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Home My WebLink About225-098CAUTION: 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:McLellan, Bryan J (OGC) To:McVey, Adrienne Cc:Regg, James B (OGC) Subject:RE: PERMIT Number 225-098 Date:Thursday, February 5, 2026 5:04:00 PM Adrienne, My Response to your questions below in red. I’m copying Jim Regg to inform him of the change in BOP test pressure and MPSP as noted below in your question #2. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: McVey, Adrienne <amcvey@asrcenergy.com> Sent: Thursday, February 5, 2026 1:15 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: PERMIT Number 225-098 Bryan, I have a few questions on the approved PTD for Gubik Unit #1: 1. Inclination-only survey required is marked Yes. I’ve not seen this required for a P&A before. Can you please clarify if this is accurate? No directional survey is required since you are not drilling new hole. -bjm 2. Condition of Approval #1 states BOP test to 1600 psi. However, Procedure Step 3.2.2 was edited to change the BOP test pressure to 1000 psi. Could we edit Condition of Approval #1 to match? Yes. BOP test to 1000 psi. I should also have corrected the BHP ⚠️CAUTION: EXTERNAL SENDER This email originated from outside of the to 950 psi and MPSP = 786 psi per your 1/26/26 email. Rig supervisor should have a copy of this email available for the AOGCC inspector during the BOP test. -bjm 3. Condition of Approval #2 states: “ice plugs to be drilled in snubbing mode, with pipe held in rotary slips and stripping annular closed, flow diverted through choke.” We will be lined up to divert flow through the choke if gas is encountered, but the plan for normal operating conditions is to route returns to the mud tank via the bell nipple bleed- off line directly below the stripping annular. This aligns with the snubbing contractor’s standard practice. Would you be willing to edit Condition of Approval #2 to read as follows: “Ice plug to be drilled with pipe held in rotary slips and stripping annular closed. Be prepared to divert flow through choke if gas is encountered.” Yes, this change is approved. -bjm 4. Condition of Approval #5 states we need to tag all cement plugs with full string weight, except surface plug. Does this apply to Contingency Plug #2a? a. Contingency Plug #2a is 75’ of cement placed on top of CIBP Plug #1, per 20 AAC 25.112 (c)(1)(E). b. Could we satisfy 20 AAC 25.112 (g)(1) by stacking weight on CIBP Plug #1 before placing cement (Contingency Plug #2a) on top of it? Yes. But if contingency plugging is not required, then still need to tag TOC for plug 2 at ~686’ MD. -bjm 5. The BOP stack drawing shows 2-7/8” slip rams at the very bottom. In our case, these are not serving as BOPE; their purpose is to secure a pipe guide that will aid entry into the existing 2-7/8” tubing. After further discussion with the snubbing contractor, I would like to use a hanger flange instead. See attached brochure. Is this acceptable? Yes, please submit updated BOP stack diagram. -bjm Thanks, Adrienne McVey ASRC Energy Services, LLC 907-980-8623 From: Christianson, Grace K (OGC) <grace.christianson@alaska.gov> Sent: Friday, January 30, 2026 2:40 PM To: McVey, Adrienne <amcvey@asrcenergy.com> Subject: PERMIT Number 225-098 organization. Do not click links or open attachments unless you recognize the sender and know the content is safe. Hello, Attached is the Permit for Gubik #1. Thank you, Grace Christianson Executive Assistant, Alaska Oil & Gas Conservation Commission (907) 793-1230 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 Grace Christianson at (907-793-1230) or (grace.christianson@alaska.gov). OUR PRODUCTS COMMERCIAL • Drilling Rigs • Service Rigs • Snubbing Units • Under-Balance Applications: APPLICATIONSMTI TEAM MANUFACTURED ITS 1ST HANGER FLANGE IN 2006 HANGER FLANGES Hanger Flanges are safety devices used to hang off tubing stings during well servicing, and underbalanced drilling operations. They are manufactured with manual extended/ retracted rams that can be engaged on a range of tubular sizes while providing Full Bore when the rams are fully retracted. They are manufactured with similarities to the MT Gripper Slip Dies to vertically hold the tubular string in place using the Hanger Flange. • Manufactured from NACE material for H2s Service • Safest way of Hanging Tubing String under Live Well Conditions • Mostly installed as part of BOP Stack as a safety device • Advance Alignment design for Ram Anti-Rotation Stack as a safety device • Dual Seal Design for Long life, without Packing Adjustment • Tested to hang 1.5 Rating of no permanent deflection of Rams • Serrated, Tool Steel Double Drawn Heat Treated Rams to secure pipe • Option of Integral Bowen Union Connection, Studded Top & Thru Flange Bottom, Thru Top Hanger Flange & Thru Flange Bottom, Studded Top & Bottom, Drill Thru Hanger Flange HIGHLIGHTED FEATURES Over the years the Mitey Titan team has prototyped and tested various improvements to MT Hanger Flange designs. The new Hanger Flanges are extremely well built with a Ram Alignment System that is practical to manufacture and use. It’s field repairable and is intended to fulfill its application requirements. WHY PURCHASE MTI HANGER FLANGES? 