1,000 - <3,000 est. Beluga Formation 1,542 4,929 <1,000 - 10,000 est Upper Tyonek Formation 4,929 5,901 4,000 - 10,000 Zone 2 Upper Confining Layer 4,965 5,155 - Injection Zones 2-F 5,155 5,239 - Injection Zones 2-E 5,375 5,464 - Injection Zones 2-D 5,535 5,589 - Injection Zones 2-C 5,701 5,734 - Injection Zones 2-B 5,781 5,821 - Injection Zones 2-A 5,901 5,960 - Zone 2 Lower Confining Layer 5,960 6,155 - Middle Tyonek Formation 5,901 7,098 4,000 - 19,000 Lower Tyonek Formation 7,098 >10,785 3,000 - >20,000 Zone 1 Upper Confining Layer 7,378 7,666 - Injection Zones 1-G 7,666 7,673 - Injection Zones 1-F 7,786 7.810 - Injection Zones 1-E 7,866 7,901 - Injection Zones 1-D 8,006 8,036 - Injection Zones 1-C 8,241 8,306 - Injection Zones 1-B 8,351 8,401 - Injection Zones 1-A 8,726 8,766 - Zone 1 Lower Confining Layer 8,766 8,974 - Hemlock Formation Not Recorded Not Recorded Not Recorded Confining Layers Both Zone 1 and Zone 2 have an upper and lower confining layer consisting of approximately 200 feet of low permeability shales and coals to confine the injected fluids to within the perforated intervals. For Zone 1, the upper confining layer is in the Lower Tyonek Formation, as is the lower confining layer. The upper confining layer is 288 feet thick and the lower confining layer is 208 feet thick. For Zone 2 the upper and lower confining layers are in the Upper Tyonek Formation, and the lower confining layer is located in the Upper Middle Formation. The upper confining layer 190 feet thick and the lower confining layer is 195 feet thick. All confining layers are highlighted on the well log provided in Attachment D. North Fork Unit C-4 12/20/21 BLANK PAGE North Fork Unit D-1 12/20/21 Attachment D. Well Logs (20 AAC 25.252 (c)(5)) General Information Well logs of the NFU 23-25 Well are provided in Figure D-1 which start in the Beluga Formation and extend downward through the proposal area in the Lower Tyonek Formation. The following should be noted regarding these logs: 1. All depth information in Table C-2 is referenced to True Vertical Depth (TVD) while all depth Information on Figure D-1 is referenced to Measured Depth (MD). Both the table and figure reference pertinent information using the same nomenclature (such as for specific injection zones and confining layers). 2. Color and labels have been added to illustrate specific feature including: Brown-confining layers Yellow-presence of sand layers\ Red-location of specific injection zones Labels starting with TU, TM, and TL-these have been added to indicate coal seams in the Upper, Middle, or Lower Tyonek Formations which are useful tracers for interpreting the logs. Regulatory Requirements for 20 AAC 25.252 (c)(4) c) An application for underground disposal or storage must include 5) logs of the disposal or storage wells, if not already on file, or other similar information North Fork Unit D-2 12/20/21 Figure D-1 Summary of Major Confining and Injection Zones. North Fork Unit D-3 12/20/21 Figure D-1 Summary of Major Confining and Injection Zones (continued). North Fork Unit D-4 12/20/21 Figure D-1 Summary of Major Confining and Injection Zones (continued). North Fork Unit D-5 12/20/21 Figure D-1 Summary of Major Confining and Injection Zones (continued). North Fork Unit D-6 12/20/21 Figure D-1 Summary of Major Confining and Injection Zones (continued). North Fork Unit D-7 12/20/21 Figure D-1 Summary of Major Confining and Injection Zones (continued). North Fork Unit D-8 12/20/21 Figure D-1 Summary of Major Confining and Injection Zones (continued). North Fork Unit D-9 12/20/21 Figure D-1 Summary of Major Confining and Injection Zones (continued). North Fork Unit D-10 12/20/21 Figure D-1 Summary of Major Confining and Injection Zones (continued). North Fork Unit D-11 12/20/21 Figure D-1 Summary of Major Confining and Injection Zones (continued). North Fork Unit D-12 12/20/21 Figure D-1 Summary of Major Confining and Injection Zones (continued). North Fork Unit D-13 12/20/21 Figure D-1 Summary of Major Confining and Injection Zones (continued). North Fork Unit D-14 12/20/21 Figure D-1 Summary of Major Confining and Injection Zones (continued). North Fork Unit D-15 12/20/21 Figure D-1 Summary of Major Confining and