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Home My WebLink About224-075CAUTION: 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:Mike Stefanov Cc:Bob Laule; Dan Robertson; Hunter Van Wyhe; Rixse, Melvin G (OGC) Subject:RE: KLU A-1A PTD #224-075 Date:Thursday, October 24, 2024 9:24:00 AM Mike, Furie has approval to alter the displacement fluid as long as the combination of fluids maintain an overbalance to the 10.1 ppg estimated reservoir pressure at 7414’ TVD. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Mike Stefanov <m.stefanov@furiealaska.com> Sent: Wednesday, October 23, 2024 5:14 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Bob Laule <b.laule@furiealaska.com>; Dan Robertson <d.robertson@furiealaska.com>; Mike Stefanov <m.stefanov@furiealaska.com>; Hunter Van Wyhe <h.vanwyhe@furiealaska.com> Subject: KLU A-1A PTD #224-075 Bryan, Furie is requesting to revise the KLU A1-A liner cement displacement sequence to replace drilling mud in the liner with 9.9 ppg NaCl brine. The originally planned cement displacement sequence was: 10 bbls freshwater 30 bbls 10.6 ppg drilling mud 30 bbls 11.0 ppg spacer 24 bbls 10.6 ppg drilling mud The proposed cement displacement sequence is: 10 bbls freshwater 30 bbls 9.9 ppg NaCl brine (this is the change relative to the original sequence) 30 bbls 11.0 ppg spacer 24 bbls 10.6 ppg drilling mud It was originally planned to perforate A-1a immediately after the well was completed. It is now tentatively planned to delay perforating approximately a month if well A-4a sidetrack is performed. If drilling mud is left static in the A-1a liner for a month, there is a concern the barite weighting agent may sag or separate from the liquid. This barite accumulation in the liner may prevent running electric line conveyed guns to bottom to perforate. Hence the proposal to replace drilling mud in the liner to a solids free brine. Thank you for your consideration, Bob Laule and Mike Stefanov Confidentiality Notice: This email and its attachments (if any) contain confidential information of the sender. The information is intended only for use by the direct addressees of the original sender of this email. If you are not an intended recipient of the original sender (or responsible for delivering the message to such person), you are hereby notified that any review, disclosure, copying, distribution or the taking of any action in reliance of the contents of and attachments to this email is strictly prohibited. If you have received this email in error, please immediately notify the sender at the address shown herein and permanently delete any copies of this email (digital or paper) in your possession. Confidentiality Notice: This email and its attachments (if any) contain confidential information of the sender. The information is intended only for use by the direct addressees of the original sender of this email. If you are not an intended recipient of the original sender (or responsible for delivering the message to such person), you are hereby notified that any review, disclosure, copying, distribution or the taking of any action in reliance of the contents of and attachments to this email is strictly prohibited. If you have received this email in error, please immediately notify the sender at the address shown herein and permanently delete any copies of this email (digital or paper) in your possession. 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 Mike Stefanov Drilling Manager Furie Operating Alaska, LLC 433 W 9th Avenue Anchorage, Alaska 99501 Re: Kitchen Lights Unit, Undefined Beluga and Sterling Natural Gas Pools, KLU A-4A Furie Operating Alaska, LLC Permit to Drill Number: 224-075 Revised Surface Location: 339' FSL, 891' FWL, Sec. 24, T10N, R11W, Seward Bottomhole Location: 362' FSL, 3584' FWL, Sec. 24, T10N, R10W, Seward Dear Mr. Stefanov: 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 23rd day of October 2024. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.10.23 15:57:05 -08'00' 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: 8,525' TVD: 7,914' 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): 114.1' 15. Distance to Nearest Well Open Surface: x-294325.85 y- 2536121.20 Zone- 4 to Same Pool: See attachments 16. Deviated wells: Kickoff depth: 3,713 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 46.57 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 6.75" 3.5" 9.2# L-80 JFE Lion 4,932' 3,593' 3,350' 8,525' 7,914' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): TVD 365' 2,154' 7,451' 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: Mike Stefanov Mike Stefanov Contact Email:m.stefanov@furiealaska.com Drilling Manager Contact Phone:(615) 738-8596 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):Perforation Depth MD (ft): 2,022' 13-3/8" Driven 365' 2,154'Lead: 300 bbl,Tail: 94.3 bbl Effect. Depth MD (ft): Effect. Depth TVD (ft): Cement Volume MD Conductor/Structural 20"304' Authorized Title: LengthCasing Size See attached well schematic Authorized Signature: Stage 1: 205.8 bbl, Stage 2: 268.8 bbl Production Liner 8,423' Intermediate Authorized Name: See attached well schematic Plugs (measured): (including stage data) Lead 1: 186 sks 12 lb/gal Lead 2: 226 sks 12 lb/gal 2,560 18. Casing Program:Top - Setting Depth - BottomSpecifications 4,198 psi GL / BF Elevation above MSL (ft): Total Depth MD (ft): Total Depth TVD (ft): 402-081A STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 Tail: 235 sks 15.3 lb/gal 3,763 psi 297' FSL, 2095' FWL, Sec. 24, T10N, R11W, Seward 362' FSL, 3584' FWL, Sec. 24, T10N, R10W, Seward 433 W. 9th Avenue, Anchorage, AK 99501 Furie Operating Alaska, LLC 339' FSL, 891' FWL, Sec. 24, T10N, R11W, Seward ADL 389197, ADL 389196 KLU A-4A Kitchen Lights Unit Undefined Beluga and Sterling Natural Gas Pools November 1st, 2024 3+ miles to non-Furie property Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. 