1. BOWEN UNION TOP & THRU 2. STUDDED TOP & THRU 3. THRU TOP HANGER FLANGE & THRU FLANGE BOTTOM 4. STUBBED TOP & BOTTOM FLANG 5. DRILL THRU HANGER FLANGE 6. DOUBLE HANGER FLANGE 7. CUSTOM ADAPTER FLANGE SIZEFLANGE SIZE 4-1/ 16 4-1/ 16 7-1/ 167-1/ 16 9 11 13-5/ 8 9 11 13-5/ 8 5,000 psi 3,000 psi 3,000 psi 3,000 psi 3,000 psi R39 R45 R49 R53 R57 10,000 psi 5,000 psi 5,000 psi 5,000 psi 5,000 psi BX155 R46 R50 R54 BX160 WORKING PRESSURE & RING GROOVE NUMBER HANGER FLANGE FLANGE CONNECTTION TYPEFLANGE CONNECTTION TYPE BRO#0028 REV #0010 ASK FOR ABOUT OUR MARKETING MATERIALS UT MATERIALS CHECK OUT OUR SOCIAL MEDIA CHE OUR SOC Always keep up to date with MITEY Check out our Social and stay in touch THE FUTURE MITEYIS GET IN TOUCH Mitey Titan Industries 3051 84 Ave NW Edmonton, AB Canada Office: 780-465-0910 Email: info miteytitan.com Web: www.miteytitan.com BRO#0028 REV #0010 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 Adrienne McVey ASRC Energy Services LLC 3900 C Street Anchorage, AK, 99503 Re: Gubik Unit Field #1, Undefined Gas Pool, Gubik Unit #1 ASRC Energy Services LLC Permit to Drill Number: 225-098 Surface Location: 3125 FSL, 1900 FWL, Sec 21, T1N, R3E, Umiat Bottomhole Location: 3125 FSL, 1900 FWL, Sec 21, T1N, R3E, Umiat Dear Adrienne McVey: Enclosed is the approved application for the permit to drill the above referenced well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Jessie L. Chmielowski Commissioner DATED this 30th day of January 2026. 1a. Type of Work: 1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name: 5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. 3. Address: 6. Proposed Depth: 12. Field/Pool(s): MD: TVD: 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 15. Distance to Nearest Well Open Surface: x- y- Zone- to Same Pool: 16. Deviated wells: Kickoff depth: feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): TVD Hydraulic Fracture planned? Yes No 20. Attachments: Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: Contact Email: Contact Phone: Date: Permit to Drill API Number: Permit Approval Number: Date: Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Samples req'd: Yes No Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Surface Perforation Depth TVD (ft): GL / BF Elevation above MSL (ft): Commission Use Only See cover letter for other requirements. Perforation Depth MD (ft): Authorized Title: Authorized Signature: Production Liner Intermediate Effect. Depth MD (ft): Effect. Depth TVD (ft): Conductor/Structural LengthCasing Cement Quantity, c.f. or sacks Cement Volume MDSize Plugs (measured): (including stage data) 18. Casing Program: Top - Setting Depth - BottomSpecifications Total Depth MD (ft): Total Depth TVD (ft): STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 Authorized Name: ions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane,gas hydrates, or gas contained in shales: Samples req'd: Yes No Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No See cover letter for other requirements. Permit Approval Date: API Number:to Drill er: Commission Use Only Contact Name: Contact Email: Contact Phone: Date: hereby certify that the foregoing is true and the procedure approved herein will not be ed from without prior written approval. ized Title: ized Signature: ized Name: tachments: Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements ulic Fracture planned?Yes No Perforation Depth TVD (ft):ation Depth MD (ft): Liner Production ntermediate Surface ductor/Structural TVDMDCementVolumeSizeLengthCasing Junk (measured):Effect. Depth TVD (ft):Effect. Depth MD (ft):Plugs (measured):Total Depth TVD (ft):l Depth MD (ft): PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) (including stage data)MD TVDLength MD TVDCasing Weight Grade Couplinge Cement Quantity, c.f. or sackssing Program:Top - Setting Depth - BottomSpecifications viated wells:Kickoff depth:feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle:degrees Downhole:Surface: cation of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft):15. Distance to Nearest Well Open e: x- y-Zone-to Same Pool:GL / BF Elevation above MSL (ft): ress:6.Proposed Depth:12.Field/Pool(s): MD:TVD: ocation of Well (Governmental Section):7. Property Designation: e: Productive Horizon:8.DNR Approval Number:13. Approximate Spud Date: Depth:9. Acres in Property:14. Distance to Nearest Property: rator Name:5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. pe of Work: 1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) C By Grace Christianson at 2:51 pm, Sep 22, 2025 BP America Production Company 317 Anaconda R. Butte, MT 59701 Sec 21, T1N, R3E, Umiat Same Same 5,642,309 318,708 4 9407340 4406'4406' AKF 020932 N/A N/A 217 (original) 200.6 Gubik Unit #1 Undefined Gas March 2026 N/A N/A N/A N/A 1756 1545 4406' 4406' 1359 1900 2020 4200 0' 0'1885' 85' 16" ID 100 sx 85' 85' 786' 11-3/4" 400 sx 786' 786' 2110' 7" 315 sx 2110' 2110' 1228' - 1754'1228' - 1754' C. Michael Jackson Legacy Wells Specialist Adrienne McVey amcvey@asrcenergy.com 907-980-8623 225-098 See attached conditions of approval. 50-287-10015-90-00 CDW 11/04/2025 DSR-9/24/25BJM 1/29/26 A.Dewhurst 07JAN26 X:Y: 3,125' FSL, 1,900' FWL A.Dewhurst 30JAN26 01/30/26 01/30/26 Gubik Unit 1 (PTD 225-098) Conditions of Approval for P&A 1. BOP test to 1600 psi. 2. Ice plugs to be drilled in snubbing mode, with pipe held in rotary slips and stripping 3. Notify AOGCC if sustained pressure is observed on the 7 x 11-3/4 annulus. 