Injection Zones (continued). North Fork Unit D-16 12/20/21 BLANK PAGE North Fork Unit E-1 12/20/21 Attachment E. Well Construction and Mechanical Integrity 20 AAC 25.252 (c)(6) General Well Information Vision has reviewed all available records for the existing NFU 23-25 Well and have determined the following The tops and bases of the injection zone and confining zones will be determined from open hole electric line logs and measurement-while-drilling logs. Baseline step rate test will be conducted in order to establish a baseline for future diagnostics. Planned is a step rate test, followed by an ISIP, and a shut-in period of 30 minutes or longer. This will determine the breakdown pressure of the formation. No “pass/fail” criteria will be assigned; this test will be run to gather baseline data. A complete set of geophysical well logs Mechanical integrity testing results, including pressure leak off tests Cased hole well logs (including cement bond logs) External mechanical integrity - a Tracer Log or other Channel Log, which measures fluid movement from the injection point up to the packer depth or to the top of the fluid movement if fluids move above the packer. The survey shall be conducted at the maximum injection pressure anticipated during injection activities. (Injection pressures during normal injection activities are estimated to be around 3000 psi). If the alternate NFU 34-25 is drilled, Vision will obtain necessary information to ensure the integrity of the new injection well. A formation testing program will be conducted for all injection wells to obtain data on fluid pressure, temperature, fracture pressures, and other physical, chemical, and radiological parameters of the injection zone. Regulatory Requirements for 20 AAC 25.252 (c)(6) c) An application for underground disposal or storage must include 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; or (B) the proposed casing program, if the disposal or storage wells are new… North Fork Unit E-2 12/20/21 Well Schematic Diagram and Modification Procedures Figure A-3 and A-4 in Attachment A provided a surface location diagram for the existing NFU 23- 25 Well and the contingency NFU 34-25 Well. The existing well was drilled from the NFU well pad approximately 3,600 ft towards the ENE and the proposed NFU 34-25 Well is planned to be drilled from the same pad approximately 3,600 feet to the East as shown on Figure E-1. The current schematic of the NFU 23-25 Well is shown on Figure E-2. The well was completed to a depth of 9,621’ TVD and was designed for gas production at a depth of 7,666’ to 9,005’ TVD. The well will need modifications in stages for use as a disposal well as discussed in the following. Specific plans are to perforate two separate zones in a sequential manner. Modifications are made in steps as discussed below. Step 1 Modify the existing well to first inject into Zone 1 which is the lower zone as depicted on Figure C-3 1. RU on well and run cased hole logs. 2. RU and test tubing (may need to install a tubing test plug at top of packer) and tubing casing annulus. Desired test pressures are 5,000/4,000 psi respectively. 3. Establish an injection rate with produced water. Vary rate while continuing to monitor and record pressures. NOTE: on all pumping and pressure tests, report and keep all charts. 4. General perforate and test. Including: After perforating each interval for injection perform initial baseline injection tests which may include among others. Existing perfs will be utilized first and additional formations for injection at a later date. Formation leak off Injectivity test Step rate test Shut in analysis (Initial Shut in Pressure, ISIP) following injection type tests Step 2 Install tree and connect to injection facilities. The basic procedure for injection is that the slurry, water, etc. will be accumulated into a storage tank. When an optimum volume is collected, the injection process will begin. Assuming the injectivity tests have previously been done, the following is a general overview: 1. Check lines, valves, gauges, etc. to ensure they are in proper working order. 2. Test all components. 3. Weigh slurry and calculate estimated pressures. 