8,481'9-5/8" s N ype of W L l R L 1b S Class: s Noq'''d::: Ye s Nooo reees::: Ye q oooooo DDrill tsss Se siss s tsss T DDrill Dril Se t s N : well is s 5.005 s S S S S S s No ooooooq'd:'d:'d:'d:d:d:d: Yes N s y E S s No oooooooo s KLU A-4A 10-401 Form Page 1 Drilling Manager API Number:it A l ion Use Only By Grace Christianson at 8:44 am, Sep 30, 2024 BJM 10/21/24 A.Dewhurst 22OCT24 DSR-10/2/24 Initial BOP test to 5000 psi. Subsequent BOP test to 4700 psi. All Annular tests to 2500 psi. Starting November 1, BOP test frequency is every 7 days. Submit FIT/LOT data and obtain AOGCC approval before drilling production hole. Separate sundry required for perforating. 224-075 8:34 am, Oct 22, 2024 50-733-20682-01-00 *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.10.23 15:57:16 -08'00'10/23/24 06/25/24 RBDMS JSB 103024 1 September 27, 2024 Bryan McLellan Sr. Petroleum Engineer Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Re: Furie Operating Alaska KLU A-4 ST Permit to Drill (10-401) Submittal Mr. McLellan, Please see attached resubmittal for previously approved permit to drill for well KLU A-4A (PTD 224-075). Please note the revised directional plan. Well KLU A-4 is planned to be sidetracked to access alternative Sterling and Beluga formation production. The well will be completed with a 3-1/2” gas lift tie-back completion. A separate sundry notice has been approved for the KLU A-4 plug back operations. A separated sundry will be submitted for perforating operations. Drilling operations are expected to commence approximately November 2024. Regards, Mike Stefanov Drilling Manager Furie Operating Alaska, LLC 2 KLU A-4A Permit to Drill (10-401) Julius R Platform September 27 th, 2024 3 Contents 1. Well Information...........................................................................................................................................4 2. Tubular Program ...........................................................................................................................................4 3. Drill Pipe Information....................................................................................................................................4 4. Current Wellbore Schematic..........................................................................................................................5 5. Pre-Sidetrack Schematic................................................................................................................................6 6. Planned Wellbore Schematic.........................................................................................................................7 7. Drilling Summary...........................................................................................................................................8 8. Mandatory Regulatory Compliance / Notifications........................................................................................9 9. BOP N/U and Test........................................................................................................................................10 10. 6.75" Production hole mud program summary:...........................................................................................11 11. Make Up the Baker Mechanical Set Whipstock. ..........................................................................................12 12. Mill Window Plus 20-30' of New Hole .........................................................................................................13 13. Drill 6.75” Hole Section................................................................................................................................14 14. Run 3-1/2” Production Liner........................................................................................................................17 15. Cement 3-1/2” Production Liner..................................................................................................................18 16. Run 3-1/2" Upper Completion Assembly.....................................................................................................21 17. ND BOPE/RDMO..........................................................................................................................................22 18. Run Cement Bond Log.................................................................................................................................22 19. Perforated Productive Beluga Zones ...........................................................................................................22 20. Anticipated