4. Submit CBL to AOGCC and obtain approval before placing cement. 5. Tag all cement plugs with full string weight, except surface plug. Provide AOGCC 48 hrs notice for opportunity to witness tags. 6. after any cement top- 7. Photo-document the cement 8. melts, before September 15, 2026. 22" 16" Well Number 1 Field Gubik Unit Company API 287-10015-00 Borough North Slope Project Mgr Lease No.AKF 020932 State Alaska Address Spud Date 16-Jul-63 Well Type Exploratory Date Permit to Drill 163-013 Status P&A Phone Fresh Water Coordinates DD Latitude 69.427833° DMS Latitude 69° 25' 40.2" DD longitude -151.411667° DMS Longitude -151° 24' 42.0" As Drilled 3125' FSL and 1900' FWL of Block 5, Umiat Meridian 7" ETOC = 547' Section 21 Township 1-N Range 3-E Elevation 200.6' (assumes no washout) Casing Strings Depth (ft) Weight (ppf) Grade ID (in) Burst (psi) Collapse (psi) Capacity (bpf) 22" ID 45' 16" ID 85' 82 Permafrost XXX' 786'11-3/4" 786' 42 H-40 11.084" 1,980 1,070 0.1193 11-3/4" shoe 7" 2110' 38 N-80 5.920" 9,240 11,390 0.0340 2-7/8" Tubing 1749' 6.5 N-80 2.441" 10,570 11,160 0.00579 Hole Depth (ft) Sacks Ann Cap (bpf) Est. Yield (ft3/sk) ETOC Pressure Test Test Date Tuluvak 1182'22" ID (driven) 45' Perfs 1228 - 1242 (squeezed)20" x 16" ID 85' 100 1.18 Surface 15" x 11-3/4" 786' 400 0.0845 1.18 Surface 1344 - 1365 (21')9-5/8" x 7" 2110' 315 0.0424 1.18 547' 2350 psi 20-Aug-63 1359'5-7/8" OH 4406' 1388 - 1410 (22')Noncommercial gas well. Well test 603 MCFD at 500 psi. <1000 MCFD was not considered economic in this remote area, per 1/6/64 USGS letter. 390'1431 - 1433 (2')Operator and lessee is Colorado Oil & Gas. "Colorado-BP-Sinclair Gubik Unit" was created in 1963. Cement 1440 - 1443 (3')Mud weight before running 7" casing was 15.8 ppg (8/14/63). Mud weight at TD was 12.2 ppg (9/10/63). Weighted up to 16 ppg before perforating (9/11/63). Plug When attempting to set 7" casing on landing slips, casing slipped through and fell 14'. Set Baash-Ross casing packing bowl over top of 7" and set packing bowl. 1522 - 1540 (18')2 cement plugs set in 5-7/8" open hole on 9/10/63. Plug #1 4200 - 4380'. Plug #2 2020 - 2200' (across 7" shoe). 1550 - 1569 (19')7" bridge plug set at 1900'. Well P&A'ed 9/13/66. 60 sx cement w/ 2% calcium chloride placed from 1359' - 1749' in 2-7/8" tubing and 7" annulus. Fresh water to surface. No surface plug. 1662 - 1674 (12')Appears there are 15' of unsqueezed perfs above calculated top of cement plug. TOC 1359', top unsqueezed perf 1344'. 1749'1749'6/29/23 site visit: dug ~2' around wellhead. Unearthed companion flange appears to be 7-1/16" 3000# Type 6B. Has 3000# valve and 4" OD x 3' marker above. 2-7/8" tubing 1750 - 1754 (4')Flange details: 15" OD, 2.5" thick, with (12) 1-1/16" OD bolts and 1.75" nuts (1" flats). OD below flange is 9-3/8". Not clear if or where 2-7/8" tubing is hung off. 1885' PBTD (several fish) 1900' bridge plug 2020' Seabee ~2050' 2110' 7" shoe 2200' 5-7/8" Open Hole Chandler ~3480' Grandstand ~3955' AMOCO Production Company Current Well Diagram Well Gubik Unit #1 Location details Well History Casing Strings Casing Cement Well & Project Detail 180' Cement Plug 4200' 180' Cement Plug 4380' 4406' TD Remediation Management Environmental liability management is our business. 22" 0' Plug #4 16" Well Number 1 Field Gubik Unit Company 150' Casing Punch API 287-10015-00 Bourgh North Slope Project Mgr 160' Plug #3 (CIBP)Lease No.AKF 020932 State Alaska Address Spud Date 16-Jul-63 Well Type Exploratory Date Permit to Drill 163-013 Status P&A Phone Coordinates DD Latitude 69.427833° DMS Latitude 69° 25' 40.2" DD longitude -151.411667° DMS Longitude -151° 24' 42.0" As Drilled 3125' FSL and 1900' FWL of Block 5, Umiat Meridian 9.8 ppg Brine 7" ETOC = 547' Section 21 Township 1-N Range 3-E Elevation 200.6' (assumes no washout) Casing Strings Depth (ft) Weight (ppf) Grade ID (in) Burst (psi) Collapse (psi) Capacity (bpf) 22" ID 45' 16" ID 85' 82 Permafrost XXX' 786'11-3/4" 786' 42 H-40 11.084" 1,980 1,070 0.1193 11-3/4" shoe 7" 2110' 38 N-80 5.920" 9,240 11,390 0.0340 2-7/8" Tubing 1749' 6.5 N-80 2.441" 10,570 11,160 0.00579 1125' Plug #2 Depth Gradient BHP PPG Original PPG Tuluvak 1182'1200' Plug #1 (CIBP)2,110 0.822 1734 15.8 15.8 Mud weight before running 7" casing (8/14/63) Perfs 1228 - 1242 (squeezed)2,110 0.832 1756 16.0 16.0 Mud weight before perforating (9/11/63) 16 ppg Fluid 4,406 0.634 2795 12.2 12.2 Mud weight at 5-7/8" open hole TD (9/10/63) 1344 - 1365 (21') 1359'Top Bottom Length (ft) API Class Weight (ppg) Barrels Sacks Plug #1 1,200 CIBP Mechanical 1388 - 1410 (22')Plug #2 1,125 1200 75 G 16 3 15 390'1431 - 1433 (2')Plug #3 160 CIBP Mechanical Cement 1440 - 1443 (3')Plug #4 0 160 160 G 16 16 98 Plug 1522 - 1540 (18')CEMENT: Class: G Weight: 16 ppg Yield: 0.93 Arctic Grade 19 113 1550 - 1569 (19') Hot tap dry hole marker, top wellhead flange, and side outlet and check for pressure. Record and bleed pressure checking for build-up. 1662 - 1674 (12') 1749'1749'Move in and rig up hydraulic workover unit. 2-7/8" tubing 1750 - 1754 (4')Install and test 7-1/16" BOPE against surface ice plug to 1600 psi. Maximum Potential Surface Pressure = 1545 psi. Drill out ice in 2-7/8" tubing down to top of existing cement plug at 1359'. Run CBL to determine TOC in 2-7/8" x 7" annulus. 