4. Begin pumping at a low rate and monitoring all gauges for specifics. 5. Increase rate to that determined by injectivity test, previous injection or permit. 6. At the end of injection cycle, flush all lines, tanks, equipment with water and inject. 7. Follow with 3 times volume of tubing and casing exposed to inject and shut down. 8. Inspect and perform maintenance on ALL equipment, lines, tanks, etc. Step 3 As needed, add additional perforations. Permit Mechanical Integrity Test (MIT) and other tests per regulatory requirements. North Fork Unit E-3 12/20/21 Step 4 General abandonment of lower most injection interval (Zone 1). See Figure E-4. Discussed in Attachment E. Step 5 Completion of Injection Zone 2 (Upper Interval). See Figure E-5. 1. Install and test lubricator. Run in hole with casing guns and perf lower most injection zone with 6 shots per foot. 2. Monitor for pressure. Pull out of hole with guns. Rig down. 3. PU tubing retrievable packer on tubing and run-in hole. Circulate and add corrosion inhibitor to annulus fluid. 4. Set packer at ± 6050' MD. Test annulus to 4000 psi. 5. Establish an injection rate with produced water. Vary rates continuing to monitor and record pressures. 6. Install tree and connect to injection pump and facilities. 7. Add additional perforations as necessary. Step 5 Abandonment of Injection Zone 2 (Upper Interval). The plugging and abandonment plan will be in accordance with EPA and AOGCC guidelines and regulations. The whole purpose is to secure the well properly to protect the environment, life and property in a safe and optimal manner. At the time of final abandonment, these plans will be revised to reflect the current AOGCC regulatory requirements and/or current EPA regulations, as well as utilizing available technology applicable to the condition of the well at the time. Appropriate approvals will be obtained, and the agencies will be notified in sufficient time to witness the abandonment operation. Well schematics provided in Figure E-6 represent the planned abandonment scenario. They are used to provide abandonment data for illustrative purposes; perforation intervals cannot be specified until the interval has been drilled, logged, and analyzed. Also, the type, grade, and quantity of cement used will vary, depending on wellbore geometry and physical conditions existing at the time of each abandonment operation. At closure the tubing will be removed, and the appropriate plugs placed. The abandonment schematics show the plug across the possible primary injection intervals and where the final surface plugs will be placed and how the well will be left. Should well conditions dictate a major revision, both regulatory agencies will be consulted, and agreement reached on a satisfactory plan. General abandonment of lower most injection interval (Zone 1). 1. Kill well (probably will not be necessary). Establish an injection rate with produced water. 2. Rig up on tubing and pump ±36 bbls cement and inject into formation leaving cement in casing and ±300’ in tubing. 3. Test to 4000 psi. 4. Rig up on tubing with wireline and tag top of cement (calculated to be ±8500’MD). 5. Cut tubing at ±8500’MD. 6. Pull out of hole with tubing. 7. Run in hole and set CIBP (Cast Iron Bridge Plug) at ±8500’ on Tbg stub, test to 5000psi for 30 min. North Fork Unit E-4 12/20/21 Abandonment of Injection Zone 2 (Upper Interval). 1. Kill well (probably will not be necessary). Establish an injection rate with produced water. 2. Unseat packer 3. Rig up on tubing and pump ±75 bbls cement and inject into formation leaving cement in casing. 4. Unseat packer. Pull up hole ±200’. Circulate produced water slowly around while waiting on cement. 5. Test to 3000psi. 6. Pull out of hole with tubing and packer. 