Drilling Hazards........................................................................................................................23 21. FIT Procedure..............................................................................................................................................25 22. BOP Schematic ............................................................................................................................................26 23. Choke Manifold Schematic.........................................................................................................................27 24. Wellhead Schematic (Current).....................................................................................................................29 25. Time vs. Depth Plot .....................................................................................................................................30 26. Property Plat...............................................................................................................................................31 27. Rig Information ...........................................................................................................................................32 28. Casing Design Information...........................................................................................................................35 29. 6-3/4” Hole Section for MASP .....................................................................................................................36 30. Permit to Drill Kick Tolerance Evaluation.....................................................................................................37 31. KLU A-4A Pore Pressure/Frac Gradient........................................................................................................39 32. KLU A-4A Drilling Fluid Program..................................................................................................................40 33. KLU A-4A Directional Program (wp13).........................................................................................................52 4 1. Well Information Well Name KLU A-4A Drilling Rig Spartan 151 Slot Name Slot C (KLU A-4) Directional Plan wp13 Pad and Old Well Designation Sidetrack of existing KLU A-4 (PTD: 218-069) Planned Completion Type 3-1/2” monobore w/ GLM Target Reservoirs Sterling/Beluga Kick Off Point +/- 3,713’ MD (wp13), Set WS anchor at 3,732’ MD Planned Well TD, MD/TVD 8,525’ MD/7,914’ TVD Surface Location (Governmental) 339’ FSL, 891’ FWL, Sec. 24, T10N, R11W, SM Surface Location (NAD 27) X=294325.85, Y=2536121.2 AFE Number 2024-04 AFE Days 25 Work String 4.5” Delta 425 16.60# RT – Mean Sea Level (MSL) 144.10 ft RT – Mud Line (ML) 232.10 ft RA Tag 3,698’ MD Water Depth Tidal Difference - +/- 20’ 88.00’ ft 2. Tubular Program Hole Section OD WT (#/ft) Couple OD ID (in)Drift (in)Grade Conn Top Bottom 6.75” 3.5” 9.2 3.96” 2.949” 2.867” L-80 JFE LION Surface 8,525’ **Minimum of 100’ overlap required between casing strings o Top of the Lower Sterling is anticipated to be 3,543’ MD RKB. o Top of the Beluga is anticipated to be 5,489’ MD RKB. 3. Drill Pipe Information Hole Section OD ID TJ ID TJ OD WT (#/ft)Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) 6.75” 4.5” 3.826 3.0 5.25 16.6 S-135 Delta 425 17690 16800 468 5 4. Current Wellbore Schematic 6 5. Pre-Sidetrack Schematic 7 6. Planned Wellbore Schematic 8 7. Drilling Summary KLU A-4 at the time this program is being prepared, is producing a limited amount of gas in the Beluga in the range of 1 MMSCFD of gas. The well is planned to be sidetracked to targets in the Beluga and Sterling formations. Except for limited production in the Beluga, the production intervals of KLU A-4 have been abandoned. A cement retainer will be set at 3,732’ MD which is 138’ above top of the packer at 3,870’ and 115 bbl of cement will be squeezed in the Sterling and Beluga perforations. The casing and the retainer will be tested to 4,200 psi. The parent wellbore will be sidetracked, and new wellbore drilled to 8,525’ MD. A 3.5” L-80 9.2# JFE Lion production liner will be run, cemented, and perforated based on data obtained while drilling the interval. The well will be completed with a 3-1/2” gas lift upper completion tied-back to the 3-1/2” lower completion. Drilling operations are expected to commence approximately November 2024. General sequence of operations pertaining to this drilling operation conducted under 10-401 Sundry: 1. Run 9-5/8” casing scraper to top of retainer. CBU. 2. RIH and set 9-5/8” whipstock anchor at 3,732’ MD. Displace well to 9.5-10 ppg LSND mud. 3. Mill window and 20-30’ of new formation. 4. Perform FIT to 14 ppg EMW. POH. 5. PU 6.75” cleanout drilling assembly and TIH to the 9-5/8” window. Drill enough hole to bury MWD/LWD BHA assembly, which will be about 210’. Circulate until returns are free of metal cuttings. Anticipate about 300# of steel cuttings. POOH. 6. Drill 6.75” production hole to 8,525’ MD, performing short trips as needed. 7. Condition mud. 8. POOH to casing shoe. 9. RIH for wiper trip to TD. 10. Condition mud. POOH. 11. RIH with 3-1/2” liner. Set liner, pump cement. and set liner top packer. 