1885' PBTD (several fish)Cut 2-7/8" tubing above TOC. Establish circulation between 2-7/8" and 7" through cut. 1900' bridge plug Pull 2-7/8" tubing above cut. Drift/clean out 7" casing down to 2-7/8" tubing stub. 2020'Place 10 bbl of 16.0 ppg fluid above tubing stub, per 20 AAC 25.112 (f). Seabee ~2050' Plug #1 - Set 7" bridge plug above tubing stub. Per 20 AAC 25.112 (c)(1)(E), set no more than 50' above top perforation (top perf 1228'). 2110'Test Plug #1 by stacking weight on it, per 20 AAC 25.112 (g)(1). 7" shoe Plug #2 - Pump a 75' cement plug from top of CIBP to ~1125', per 20 AAC 25.112 (c)(1)(E). 2200'Displace well to 9.8 ppg brine above cement plug. Run CBL to determine TOC behind 7" casing. ETOC = 547' (assumes no washout). Punch 7" casing above TOC. Planned punch depth 150'. NOTE: AOGCC requires cement across surface casing shoe. 150' punch depth assumes 7" TOC is above surface casing shoe. Plug #3 - Set 7" bridge plug just below 7" casing punch. Planned set depth 160'. Test Plug #3 by stacking weight on it. Fill 7" x 11-3/4" annulus with Arctic Grade cement to surface via casing punch. Plug #4 - Fill 7" casing with Arctic Grade cement from CIBP to surface. 150' surface plug required per 20 AAC 25.112 (d)(1). Rig down and de-mobilize hydraulic workover unit. Cut casing 3' below tundra level and weld on marker plate. Variance request: 20 AAC 25.112 (b)(1) requires cement from 100' below to 100' above casing shoe. The well currently has cement from 90' below to 90' above. 5-7/8" Open Hole Chandler ~3480' Grandstand ~3955' Well Control 180' Cement Plug Casing Strings Well Abandonment Work Scope 75' Plug #4 volume includes 7" x 11-3/4" annulus from 150' to surface. AMOCO Production Company Proposed P&A Work Scope Well Gubik Unit #1 Well & Project Detail Location details 4200' 180' Cement Plug 4380' 4406' TD Remediation Management Environmental liability management is our business. Remediation Management Environmental liability management is our business. ent fr evel a ze hy g with ulus w ackin bridg C req g asin to de e wel #2 - st Plu Plug # Plac 9.8 P 13 1431 440 - - 15 1569 74 (1 4') ) D 955' ill 7" x Plug R t Plug #3 - Se OGCC si g a termin .8 pp 5' cem ng we lug ab id abo to 2- blish x 7" a of ex ace ic side d: 0.93 volum 16 75 ) ment 16 15.8 al PPG 1 (psi) C sing Superseded Circulate warm fluids for sufficient time to thaw ice in IA. -bjm 22" 0' Plug #4 16" Plug #4 Well Number 1 Field Gubik Unit Company 150' Casing Punch API 287-10015-00 Bourgh North Slope Project Mgr 160' Plug #3 (CIBP)Lease No.AKF 020932 State Alaska Address Spud Date 16-Jul-63 Well Type Exploratory Date Permit to Drill 163-013 Status P&A Phone Coordinates DD Latitude 69.427833° DMS Latitude 69° 25' 40.2" DD longitude -151.411667° DMS Longitude -151° 24' 42.0" As Drilled 3125' FSL and 1900' FWL of Block 5, Umiat Meridian 11.5 ppg Brine 7" ETOC = 547' Section 21 Township 1-N Range 3-E Elevation 200.6' (assumes no washout) Casing Strings Depth (ft) Weight (ppf) Grade ID (in) Burst (psi) Collapse (psi) Capacity (bpf) 22" ID 45' 686' Plug #2 16" ID 85' 82 Permafrost XXX' 786' 11-3/4" Shoe 11-3/4" 786' 42 H-40 11.084" 1,980 1,070 0.1193 7" 2110' 38 N-80 5.920" 9,240 11,390 0.0340 Plug #2 2-7/8" Tubing 1749' 6.5 N-80 2.441" 10,570 11,160 0.00579 Depth Gradient BHP PPG Original PPG Tuluvak 1182'1200' Plug #1 (CIBP)2,110 0.822 1734 15.8 15.8 Mud weight before running 7" casing (8/14/63) Perfs 1228 - 1242 (squeezed)2,110 0.832 1756 16.0 16.0 Mud weight before perforating (9/11/63) 11.5 ppg Brine 4,406 0.634 2795 12.2 12.2 Mud weight at 5-7/8" open hole TD (9/10/63) BHP (DST) = 750 psi @ 1322'1344 - 1365 (21') (0.568 psi/ft, 11.0 ppg)1359'Top Bottom Length (ft) API Class Weight (ppg) Barrels Sacks Plug #1 1,200 CIBP Mechanical 1388 - 1410 (22')Plug #2 686 1200 514 G 16 17 106 390'1431 - 1433 (2')Plug #3 160 CIBP Mechanical Cement 1440 - 1443 (3')Plug #4 0 160 160 G 16 16 98 Plug BHP (DST) = 650 psi @ 1487'1522 - 1540 (18')CEMENT: Class: G Weight: 16 ppg Yield: 0.93 Arctic Grade 34 203 (0.438 psi/ft, 8.5 ppg)1550 - 1569 (19') Hot tap dry hole marker, 7" casing, and 11-3/4" casing and check for pressure. Record and bleed pressure, checking for build-up. BHP (DST) = 950 psi @ 1640'1662 - 1674 (12') 0.580 psi/ft, 11.2 ppg 1749'Move in and rig up hydraulic workover unit. BHP (DST) = 885 psi @ 1719'2-7/8" tubing 1750 - 1754 (4')Install and test 7-1/16" BOPE against surface ice plug to 1000 psi. Maximum Potential Surface Pressure = 786 psi. (0.515 psi/ft, 10.0 ppg)Drill out ice in 2-7/8" tubing down to top of existing cement plug at 1359'. Run CBL to determine TOC in 2-7/8" x 7" annulus. 1885' PBTD (several fish)Cut 2-7/8" tubing above TOC. Establish circulation between 2-7/8" and 7" through cut. Circulate well to 11.5 ppg brine. 1900' bridge plug Pull 2-7/8" tubing above cut. Drift/clean out 7" casing down to 2-7/8" tubing stub. 2020'Plug #1 - Set 7" bridge plug above tubing stub. Per 20 AAC 25.112 (c)(1)(E), set no more than 50' above top perforation (top perf 1228'). Seabee ~2050'Test Plug #1 by stacking weight on it, per 20 AAC 25.112 (g)(1). 