7. Trip in hole with cast iron bridge plug and set at ± 5,750’, test to 3,000 psi. 8. Determine whether to complete abandonment or utilize wellbore for another drill well. 9. If total wellbore abandonment is desired abandon per AOGCC regulations Injection Well Abandonment The plugging and abandonment plan will be in accordance with AOGCC guidelines and regulations. The whole purpose is to secure the well properly to protect the environment, life and property in a safe and optimal manner. At the time of final abandonment, these plans will be revised to reflect the current AOGCC regulatory requirements, as well as utilizing available technology applicable to the condition of the well at the time. Appropriate approvals will be obtained, and the agencies will be notified in sufficient time to witness the abandonment operation. Well schematics provided in Figure E-6 represent the planned abandonment scenario. They are used to provide abandonment data for illustrative purposes; perforation intervals cannot be specified until the interval has been drilled, logged, and analyzed. Also, the type, grade, and quantity of cement used will vary, depending on wellbore geometry and physical conditions existing at the time of each abandonment operation. At closure the tubing will be removed, and the appropriate plugs placed. The abandonment schematics show the plug across the possible primary injection intervals and where the final surface plugs will be placed and how the well will be left. Should well conditions dictate a major revision, both regulatory agencies will be consulted, and agreement reached on a satisfactory plan. North Fork Unit E-5 12/20/21 Figure-E-1 Vertical Profile for the NFU 23-25 Well. North Fork Unit E-6 12/20/21 Figure-E-2 Current Schematic for the NFU 23-25 Well. North Fork Unit E-7 12/20/21 Figure-E-3 Proposed Modifications for the NFU 23-25 Well Injection Zone 1. North Fork Unit E-8 12/20/21 Figure-E-4 Proposed Abandonment for the NFU 23-25 Well injection Zone 1. North Fork Unit E-9 12/20/21 Figure-E-5 Proposed Schematic for the NFU 23-25 Well Injection Zone 2. North Fork Unit E-10 12/20/21 Figure-E-6 Proposed Schematic for the NFU 23-25 Well at Abandonment. North Fork Unit F-1 12/20/21 Attachment F. Waste Sources, Types and Compatibility Waste Categories The wastes to be injected include nonhazardous wastes and exempt wastes as listed in EPA guidance publications. Anticipated injectants should include slurried drill cuttings and mud, produced fwater, well test and completion fluids, rig and production facility wash and rinsate, office/limited camp waste, storm water, and other qualified wastes. Estimated volumes of the various wastes are provided on Table F-1. Various assumptions in determining these volumes include: Assumes 30-year life remaining for field Produced water assumed to increase with the new wells Workover fluids typically produced water at 500 bbl each Drilling muds etc.-assumes 15 new wells at 3,000 bbl each Table F-1 General Waste Types and Volumes Over 30 Year Time. Waste Types Total Discharge Duration years) Discharge Period Years) Average Rate bbl/day) Maximum Rate bbl/day) Estimated Total Volume bbl) Total] Produced water 30 1-7 8-30 200 1,300 2,000 11,424,500 75%] Well workover fluids 23 1-2 3-7 8-30 100 225 378 3,174,000 21%] Drill cuttings, mud, completion fluids 10 1-10 66 2,000 240,000 2%] Other exempt fluids 30 1-30 33 -- 360,000 2%] Total 30 1-2 3-7 8-10 10-30 399 524 1,777 1,711 15,198,500 100%] Regulatory Requirements for 20 AAC 25.252 (c)(7) c) An application for underground disposal or storage must include 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 … North Fork Unit F-2 12/20/21 An estimated 75 percent of wastes planned for disposal is produced water comes directly from the gas production which is entirely from the Tyonek Formation. These produced fluids will be sent to the injection well(s) for disposal back into areas of the Tyonek Formation where natural gas is not being produced. Table F-2 provides the chemical characteristic of both the water recovered from the natural gas processing/recovery and the produced water that is to be injected back into the Tyonek Formation. Fluid Compatibility Waters are compatible if they can be mixed without producing chemical reactions among the dissolved solids in the waters and precipitating insoluble compounds. The precipitated insoluble compounds are undesirable because they can reduce the permeability of a porous petroleum- productive rock formation, plug input wells in water-flood systems, and cause scale formation in water pumps and lines. Some of the more common ions that frequently occur in oilfield waters and that cause precipitation in incompatible