12. Perform liner lap test to 3,500 psi. 13. Perform polish mill and scraper run to dress top of PBR. 14. Pull wear bushing. 15. Install upper 3-1/2” completion with GLM’s with dummy valves installed and CIM with shear disk in the string. 9 16. Space out and land tubing hanger and test. 17. ND BOPE, NU tree and test. 18. Perform CBL via E-Line. 19. Sequentially perforate selected Beluga intervals as per G&G team (to be approved under a separate sundry). 8. Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. x BOPs shall be tested at 2-week intervals during drilling and at 1 week intervals during abandonment operations. Ensure to provide AOGCC 48 hours’ notice prior to testing BOPs. x The initial test of BOP equipment will be to 250/5,000 psi and subsequent tests of BOP equipment will be to 250/4,700 psi for 5/5 min (annular to 50% rated WP, 2,500 psi on the high test for initial and subsequent tests). o Confirm that these pressures match those specified on the APD. o The highest reservoir pressure expected is 4,198 psi in the Beluga lower sand (7,914’ TVD). MASP (MPSP) is 3,763 psi with 0.055 psi/ft gas in the wellbore. o A casing test to 4,200 psi is planned as part of the pre rig work. o Pressure test Mechanical Integrity Test Inner Annulus (MITIA) to 4,000 psi, which is greater than the MPSP (MASP) of 3,763 psi. x Minimum required Rated Working Pressure (RWP) of the BOPE and wellhead must exceed: 3,900 psi. The wellhead and BOPE system will be rated to 5,000 psi. x If the BOP is used to shut in on the well in a well control situation, ALL BOP components utilized for well control must be tested prior to the next trip into the wellbore. This pressure test will be charted same as the 14-day BOP test. x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid system”. x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements” 10 x Review all conditions of approval of the PTD on 10-401 form. Ensure that the conditions of approval are captured in shift handover notes until they are executed and complied with. x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. Required AOGCC Notifications: x Well control event (BOPs utilized to shut in the well to control influx of formation fluids). x 48-hour notice prior to full BOPE test. x Any other notifications required in APD conditions of approval. AOGCC Contact Information: x Jim Regg / AOGCC Inspector/ (O): 907-793-1236 / Email: jim.regg@alaska.gov x Bryan McLellan / Petroleum Engineer/ (O): 907-793-1226 / (C): 907-250-9193 / Email: bryan.mclellan@alaska.gov x Melvin Rixse / Petroleum Engineer/ (O): 907-793-1231 Email: melvin.rixse@alaska.gov Primary Contact for Opportunity to Witness: x Test/Inspection notification standardization format: Test Witness Notification - Alaska Oil and Gas Conservation Commission (state.ak.us) x Notification/ Emergency Phone: 907-793-1236 (During normal Business Hours) x Notification/ Emergency Phone: 907-659-2714 (Outside normal Business Hours) 9. BOP N/U and Test 1. N/D Tree master valve and adapter (BPV will be installed as part of the abandonment operations), inspect landing threads in tubing hanger. Make dummy run to check threads. Install plug off tool. 2. Check the full drift of any spacer spools used several days prior to installation. 3. N/U to 13-5/8" 5M X 13-5/8” 5M spool. 4. N/U 13-5/8" x 5M BOP as follows (top down): o 13-5/8" x 5M Shaffer spherical annular BOP. 11 o 13-5/8" Shaffer SL Double ram. (2-7/8" X 5" VBR in top cavity, blind ram in bottom cavity). o 13-5/8" mud cross. o 13-5/8" Shaffer SL single ram. (2-7/8" X 5" VBR). o N/U bell nipple, install flowline. o Install (1) manual valves on kill side of mud cross. Manual valve used as inside or "master valve". o Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. 5. Test BOPE. o Test BOP to 250/5,000 psi for 5/5 min. Test annular to 250/2,500 psi for 5/5 min. o Ensure to leave "A" section side outlet valves open during BOP testing so pressure does not build up beneath the back pressure valve with plug off tool. Confirm the correct valves are opened. o Test VBRs on 3.5” and 4.5" test joint (5,000 psi). o Test Annular on 4.5" test joint (2,500 psi). o Ensure gas monitors are calibrated and tested in conjunction w/ BOPE. 10.6.75" Production hole mud program summary: o Primary weighting material to be used for the hole section will be barite to minimize solids. Ensure enough barite is on location to weight up the active system 1ppg above highest anticipated MW in the event of a well control situation. o Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, and Toolpusher office and mudlogging unit if on rig. o Program mud weights are generated by reviewing data from producing & shut-in offset wells, estimated BHP's from formations capable of producing fluids or gas and formations which could require mud weights for hole stabilization. o A guiding philosophy will be that it is less risky to weight up a lower weight mud than be overbalanced and have the challenge to mitigate lost circulation while drilling ahead. Need to maintain overbalance at all times. -bjm 12 11.Make Up the Baker Mechanical Set Whipstock. x A bond log and CCL has been recorded over the whipstock anchor setting depth of 3,730’ MD. o RA tag at 3,698’ MD. o 3,700’ – 3,740’ MD looks like good cement. (Per SLB) o Joint 99 - 