2110' 7" shoe Run CBL to determine TOC behind 7" casing. ETOC = 547' (assumes no washout). Plug #2 - Pump a 514' cement plug from top of CIBP to 686', per 20 AAC 25.112 (c)(3). 2200'After WOC, tag TOC with full string weight. Displace well to 9.8 ppg brine above cement plug. NOTE: if 7" CBL shows TOC below the 11-3/4" casing shoe at 786', place contingency plugs as follows: Plug #2a: 75' cement plug from top of CIBP Plug #1 to 1125', per 20 AAC 15.112 (c)(1)(E) Plug #2b: CIBP at 810' Plug #2c: Punch 7" casing at 800', then place 114' cement plug from 800' (14' below surface casing shoe) to 686', per 20 AAC 25.112(c)(3). (See Contingency Proposed P&A Schematic for Plugs #2a, b and c details) Punch 7" casing above TOC. Planned punch depth 150'. Plug #3 - Set 7" bridge plug just below 7" casing punch. Planned set depth 160'. Test Plug #3 by stacking weight on it. Fill 7" x 11-3/4" annulus with Arctic Grade cement to surface via casing punch. Plug #4 - Fill 7" casing with Arctic Grade cement from CIBP to surface. 150' surface plug required per 20 AAC 25.112 (d)(1). Rig down and de-mobilize hydraulic workover unit. Cut casing 3' below tundra level and weld on marker plate. 5-7/8"Variance request: Open Hole 20 AAC 25.112 (b)(1) requires cement from 100' below to 100' above casing shoe. The well currently has cement from 90' below to 90' above. Chandler ~3480' Grandstand ~3955' Well Control 180' Cement Plug Casing Strings Well Abandonment Work Scope Plug #4 volume includes 7" x 11-3/4" annulus from 150' to surface. AMOCO Production Company Proposed P&A Work Scope (1/29/26) Well Gubik Unit #1 Well & Project Detail Location details 4200' 180' Cement Plug 4380' 4406' TD Remediation Management Environmental liability management is our business. Remediation Management Environmental liability management is our business. 22" 0' Plug #4 16" Plug #4 150' Casing Punch 160' Plug #3 (CIBP) 11.5 ppg Brine Plug #2c 686' Plug #2c Permafrost XXX' 786' 11-3/4" shoe 800' Casing Punch 11.5 ppg Brine 810' Plug #2b (CIBP) 1125' Plug #2a Tuluvak 1182'1200' Plug #1 (CIBP) Perfs 1228 - 1242 (squeezed) 11.5 ppg Brine BHP (DST) = 750 psi @ 1322'1344 - 1365 (21') (0.568 psi/ft, 11.0 ppg)1359' 1388 - 1410 (22') 390'1431 - 1433 (2') Cement 1440 - 1443 (3') Plug BHP (DST) = 650 psi @ 1487'1522 - 1540 (18') (0.438 psi/ft, 8.5 ppg)1550 - 1569 (19') BHP (DST) = 950 psi @ 1640'1662 - 1674 (12') 0.580 psi/ft, 11.2 ppg 1749' BHP (DST) = 885 psi @ 1719'2-7/8" tubing 1750 - 1754 (4') (0.515 psi/ft, 10.0 ppg) 1885' PBTD (several fish) 1900' bridge plug 2020' Seabee ~2050' 2110' 7" shoe 2200' 5-7/8" Open Hole Chandler ~3480' Grandstand ~3955' Contingency Proposed P&A Schematic (1/29/26) Plug #2a 180' Cement Plug 4200' 180' Cement Plug 4380' 4406' TD 1 General Plug & Abandonment Design Gubik Unit #1 was drilled in 1963 under Permit to Drill number 163-013. Well tests indicated no economic production. The well was partially plugged in 1966, but no surface plug was installed, and the wellhead was not cut off. 2-7/8 kill string and 7 casing are full of fresh water (ice) from 1359 (top of existing cement plug) to surface. Thru Tubing Solutions, Cudd Pressure Control and ASRC representatives visited the site in June 2023 to confirm wellhead specifications and height. The wellhead top flange is 7-1/16, 3000 psi working pressure, and is located approximately 2 below ground level. Bottomhole pressure estimate: 16.0 ppg mud weight before perforating 7 casing * 0.052 * 2110 ft TVD = 1756 psi Maximum potential surface pressure: 1756 psi (0.1 psi/ft * 2110 ft TVD) = 1545 psi 2 Objective Complete permanent plug and abandonment of the subject well, excavate and cut casings three feet below original tundra grade and weld permanent marker cap. 3 Procedure 3.1 Site Preparation 3.1.1 Build snow trail from Franklin Bluffs. Approximately 70 miles from Franklin Bluffs to Gubik Unit #1. 3.1.2 Begin site remediation. 3.1.3 Notify AOGCC Inspectors 48 hours before commencing hot tap. 3.1.4 Hot tap dry hole marker, top flange, and side outlet and verify zero pressure. Record and bleed any pressure. Monitor for 1 hour for potential pressure build up. 3.1.5 Begin excavation and leveling required for upcoming wellwork. 786 psi per Adrienne McVey email 1/21/26 -bjm Hot tap 7" casing and 11-3/4" casing also per A. McVey email. -bjm 950 psi @ 1640' TVD per Adrienne McVey email 1/21/26 -bjm 3.2 Hydraulic Workover Unit Scope 3.2.1 MIRU hydraulic workover unit. 3.2.2 Install and test 7-1/16 BOPE against surface ice plug to 1600 psi. 3.2.3 Drill out ice in 2-7/8 tubing down to top of existing cement plug at 1359. 3.2.4 Run CBL to determine the top of cement in 2-7/8 x 7 annulus. 3.2.5 Cut 2-7/8 tubing above TOC. Establish circulation between 2-7/8 and 7 through cut. 3.2.6 Pull 2-7/8 tubing above cut. 3.2.7 Drift/clean out 7 casing down to 2-7/8 tubing stub. 3.2.8 Place 10 bbl of 16.0 ppg fluid above tubing stub, per 20 AAC 25.112 (f). 3.2.9 Plug #1 (CIBP) Set 7 bridge plug above tubing stub, at approximately 1200. Set plug no more than 50 above top perf at 1228, per 20 AAC 25.112 (c)(1)(E). Test plug by stacking weight on it, per 20 AAC 25.112 (g)(1). 3.2.10 Plug #2 (75 cement above CIBP) Pump a 75 cement plug from top of CIBP to ~1125. 75 cement on top of CIBP required per 20 AAC 25.112 (c)(1)(E). Displace well to 9.8 ppg brine above cement plug. 3.2.11 Run CBL to determine the top of cement behind 7 casing. ETOC = 547 (assumes no washout). 