waters are Ca+2, Sr+2, Ba+2, and Fe+2. Deposition of scale in both primary and secondary recovery producing wells and formations is a very costly problem in the petroleum industry. The scale not only restricts production but also causes inefficiency and production equipment failure. Scale deposits are caused by mixing incompatible waters and by environmental changes during the production of well fluids. With the experiences in the Cook Inlet area in geology and fluid types, the chemical, physical and radiological characteristics of the receiving formation; and other physical and chemical characteristics of the injected fluids are well known, the compatibility of the formation fluids and injected fluids is not expected to be a concern. As indicated in Table F-1 the largest volume of fluids (75%) being injected is the produced water from the Tyonek Formation. As these fluids are being injected back into the same formation, there is no compatibility issues these fluids. Well workover fluids are about 21 % of the volume injected are typically a brine that should be clean and chemically compatible with reservoir fluids and the formation matrix. North Fork Unit F-3 12/20/21 Table F-2. Representative Produced Water From Tyonek Formation In North Fork Unit. Parameter Produced Water 1/9/2012 SGS Lab NFU 14-25 Well 4/3/2013 SGS Lab NFU 42-35 Well 2/24/2015 Baker Hughes NFU 24-26 Well 2/2416 Baker Hughes Group Separator 10/22/16 Baker Hughes Anions Chloride (Cl) 3380 mg/l 17110.9 mg/ 15440.5 mg/l 3877.0 mg/l Sulfate (S042) 4.73 mg/l 624.0 mg/l 50.7 mg/l 1.0 mg/l Borate(H2BO3)3 ND ND ND Fluoride (F) ND ND ND ND Bromide (Br) ND ND ND Nitrite (NO2) ND ND ND Nitrate (NO3) ND ND ND ND Phosphate (PO43) 57.7 mg/l 6.5 mg/l 1.4 mg/l Silica (SiO2) 307.9 mg/l 10.5 mg/l 35.7 mg/l Cations Sodium (Na+) 3620 mg/l 4780 mg/l 2628.1 mg/l 3182.0 mg/l 4336.0 mg/l Potassium (Na+) 496.0 mg/l 76.1 mg/l 14148.0 mg/l 10529.7 mg/l 36.1 mg/l Magnesium (Mg2+) 15.5 mg/l 13.0 mg/l 41.8 mg/l 88.7 mg/l 18.7 mg/l Calcium (Ca2+) 44.9 mg/l 33.6 mg/l 102.5 mg/l 283.5 mg/l 45.8 mg/l Strontium (Sr2+) 9.5 mg/l 37.8 mg/l 12.0 mg/l Barium (Ba2+) 6.45 mg/l 2.0 mg/l 11.4 mg/l 17.2 mg/l Iron (Fe2+) ND 111.9 mg/l 52.6 mg/l 18.2 mg/l Manganese (Mn2+) 0.413 mg/l 1.6 mg/l 0.8 mg/l 0.2 mg/l Lead (Pb2+) ND ND ND ND Zinc (Zn2+) ND 1.7 mg/l 0.5 0.2 mg/l Aluminum (Al3+) ND ND ND Chromium (Cr3+) ND ND ND ND Cobalt (Co2+) ND ND ND Copper (Cu2+) ND ND ND Molybdenum (Mo2+) ND ND ND Nickel (Ni2+) ND ND ND ND Tin (Sn2+) ND ND ND Titanium (Ti2+) ND ND ND Vanadium (V2+) ND ND ND Zirconium (Zr2+) ND ND ND Other pH 7.40 7.40 7.7 mg/l 7.9 mg/l ND Hardness *13200mg/l *15400 mg/l 441 mg/l 1125 mg/l 218 mg/l Calculated TDS 37569 mg/l 30612 mg/l 8364 mg/l Density 1.0214 g/cm3 1.0170 ND Conductivity 46.6 mmhos 40.3 mmhos 14.6 mmhos Resistivity 0.450 ohm-m Alkalinity 4280 mg/l Boron ND Silicon 15.6 mg/l 6.65 Cadmium 0.0534 mg/l Total Phosphorus* 0.551 mg/l Measured North Fork Unit F-4 12/20/21 BLANK PAGE North Fork Unit G-1 12/20/21 Attachment G. Average and Maximum Injection Pressure Injection Well Procedures and Monitoring A conceptual overview of the waste flow process is provided in the Figure D-1 at the end of this Attachment. Monitoring of the disposal operations will occur in two modes depending on the ongoing operation. If there is no injection occurring, the casing and tubing pressures will be recorded at least once daily. If injection is occurring, physical and electronic (recording and visual non recording) gauges will be employed to indicate tubing and casing pressures, volumes, and injection rates. This data will be used to monitor the operation. In addition, high/low limit alarms and shut-off (down) systems will be employed. The injectants will be sampled (if necessary) according to the disposal procedures. It is requested that annular pressure (tubing x casing annulus) be allowed to stabilize or be pressure to a point to address swings in wellbore temperature and tubing thermal expansion/contraction. The increased pressure also allows a more accurate indication of communication should it occur. It is requested that 1,500 psi be the preliminary target. Large volume pressure tests (for example the tubing x casing annulus) should