3,697’ – 3,738’ MD. o Set plug as close to bottom as possible. x Anticipated metal cuttings from window will be about 300 lbs. x Ditch magnets/string magnets (2). x Weight of 20,000 lbs to be set on the retainer. o Anchor pinned, ~15K to set. Verify 15K can be set with no movement x The bottom of the whipstock should be set closer to the top of the casing connection. Check pipe tally and space out. (WS Anchor 3,732’ MD and collar at 3,738’ MD) x NOTE the 9-5/8” casing was run with one centralizer per joint. x The whipstock run will be made with an MWD survey. x Simulation Run BHA: o 8-1/2” Bit\Bit Sub\Full Size Watermelon Mill\Scraper\4-3/4” Drill Collar \full drift stabilizer\HWDP\ Jars o Baker 4.5” IF connections 6. Optional: Run wireline gauge ring in lieu of casing scraper run to verify all SS bands are pushed to bottom. 7. RIH with Simulation run and tag cement retainer at 3,732’ MD. 8. Reciprocate the assembly across the whipstock setting depth. o Note any tight spots during this operation and advise Drilling Manager and Drilling Engineer in Anchorage 9. Circulate bottoms up, to ensure the hole is clean. 10. POOH with Simulation BHA. 11. Make up the Whipstock assembly in the rotary, using the whipstock handling bar. o Lower Whipstock BHA: TorqueMaster mechanical set anchor\WindowMaster Whipstock o Upper Whipstock Milling Assembly: Window Mill\Lower Watermelon mill\flex joint\ Upper Watermelon mill\Float Sub\XO\MWD tool\HWDP(s)\Drill Pipe 12. Install the milling assembly. 13 13. Remove the whipstock handling bar, RIH and set the slips on the Drill Collar above the upper watermelon mill. 14. Pick up the MWD assembly. o Measure and record MWD tool face from the scribed line from the whipstock shear stud. This will ensure the alignment of the whipstock. 15. Hold a pre-trip meeting with the drilling crew, directional driller, and Baker whipstock hand etc. 16. Run string at 2 to 3 minutes per stand. 17. Take care running assembly through the BOPs and other potentially tight spots. 18. TIH with string to the whipstock. Shallow test the MWD. 19. TIH with DP to the whipstock anchor setting depth at 3,730’ MD. Exercise caution when RIH and setting slips with whipstock assembly. 20. Fill the drill pipe a minimum of every 10 stands on the trip in the hole with the whipstock assembly. o These precautions are required to avoid any weakening of the whipstock shear mechanisms and/ or to avoid parting/ presetting of the packer. o Orient whipstock as directed by the directional driller. o Orient at least 30’ - 90’ above retainer. 21. Set the top of the whipstock at 3,713’ MD.WS anchor at 3,730’ MD. o 13-3/8” 68# L-80 surface casing set at 2,172’ MD. o 9-5/8" 47# L-80 production casing run from surface to 8,482’ MD. o Ref log: FURIE-KLU_A1_IBC-CBL-GR-CCL_ 4 Oct 2018 12.Mill Window Plus 20-30' of New Hole (DO NOT EXCEED 50' OF NEW HOLE BEFORE RUNNING THE PLANNED FIT) 22. Use ditch magnets to collect the metal shavings. Clean regularly. 23. Ensure any personnel working around metal shavings wear proper PPE, including goggles, face shield and Kevlar gloves. 24. Work the upper mill through the window to confirm the window milling is complete and circulate well clean (circulate a minimum of 1-1/2 bottoms up). 25. Pump a high-vis sweep to remove metal shavings and make every effort to remove all of the hi-vis sweep from the mud system as it is circulated to surface. o Pump sweep every 3-5 feet (10-15 bbls). 26. Condition mud. 14 27. Pull starter mill into casing above top of whipstock, flow check the well for 10 minutes and conduct a FIT to 14 ppg. Any FIT greater than 13 ppg is sufficient to continue operations. o **Assuming the kick zone is at TD, a FIT of 14 ppg EMW gives a Kick Tolerance volume of 27.6 bbls with 10.7 ppg mud weight. o Monitor 9-5/8 x 13-3/8” annulus during FIT and report any change in pressure. o Contact AOGCC to witness FIT 48 hours in advance. Submit FIT results to AOGCC. 28. POOH and LD milling assembly. o Flow check well for 10 minutes to confirm no flow: Before pulling off bottom. Before pulling the BHA through the BOPE. 29. Once out of the hole, inspect mill gauge and record. Record weight of milled cuttings recovered. If upper watermelon mill is more than 1/8” under gauge, PU second set of mills (polish BHA). 30. Flush the stack/lines to remove metal debris that may have settled out in these areas. Ensure BOP equipment is operable. 31. At least one Baker hand to stay on location until milling BHA is pulled out of window and is laid down and drilling and logging assembly is run through the window. 13.Drill 6.75” Hole Section 32. PU 8,600’ of 4.5" Delta 425 drill pipe for drilling 6.75" hole section. 33. P/U 4.75" Sperry motor with a 1.5 degree bend and drilling cleanout assembly, with no logging tools. 34. Drill ~210’ to have sufficient hole to bury MWD/LWD BHA (length determined by total length of logging tools) with this assembly to ensure hole is clean. 