3.2.12 Punch 7 casing above TOC. Planned punch depth 150. AOGCC requires cement across 11-3/4 surface casing shoe. If TOC is below surface casing shoe (786), punch below surface casing shoe. 3.2.13 Plug #3 (CIBP) Set 7 bridge plug just below 7 casing punch. Planned set depth 160. Test plug by stacking weight on it. 3.2.14 Fill 7 x 11-3/4 annulus with Arctic Grade cement to surface via casing punch. 3.2.15 Plug #4 (surface cement plug) Fill 7 casing with Arctic Grade cement from CIBP to surface. 150 surface plug required per 20 AAC 25.112 (d)(1). 3.2.16 RDMO hydraulic workover unit. See email from A. McVey 1/29/26 for updated 3.2.10 cement plug and contingency. Tag TOC with full string weight for both primary and contingency cement plugs. -bjm CBL to be run before setting plug #2. per A. McVey 1/29/26 email. -bjm Circulate well to 11.5 ppg brine per A. McVey email 1/21/26. -bjm 1000 psi per A. McVey email 1/21/26. -bjm Drill ice in snubbing mode, with pressure containment and workstring in slips. see email from A. McVey 12/17/25 -bjm 3.3 Post Cementing Excavation and Capping 3.3.1 Notify AOGCC Inspectors 48 hours in advance for opportunity to witness casing cut-off. 3.3.2 Excavate and cut off casings and wellhead three feet below original tundra grade. Top off all annuli and casing with cement as needed. 3.3.3 Photo document the well: Immediately after cutting off the wellhead. Before and after top job(s). 3.3.4 Bead weld marker cap on outermost casing string (23.25 OD structural casing indicated in well file; verify) to read as follows: BP America Production Company Gubik Unit #1 163-013 286-10015-00 3.3.5 Take pictures of welded on marker plate with well identification information. 4 Variance Request 20 AAC 25.112 (b)(1) requires cement from 100' below to 100' above casing shoe. The well currently has cement from 90' below to 90' above. Above that cement plug is a bridge plug, and another cement plug 390 in length. 5 BOP Sketch See next page. Refers to 7" casing shoe. -bjm Variance approved. -bjm 7-1/16 5M BOPE Supreseded PePPrf Intetetervrvrvalalals:ss 131313444444 ---131313656565,,,131313888888-1-1-14141410,0,0,1414143133-143333,3,3,14404040-11144444333 DST #7#7#7:PePePerfrfrfs,s,s,737373 MCMCMCFDFDFD @@@ 12555 psi (t(oool plplplugged)d)d) DSDT #8#8#8:::PePePerfrfrfs,s,s,121212111 MCMCMCFDFDFD @@ 585858 psi NOTET:rererecococordrdrdsss innndididicacacatetete 151515'of opopen peperfrfs (11134344-1333595959)abababovooeee exxxisiitinggg cememement plug.However,after placing cement plplugu,p g,plug,SISISICPCPCPSIICPP ===SISISITPTPTPSSITP ===0000 ppspi.i.i.pppsii.FrresehFrresh waateterwater abaovooveabovoe llplugugg;;;p gg;plugg;tetetempssspptempps bbabovovoveabovoe frfrfreezizizinggfreezing ttatat thththethe titimetime llplugp gplug waswas llplacededed.pplacedd. PePePerfrfrf InInIntetetervrvalalal 121212282828-1-1-1242222 DSSSTT #9#9#9:::PePePerfrfrfsss wet.t PePPrfrroroomeeed sqsqsueeezzzee.e DSDSDST #1:OOOpenee Hooolle,161616606060-1-116969692,2,2,amamaxxx flflflowowow 1000 MCMFDFDFD @ 1222000 psppi DST #2:OOpOpen Hooolelele,161616555555-1-1-1696969222,maaaxxx flflflowowow 4044000 MCMCMCFDFDFD @@@ 202020000 pspspsiii DSDDT #3:OpOpOpenenen HoHoHolelele,,,161616393939-1-1-16969692,2,2,mamamaxxx flflflowowow 70707000 MCMCMCFDDD @@@ 181818555 pspspsiii DSSTT #1#10:0:PePerfrfs,s,16166262-167674,4,mamaxx fllowow 15156 MCCFDFD @@ 2828 pspsii Perf Intetrvals:1552222-15440,0 1555050-156599 DSDSTT #1#11:Perfs,s,2121 MCMCFDFD @@ 9595 pspsi DSSTT #1#12:2:PePerfrfs,s,17175050--1754,65 MCFDD @@ 9595 pspsii 7" shoe at 2110' 1 McLellan, Bryan J (OGC) From:McVey, Adrienne <amcvey@asrcenergy.com> Sent:Thursday, January 29, 2026 3:27 PM To:McLellan, Bryan J (OGC) Cc:Jackson, C. Michael; Collin Simmons; Spence, Clinton Subject:RE: Gubik Unit 1 (PTD 225-098) Attachments:Proposed P&A Schematic Gubik Unit #1 Re-Entry (PTD 225-098) - Updated 26-01-29.pdf; Contingency Proposed P&A Schematic Gubik Unit #1 Re-Entry (PTD 225-098).pdf Bryan, Thanks for your time this morning. I have outlined the proposed procedure changes below. For clarity and completeness, Ive included the original procedure changes from my 1/21 e-mail (red text), the changes to 3.2.10 outlined in your 1/26 e-mail below (green text), and the contingency cementing plan (discussed on 1/26 and 1/29) if the 7 CBL shows TOC below the 11-3/4 surface casing shoe (blue text). I have also attached: Updated proposed P&A schematic Contingency proposed P&A schematic: contingency cementing plan if the 7 CBL shows TOC below the 11-3/4 surface casing shoe at 786 Please let me know if you have additional questions or need more information to facilitate review and approval. Ive copied C. Michael Jackson, bp Legacy Wells Specialist, and Collin Simmons, Through Tubing Solutions Project Manager/Engineer (prime contractor to bp), to keep them apprised. Thanks, Adrienne McVey ASRC Energy Services, LLC 907-980-8623 Section 1: General Plug & Abandonment Design Bottomhole pressure estimate: 950 psi at 1640 TVD. This estimate is based on the shut-in bottomhole pressure measured during a 9/19/63 drill stem test (DST) of the 1662 1674 perforated interval, which represents the highest-pressure interval in the well. The packer and pressure gauge depth for this DST were not recorded. For other DSTs conducted in this well, the packer and gauge were set approximately 18 35 above the top perforation. For purposes of this bottomhole pressure estimate, a gauge depth of 1640 TVD (approximately 22 above the top perforation) was assumed. Maximum potential surface pressure: 950 psi (0.1 psi/ft * 1640 TVD) = 786 psi. 