have the flexibility for a decrease of up to 10% during a 30 minute or longer shut-in test period to accommodate for fluid compression and temperature changes. Table G-1 provides representative injection pressures for initiation of the injection operations. These higher pressures are required in order to fracture the injection zones for use; the higher pressures are typically achieved by using higher injection rates during this initiation period. Minimum and maximum pressures and requested injection rates expected for normal operations are also indicated. Regulatory Requirements for 20 AAC 25.252 (c)(8) c) An application for underground disposal or storage must include 8) the estimated average and maximum injection pressure… North Fork Unit G-2 12/20/21 Table G-1. Representative Injection Pressures Injection Zone* Depth Bottom Hole Injection Initiation Injection Slurry Weight Estimated Surface Weight Requested Injection Rate Feet TVD (psi) Min (psi) Max (psi) Max (psi) Min (psi) (bbl/min) 2-F 5.155 4,440 8.3 16 2,720 660 2.5 2-E 5,375 2-D 5.535 2-C 5,701 2-B 5.781 2-A 5,901 1-G 7,666 6,976 8.3 16 4,170 1,100 2.75 1-F 7,786 1-E 7,866 1-D 8,006 1-C 8,241 1-B 8,351 1-A 8,726 8,077 8.3 16 4,820 1,320 3.0 See Table C-2 in Attachment C for details on Injection Zones With the above pressures, it is expected that the typical distance for fluid to be injected be on the order of ±400 feet to ±1,200' depending on the volume to be injected. Over a ±100' vertical injection area, depending on the formation stresses, the volumes would range from 50,000 bbls to 1,000,000 bbls to give the ±400'-1,200' fracture half wings. North Fork Unit H-1 12/20/21 Attachment H. Waste Confinement and Fracture Studies General Confinement of injected fluids are achieved by both confining layers and by the presence of local faults. These are discussed in the following sections. Confining Layer Structure Contours Confining layers at the wellbore were discussed previously in Attachment C and D. Figure H-1 and H-2 show the an aerial view of contours of the tops of the upper confining formations (shales) for Injection Zone 1 and 2, respectively. The individual coal seams are readily traceable on the areawide seismic records. The actual contours were obtained from aerial tracing of coal seams as shown on the log in Figure d-1 that were closest to the tops of the confining formations. Figures H-1 and H-2 also indicate the expected maximum extent of travel for materials injected into the injection zones. as discussed in Attachment G. For this operation a maximum radius of injection will be approximately 1,200 feet from the point of injection. For Injection Zone 1 (Figure H-1) the point of injection is located at the coordinates of the bottom of the NFU 23-25 Well. For Injection Zone 2 (Figure H-2) the location of injection is moved about 400 feet towards the WSW to reflect the different coordinates further up the wellbore in the vicinity of Injection Zone 2. Local Faults Figures H-1 and H-2 also shows the locations of faults in the approximate location and elevation of the top of the confining layers for the injection zones. The Zone 1 injection interval in the NFU 23-25 well is bound on the southwest by Fault Bravo and the northeast by Fault Popeye. These are normal faults. At the top of the Upper Confining Zone 1, Bravo Fault has a throw of approximately 200 feet, and the Popeye Fault has a throw of approximately 50 feet. These faults appear to be sealing as the production from the NFU 23-25 well was minimal despite being high to the main field production downthrown to Fault Bravo. As such the presence of these faults should have few effects on the proposed injection program except that injection of fluids may be limited to the SW because of the presence of the Fault Bravo which creates a barrier for spreading of injected fluids. The Zone 2 injection interval in the NFU 23-25 well is downthrown to Fault Bravo and well away from all faulting. In Injection Zone 2, the faulting will not have any impact on injection activities. Regulatory Requirements for 20 AAC 25.252 (c)(9) c) An application for underground disposal or storage must include 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 … North