35. POOH and pick up MWD/LWD BHA. 36. TIH. Clear the rig floor while installing nuclear sources in the Density (ALD) and Neutron (CTN) tools Shallow test MWD/LWD on trip in. Ensure Sperry MWD/LWD service rep on rig floor during this operation. Fill pipe every 10 stands while running in the hole. 37. Circulate well with 9.5-10 ppg LSND to warm up mud until good 9.5-10 ppg in and out. 38. Drill 6.75" hole to 8,525' MD. Need to maintain overbalance. Follow mud weight increase schedule in the PPFG chart section 31 to maintain overbalance at all times . -bjm Need to check calculations. I get 19.2 bbls. Pull starter mill into casing above top of whipstock, flow check the well for 10 minutes and conduct a FIT to 14 ppg. Any FIT greater than 13 ppg is sufficient to continue operations. **Assuming the kick zone is at TD, a FIT of 14 ppg EMW gives a Kick Toleranceo volume of 27.6 bbls with 10.7 ppg mud weight. Circulate well with 9.5-10 ppg LSND to warm up mud until good 9.5-10 ppg in and out. 15 o Plan to run triple combo (DENSITY, POROSITY, RESISTIVITY) + Sonic. Motor bend of 1.5 deg. If any stickiness may need to backream some intervals. Preferred option is to drill to stand down, then mad pass each stand to acquire density data. o Top of the Lower Sterling is anticipated to be 3,543’ MD RKB. o Top of the Beluga is anticipated to be 5,489’ MD RKB. o No major anticipated faults expected to be encountered. o Pump sweeps and maintain mud rheology to ensure effective hole cleaning. o Utilize Inlet experience to drill through coal seams efficiently. Coal seam log will be provided by Geo team, try to avoid sliding through coal seams. Work through coal seams once drilled. o Keep swab and surge pressures low when tripping. Minimize the number of short trips unless wellbore problems such as torque, pickup/slackoff increases. o Ensure solids control equipment is functioning properly and utilized to keep LGS to a minimum without excessive dilution. o Adjust MW as necessary to maintain hole stability. o Ensure mud engineer set up to perform HTHP fluid loss. o Maintain API fluid loss < 6 ml/30 minutes. HPHT < 11 ml/30 minutes at 200° o Ensure Low Gravity Solids (LGS) are maintained at less than 6 %. o Take MWD surveys every stand drilled. o Minimize backreaming when working tight hole. o Drilling fluid Use thicker, more viscous milling fluid for window milling. Thin it back for drilling below the casing window with same fluid. Drilling/milling fluids have to be approved for discharge. Any different additives have to be approved for discharge prior to use. Additives include KCl, amine salt, etc. for inhibition. Inhibited polymer mud, seawater based. Review Baroid provided coal drilling recommendations. Mud will include LCM in recipe. o Directional drilling Run a stabilizer right above the motor to prevent hole angle building more than desired. Stay within 100’ radius of directional plan. Control drill at 40-60 ft/hr if losses encountered. Non fibrous LCM limited to no more than 40 lb/bbl. o Sonic tool 16 250-280 gpm desirable range for logging tools. Typically have a float in motor, to be provided by directional company . Turbine in logging tools generates power while circulating for LWD\MWD tools. Battery is primarily a backup power source when not circulating. o Bits GTD54DM primary, GT64D backup recommended x (5 and 6 refer to number of blades, 5 blade has larger junk slots for coals and clays) WOB 6-10 Klbs, up to 15K+ lbs if needed. RPM 240-380 total bit RPM, string rpm between 50 to 70. Cutters on back of blades to allow for backreaming if desired. Optimize bit weight and rotation to minimize vibration on logging tool. o Electric line/Slickline Pipe recovery will be prepared for as needed. Unit available that can be used for slickline on platform. Different diameters of E-Line available. o Cementing - Centralizers Use stop collars on shoe track to keep centralizers in place. Centralizers may be free floating on rest of liner or can use stop collars. Slip on type, as opposed to clamp on. Bridgemaker with multiple types and particle sizes of LCM will be added to the tail end of the lead cement slurry to cure losses. Bridgemaker will be mixed with the bulk cement at the bulk plant and sent to rig. 39. At TD pump a sweep and a marker, to be used as a fluid caliper to determine annular volume for cement calculations. CBU and pull a short trip back to the window back to TD. 40. TOH with drilling assembly, handle BHA as appropriate. 17 14.Run 3-1/2” Production Liner 41. The float shoe, float collar and landing collar should be premade up with thread lock compound, prior to shipment to the rig. Prepare and rack back the liner cement head (Halliburton). 42. Note the liner hanger and running tool have been pre-made up at the Frontier facility in Houston. 43. R/U 3-1/2" liner running equipment including torque turn equipment (Parker) for JFE Lion 3-1/2” 9.2# L-80 tubing. 44. P/U shoe joint, visually verify no debris inside joint. 45. Continue to M/U and thread lock shoe track assembly consisting of float shoe, three joints of tubing, float collar, and landing collar joint. 46. Continue running 3-1/2" production liner in the hole. 47. RIH w/ liner no faster than 30 seconds per joint. Watch displacement carefully to avoid surging the hole. Slow down running speed if necessary, to minimize surge pressures and chances of losing circulation. 48. Fill pipe while lowering string every 10 joints. 49. Set string slowly in and pull slowly out of slips. 