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. 2 Section 3.1: Site Preparation 3.1.4 Hot tap dry hole marker, top ange, and side outlet 7 casing, and 11-3/4 casing and verify zero pressure. Record and bleed any pressure. Monitor for 1 hour for potential pressure build-up. Section 3.2: Hydraulic Workover Unit Scope 3.2.2 Install and test 7-1/16 BOPE against surface ice plug to 1600 psi 1000 psi. 3.2.5 Cut 2-7/8 tubing above TOC. Establish circulation between 2-7/8 and 7 through cut. Circulate well to 11.5 ppg brine. 3.2.8 (delete) 3.2.10 Plug #2 (75 cement above CIBP) Pump a 75514 cement plug from top of CIBP to ~1125 686 (100 above surface casing shoe), per 20 AAC 25.112 (c)(3). After WOC, tag TOC with full string weight. 75 cement on top of CIBP required per 20 AAC 15.112 (c)(1)(E). Displace well to 9.8 ppg brine above cement plug. NOTE: if 7 CBL shows TOC below the 11-3/4 surface casing shoe at 786, place contingency plugs as follows: o Plug #2a: 75 cement plug from top of CIBP Plug #1 to 1125, per 20 AAC 15.112 (c)(1)(E) o Plug #2b: CIBP at 810 o Plug #2c: Punch 7 casing at 800, then place 114 cement plug from 800 (14 below surface casing shoe) to 686 (100 above surface casing shoe), per 20 AAC 25.112 (c)(3). o (See Contingency Proposed P&A Schematic for Plugs #2a, b and c details) 3.2.11 Run CBL to determine the top of cement behind 7 casing. ETOC = 547 (assumes no washout). From: McVey, Adrienne Sent: Monday, January 26, 2026 5:22 PM To: 'McLellan, Bryan J (OGC)' <bryan.mclellan@alaska.gov> Subject: RE: Gubik Unit 1 (PTD 225-098) Bryan, Got it. Sounds good. Should I submit a revised procedure and/or proposed wellbore diagram? Thanks, Adrienne McVey ASRC Energy Services, LLC 907-980-8623 3. 00 abo 3 From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Monday, January 26, 2026 5:11 PM To: McVey, Adrienne <amcvey@asrcenergy.com> Subject: Gubik Unit 1 (PTD 225-098) Adrienne, Id like to discuss plug #2 in step 3.2.10. The current plan is for a 2.6 bbls cement plug, which is very di icult to place without contaminating most of it. Would be better to increase cement volume to assure good cement where you need it. Need to place cement across surface casing shoe per 20 AAC 25.112(c)(3) unless we know there is no fresh water aquifer present. If you run the CBL log before placing cement and determine that there is already cement in the annulus above the casing shoe, you could then lay one plug from top of CIBP at 1200 to 686 MD (100 above surface casing shoe. Would need to tag cement with full string weight after. Then proceed to setting surface plug. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 CAUTION: EXTERNAL SENDER This email originated from outside of the organization. Do not click links or open attachments unless you recognize the sender and know the content is safe. 1 McLellan, Bryan J (OGC) From:McVey, Adrienne <amcvey@asrcenergy.com> Sent:Wednesday, December 17, 2025 8:41 AM To:McLellan, Bryan J (OGC) Subject:RE: Gubik Unit 1 P&A question Attachments:BOP Stack Drawing - Gubik Unit 1 (PTD 225-098) - Oct 23, 2025.png Bryan, I am working with the snubbing contractor to generate a piping diagram and will send as soon as its available. Regarding your other questions: Primary pressure control: Annular preventer (stripping annular BOP in attached diagram) Dual BPVs in workstring Secondary pressure control: Second annular preventer (annular BOP in attached diagram) 1-1/4 pipe ram (single gate ram BOP 1-1/4 in attached diagram) TIW valve Managing pipe light: Snubbing slips will always be engaged on the 1-1/4 workstring, preventing it from being ejected under pipe-light conditions. Thanks, Adrienne From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Monday, December 15, 2025 3:59 PM To: McVey, Adrienne <amcvey@asrcenergy.com> Subject: RE: Gubik Unit 1 P&A question Adrienne, Can you please submit a piping diagram and an explanation of how you will maintain pressure containment and avoid pipe-light scenario when drilling out the ice plug in step 3.2.3? Thank you Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 CAUTION: EXTERNAL SENDER This email originated from outside of the organization. Do not click links or open attachments unless you recognize the sender and know the content is safe. 2 From: McVey, Adrienne <amcvey@asrcenergy.com> Sent: Monday, December 15, 2025 8:50 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: Gubik Unit 1 P&A question Bryan, Yes, we are. Thanks, Adrienne McVey ASRC Energy Services, LLC 907-980-8623 From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Friday, December 12, 2025 5:20 PM To: McVey, Adrienne <amcvey@asrcenergy.com> Subject: Gubik Unit 1 P&A question Adrienne, Are you planning to perform the ice drilling in snub mode in case there is gas encountered? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 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. CAUTION: EXTERNAL SENDER This email originated from outside of the organization. Do not click links or open attachments unless you recognize the sender and know the content is safe. 1 McLellan, Bryan J (OGC) From:McVey, Adrienne <amcvey@asrcenergy.com> Sent:Friday, September 26, 2025 12:33 PM To:McLellan, Bryan J (OGC) Subject:RE: Gubik Unit 1 (PTD 225-098) PTD for Reentry and P&A questions Bryan, Ill nd out whether the CBL can distinguish between cement and ice. Good point on the extended time it will likely take to thaw the annuli. For the 2-7/8 x 7 annulus: I expect the ice cleanout/melting run with heated uid inside the 2-7/8 will take quite a bit of time, which will give ample opportunity for heat transfer to thaw and warm the annulus before we run the rst CBL. For the 7 x 11-3/4 annulus: well be doing quite a lot of circulating with heated uid inside the 7 after the 2-7/8 is pulled and before we run the CBL, again giving ample opportunity for heat transfer to thaw and warm the annulus. Although we are planning for 12 versus 24-hour full-scale operations, we will have a small night crew so we can continue circulating heated uid overnight to keep the wellbore warm. Thanks, Adrienne McVey ASRC Energy Services, LLC 907-980-8623 From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Wednesday, September 24, 2025 1:58 PM To: McVey, Adrienne <amcvey@asrcenergy.com> Subject: Gubik Unit 1 (PTD 225-098) PTD for Reentry and P&A questions Adrienne, Just reading over the permit application for P&A of this well. Is the CBL able to distinguish between cement and ice in the annulus? I think you will need to circulate hot water for a considerable amount of time to thaw the ice in both the 2-7/8 x 7 annulus and the 7 x 11-3/4 annulus before running CBL and before you will be able to circulate through perf holes. In my experience, it takes a lot longer than you think to establish communication when trying to thaw a frozen annulus. I would expect you to circulate for at least 3-6 hrs before you can establish circulation up the annuli. 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. CAUTION: EXTERNAL SENDER This email originated from outside of the organization. Do not click links or open attachments unless you recognize the sender and know the content is safe. 2 Thanks Bryan Revised 7/2022 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: __________________________ POOL: ____________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit Number _____________, API Number 50-______________________. Production from or injection into this wellbore must be reported under the original API Number stated above. Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce or inject is contingent upon issuance of a conservation order approving a spacing exception. The Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30-foot sample intervals from below the permafrost or from where samples are first caught and 10-foot sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for this well until after the Operator has designed and implemented a water-well testing program to provide baseline data on water quality and quantity. The Operator must contact the AOGCC to obtain advance approval of such a water-well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by the Operator in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. UNDEFINED GAS 225-098 Gubik Unit-1 GUBIK WELL PERMIT CHECKLISTCompanyBP America Production CompanyWell Name:GUBIK UNIT 1 RE-ENTRYInitial Class/TypeDEV / PENDGeoArea890Unit50770On/Off ShoreOnProgram DEVWell bore segAnnular DisposalPTD#:2250980Field & Pool:GUBIK, UNDEFINED GAS - 284500NA1 Permit fee attachedNA Orphan well: original lease exipred2 Lease number appropriateYes3 Unique well name and numberNA GUBIK, UNDEFINED GAS - 2845004 Well located in a defined poolNA5 Well located proper distance from drilling unit boundaryNA6 Well located proper distance from other wellsNA7 Sufficient acreage available in drilling unitNA8 If deviated, is wellbore plat includedNA9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForNA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)NA18 Conductor string providedNA19 Surface casing protects all known USDWsNA20 CMT vol adequate to circulate on conductor & surf csgNA21 CMT vol adequate to tie-in long string to surf csgNo See variance discussion in Conditions of Approval22 CMT will cover all known productive horizonsNA23 Casing designs adequate for C, T, B & permafrostYes24 Adequate tankage or reserve pitNA25 If a re-drill, has a 10-403 for abandonment been approvedNA26 Adequate wellbore separation proposedNA27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes29 BOPEs, do they meet regulationYes MPSP = 1545 psi. BOP test to 1600 psi (BOP rated to 3000 psi)30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownNo33 Is presence of H2S gas probableNA34 Mechanical condition of wells within AOR verified (For service well only)Yes H2S not anticipated35 Permit can be issued w/o hydrogen sulfide measuresYes Not drilling new hole; existing cement plugs isolate from open hole section.36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprADDDate30-Jan-26ApprBJMDate29-Jan-26ApprADDDate30-Jan-26AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateJLC 1/30/2026