Fork Unit H-2 12/20/21 North Fork Unit H-3 12/20/21 North Fork Unit H-4 12/20/21 BLANK PAGE North Fork Unit I-1 12/20/21 Attachment I. Formation Water Salinity and Aquifer Exemption Freshwater Aquifer Exemption Regulations Per 20 AAC 25.440 a) Upon receipt of a letter of application, and in accordance with (b) of this section, the commission will, in its discretion, issue an order designating a freshwater aquifer or portion of it as an exempt freshwater aquifer, if the freshwater aquifer meets the following criteria: 1) it does not currently serve as a source of drinking water, and it cannot now and will not in the future serve as a source of drinking water because A) it is hydrocarbon-producing or can be demonstrated by the applicant to contain hydrocarbons that, considering their quantity and location, are expected to be commercially producible; or B) it is situated at a depth or location that makes recovery of water for drinking water purposes economically or technologically impractical; or ( C) it is so contaminated that recovery of water for drinking water purposes is economically or technologically impractical; or 2) the total dissolved solids content of the ground water is more than 3,000 and less than 10,000 mg/l, and it is not reasonably expected to supply a public water system. b) To apply for exemption of a freshwater aquifer, an operator shall submit to the commission a letter of application that includes sufficient data to justify the proposal, including data to substantiate that the criteria in (a) of this section are met. The commission will provide 15 days legal notice and the opportunity for a public hearing on the matter in accordance with 20 AAC 25.540. c) Freshwater aquifers within the state that, as of June 19, 1986, are designated as exempt aquifers by the United States Environmental Protection Agency under 40 C.F.R. 147.102 are accepted as exempt aquifers by the commission. d) A commission order designating a freshwater aquifer or a portion of it as an exempt freshwater aquifer is not effective with respect to underground disposal or storage operations subject to 29 AAC 25.252 or injection operations subject to 20 AAC 25,492 until the United States Environmental Protection Agency has been provided the opportunity to review the order under 40 C.F.R. 144.7(b)(3) and has (1) approved the order, if it was issued under (a)(1) of this section; or Regulatory Requirements for 20 AAC 25.252 (c)(10) & (11) c) An application for underground disposal or storage must include 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 … 11) a reference to any applicable freshwater exemption issued in accordance with 20 AAC 25.440... North Fork Unit I-2 12/20/21 2) has allowed the applicable time period within which to disapprove the order to expire without acting on it, if the order was issued under (a)(2) of this section. Local Water Wells The immediate area for injection operations does not currently serve as a source of drinking water also see discussions below). The Alaska Department of Natural Resources (ADNR) regulates drinking water wells in their Well Log Tracking System (WELTS). WELTS contains water well construction and lithologic information submitted to ADNR by water well contractors as required per Alaska State Statute 41.08.020(b4). It requires water well contractors to file ADNR with it of basic water and aquifer data normally obtained, including but not limited to well location, estimated elevation, well driller's logs, pumping tests and flow measurements, and water quality determinations. WELTS indicated 8 water wells occurred within ¼ to ½ mile horizontally from the proposed well bore (see Attachment B). Water well depths ranged from 7 to 143 feet; the disposal zones are at least 5,000 feet below the depth of the deepest water well. It cannot and will not in the future serve as a source of drinking water because it is situated at a depth or location which makes recovery of water for drinking water purposes economically or technologically impractical. As discussed in the following section, the total dissolved solids content of the ground water is more than 3,000 and less than 10,000 mg/l and it is not reasonably expected to supply a public