50. Circulate 1-1/2 string volumes at the 9-5/8” casing window prior to going into open hole. Stage pumps up slowly and monitor for losses. Do not exceed 60 % of the nominal liner hanger setting pressure of 1,933 psi, which is roughly 1,160 psi. 51. Obtain up and down weights of the liner before entering open hole. 52. Run enough liner to provide at least 100' overlap inside casing. Ensure setting sleeve will not be set in a connection. 53. Before picking up liner hanger/ packer assembly, count the number of joints on the pipe deck to make sure it coincides with the pipe tally. 54. M/U liner hanger and top packer assembly. Fill liner tieback sleeve with viscous mud, that is thin enough to travel past the running tool down to the packoff. 55. RIH one stand and circulate a minimum of one string volume. Note weight of liner. 56. Check to see that the liner shoe is opposite a competent formation before circulating based on LWD logs. Consider reciprocating liner to prevent washout as shoe is in open hole. 57. Record weight of liner. This is the approximate weight to be lost when hanger is set. 58. Continue to fill the string every 10 stands while running liner. Do not stop to fill casing. 18 59. PU the cement stand and tag bottom with the liner shoe. PU 10' off bottom. Note slack-off and pick-up weights. 60. Stage pump rates up slowly to circulating rate without exceeding 60% of the liner hanger setting pressure of 1,933 psi, which is 1,160 psi. Circ and condition mud with the liner on bottom. Reduce the low-end rheology of the drilling fluid by adding water and thinners. 61. Reciprocate if hole conditions allow. Circ until hole and mud is in good condition for cementing. 62. Set liner 5-10’ off bottom. 63. Release setting ball from the liner cement head and displace at 1-3 bbl/min. Pressure up to 1,933 psi to shear the hanger cylinder, hold pressure for one minute. Set the liner hanger slips by slacking off 30 K lbs. Bleed off pressure. 64. For setting the hanger, hold hanger running tool in compression. Pressure up to 2,520 psi to shear setting tool and hold pressure for 2 minutes. Bleed off to 500 psi and pick up to release the running tool. Do not pick up more than 4 feet to ensure that the liner hanger packer is not set. If running tool does not release, pressure up to 2,750 psi, 3,000 psi and 3,200 psi. After each try to confirm release. If running tool does not hydraulically release, it can be mechanically released. Rotate string to the left ¼ turn at tool with 2,550 ft-lbs of torque. After rotation shear, then set down 16,200 lbs to shear. Tool will then be released. 65. Set back down 20K lbs. Pressure up to 3,668 psi to shear out ball seat. 66. Proceed pre-cement job circulation and cement job. 15.Cement 3-1/2” Production Liner 67. Hold a pre-job safety meeting for the upcoming cementing operations. 68. Pump 5 bbls of fresh water. 69. Test surface cement lines to 4,500 psi. 70. Pump 60 bbls 10.5 ppg spacer. 71. Mix and pump 78 bbls of lead cement without bridgemaker y cement volume with actual inputs. Ensure cement is pumped at designed weight, using a pressurized mud balance. Job is designed to pump 40 % OH excess (based on caliper), but if wellbore conditions dictate otherwise decrease or increase excess volumes. Ensure cement with Bridgemaker does not make it to liner top. Cement volume is designed to bring cement to TOL. 72. Displacement fluid will be clean drilling mud. Program displacement is estimated at 93 bbls (Drill pipe and liner). Please independently verify with actual inputs. Plan to pump first lead (78 bbls) second lead (96 bbls) and tail (52 bbls) as shown in cement design below. - bjm 19 73. Pump cement at max rate of 5 bpm maximum, monitor pump pressures. Reduce pump rate to 3 bpm prior to latching DP dart into liner wiper plug. Note plug departure from liner hanger running tool and resume pumping at full displacement rate. Displacement volume can be re-zeroed at this point. Drill pipe displacement is about 47 bbl (3,593’ X .0132 bbl/ft) and liner displacement is 42 bbls (4,842’*.008699 bbl/ft). Follow cement with 10 bbls freshwater, 30 bbls mud and 30 bbls spacer and 20 bbls mud behind to bump the plug. This will place spacer across the liner top. 74. Monitor returns & pressure closely while circulating. Notify Well Site Supervisor immediately of any changes. Reduce pump rate as required to avoid packoff. 75. Do not over displace by more than 10 bbls = 308’ of liner X OH volume. Review this value based on lowest possible perf interval. Current estimate for Beluga BL1 upper is 7,800’ MD 7,106’ TVDss. The priority is to get a clean wellbore down to the landing collar. Lead #1: No LCM System SBM CEM ECONOCEM Density 12 lb/gal Design Volume 78 bbls Yield 2.3550 ft3/sk Mixed Water 13.947 gal/sk Expected Thickening 2.5-5 hrs API Fluid Loss < 100 Additives Code Description Concentration Type I/II Halad 344 HR-5 D-Air 5000 SA-1015 Cement Fluid Loss Retarder Defoamer Suspension Aid 94 lbs/sk 0.4 % 0.3 % 0.2 % 0.125 % 20 Lead #2: Bridgemaker LCM System SBM CEM ECONOCEM Density 12 lb/gal Design Volume 96 bbls Yield 2.388 ft3/sk Mixed Water 14.068 gal/sk Expected Thickening 2-4 hrs API Fluid Loss < 100 Additives Code Description Concentration Type I/II Halad 344 HR-5 D-Air 5000 SA-1015 BridgeMaker II Cement Fluid Loss Retarder Defoamer Suspension Aid LCM 94 lbs/sk 0.4 % 0.3 % 0.2 % 0.125 % 5 lb/bbl Tail System SBM CEM VERSACEM TAIL Density 15.3 lb/gal Design Volume 52 bbls Yield 1.24 ft3/sk Mixed Water 5.57 gal/sk Expected Thickening 4-5 hrs API Fluid Loss < 100 Additives Code Description Concentration Type I/II Halad 344 HR-5 CFR-3 FDP-C1446-21 Cement Fluid Loss Retarder Dispersant Gelation inhibitor 94 lbs/sk 0.3 % 0.35 % 0.3 % 0.3 % 76. Bleed pressure to zero to check float equipment. 