water system. Vertical Total Dissolved Solids Profile The total dissolved solids (TDS) were determined/calculated using the following information obtained in house or from AOGCC: NFU 23-25 Open Hole Logs from AOGCC digital well log files NFU 23-25 Mud Logs Armstrong NF 34-6 disposal application and questions (from 2012) SWD 23-25 Log Injection Exhibit Directional surveys Open hole LWD logs Mud log suites Other reports and well history. Evaluation of these data were conducted by Petrophysicist at Waters Petroleum Advisors... Well logs were used to first determine the Clay Volume and Total Porosity. Porosity and Deep Resistivity were then combined to back calculate the water resistivity to make zones of 100% water saturated. This technique is known as the Rwa (Apparent Water Resistivity). These values were corrected to 75°F, limited to clean and porous intervals, then converted to NaCl equivalent concentrations. These Rwa values were also checked against Pickett plots of Resistivity versus Total Porosity (uncorrected to 75°F). North Fork Unit I-3 12/20/21 Clay Volume was calculated from a collection of indicators using Neutron, Density, Gamma Ray, and Resistivity logs. The well was subdivided and processed by geologic intervals for this and Total Porosity calculations. Once an acceptable Shale Volume was achieved, individual porosity logs were corrected for lay and combined into cross-plot routines to get the Final Porosity. Total Porosity and Deep Resistivity were input into the Archie Formula to solve for the Apparent Water Resistivity, Rw = 1.76 Rt porosity in decimal Rt = formation resistivity The cementation exponent of 1.76 was used form the average core electrical properties of many other Cook Inlet wells. This value was then converted to salinity concentrations and is presented in Figure I-1. This calculation becomes less reliable under conditions of low porosity or conductive shale content. Summary of Requested Freshwater Aquifer Exemption and Related Actions We believe that the proceeding text demonstrates that the Tyonek Formation should meet the requirements for a freshwater aquifer exemption under 20 AAC 25.252 (c)(10). The top elevation of the Tyonek Formation at our initial disposal well is at 4,929 feet TVD (True Vertical Depth) as indicated previously on Table 4-2. Figure H-2 shows the contour map for the approximate top of this formation in the vicinity of our initial injection well. Given the configuration to the top of the Tyonek Formation and other supporting information, it is clear that the limit of the Tyonek Formation aquifer extents over all of the North Fork Unit as shown in Figures A-1 and B-1. As such, we are requesting the freshwater exemption to include all portions of Sections 25, 26, 35 and 36 in Township 4 South, Range 14 West, Seward Meridian that lie within the boundaries of the North Fork Unit. It should be noted that Vision submitted a request for a freshwater exemption from the Environmental Protection Agency on December 7, 2021. That request uses the same depth and areal extent as identified in the preceding two North Fork Unit I-4 12/20/21 Figure I-1 Calculated NaCl (or TDS in mg/l) Values for NFU 23-25 Well. North Fork Unit J-1 12/20/21 Attachment J. Reporting of Mechanical Integrity of Nearby Wells General The NFU 14-25 Well is the closest well to the proposed disposal well and it is located just over one-quarter mile away from the disposal location on the NFU 23-25 Well (see Figure H-2 in Attachment H). The NFU 14-25 Well was previously shut in but in the past several months has been reperforated and is determined to be fit for reuse. Appropriate paperwork has been submitted to and reviewed with AOGCC. Regulatory Requirements for 20 AAC 25.252 (c)(12) c) An application for underground disposal or storage must include 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. North Fork Unit J-2 12/20/21 BLANK PAGE 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 0.00 0.50 1.00 1.50 2.00 TVDSS (ft)North Fork Unit Area -LOT / FIT Tests Visual Trend line LOT Points FIT Points Gradient ( psi/ft)NFU 23- 25 Depths Beluga (- 864' TVDSS)Tyonek (-4, 316' TVDSS)Disposal Zone 2 4,475' to -5, 275' TVDSS)Disposal Zone 1 6,987'to -8,