77. Pick up to release liner running tool and set packer. 78. To set packer. PU to neutral weight. Pick up a minimum of 9 feet, maximum of 11 feet. This will release Setting Dogs. Slack off 50K to shear packer setting pins with 30,240 lbs. Set down stoke should be only a few feet. If it strokes fully back 21 down, the Setting Dogs did not release outside of Tie Back Receptacle. Pick up 2 feet further than prior pick up and slack off again. 79. Circulate surface to surface to remove any spacer and cement. 80. Test packer by pressuring down the backside 3,500 psi for 30 minutes. Record test on chart recorder. 81. Bleed off pressure. Slack off to neutral to weight. 82. Circulate well. 83. Pick up lower PBR polish mill and 9-5/8” casing scraper assy and RIH to liner top CBU. Change over to inhibited sea water. POOH. o Note: Caliper OD’s and ID’S and strap all components going below the rotary. We need to have fishing dimensions and sketches for anything that goes below the rotary. 84. Be sure to have rabbits for all tubulars used in the completion. 85. Rabbit 3-1/2” as picked up and get good strap. Only one rabbit on the floor and nothing rabbited near the rotary. 86. Optional: Slickline run with gauge ring to total depth. 16.Run 3-1/2" Upper Completion Assembly 87. Confirm the GLM’s and chemical injection mandrel with dummy valves installed, and SSSV are stenciled as being dummied off. Ensure seal assembly has been redressed and is on site. 88. MU seal stem assembly. 89. RU torque turn equipment for JFE Lion 3-1/2” 9.2# L-80 connection specification. 90. MU 3-1/2” 9.2 #L-80 monobore completion with GLM’s, chemical injection mandrel, SSSV and seal stem. RIH while spooling chemical and control lines. Make up control lines and test at 5,000 psi after connections are made. Maintain approximately 200-300 psi over opening pressure. Test pressure estimated at 2,500 psi pressure on chemical injection line and SSSV control line while running. Establish space out. 91. PU and space out. Set down 10K. Mark pipe to establish space out pup requirements. Pressure Inner Annulus (3-1/2”x9-5/8”) to 2,500 psi to confirm seal engagement. 92. PU install space out pups one joint below tubing hanger. 93. Terminate control lines and tie into tubing hanger. PT control lines to 5,000 psi. 94. Install ¼” Swagelok fitting and ¼ turn valve. Pressure up to 5,000 psi and lock in pressure to keep SSSV open while landing the tubing hanger. 22 95. Land tubing hanger. Test SSSV control line and chemical injection line at 5,000 psi. 96. PT annulus to 3,500 psi per AOGCC requirement and record on chart for 15 minutes. 17. ND BOPE/RDMO 97. Install BPV. 98. ND 13-5/8” BOP. Install plug off tool in BPV. 99. Confirm correct orientation of flow cross prior to tightening studs and nuts. NU and pressure test 4-1/16” 5K tree to 5000 psi. 100. Retrieve BPV and plug off tool. 101. Release to Production. 18. Run Cement Bond Log 102. Contact Halliburton cementer for impedance value for the cement versus time. 103. R/U E-line and run 1-11/16” CBL. Put log on depth tying into the original open hole log dated October 4, 2018. 19. Perforated Productive Beluga Zones 104. A separate 10-403 sundry will be submitted for perforating operations. 23 20.Anticipated Drilling Hazards Lost Circulation: Drilling depleted reservoir may cause loss circulation events. x Maintain sufficient mud volumes while drilling. x Maintain ability to take on fresh water during drilling phase. x If a LC event occurs pumping cement will be the last resort x Ensure 500 lbs. of medium/coarse fibrous material, 500 lbs. SteelSeal (Angular, dual- composition carbon-based material), & 500 lbs. different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. x No LC events occurred during the original drilling of KLU A-1 x KLU A2/A2A: Lost circulation in production with a loss rate of 120bph. Losses cured with 30ppb LCM sweeps. x KLU A-4: Lost circulation in Production hole with a loss rate of 105bph. Losses cured with 16ppb LCM sweeps. o 6,282’ MD Well Control: x Prior to drilling into the Sterling, Beluga, and Tyonek (if any), hold a pre-reservoir meeting to outline heightened awareness for kick detection and lost circulation. x Following any Tyonek formation penetration, pick up off bottom, shut off the pumps and perform a flow check to verify there isn’t any overpressure. x Review Kick tolerance based on actual FIT data. Hydrates and Shallow gas x No hydrates are expected in this area. x No H2S are expected in this area. x Ensure H2S monitoring equipment as specified in 20 AAC 25.065(1) will be functioning on the rig as standard operating procedure. x Ensure products for treating H2S contamination in the drilling mud system will be maintained on the rig. Find out if they will drill into the Tyonek. The Tyonek will not be penetrated in this well per Mike Stefanov email 10/18/24 attached. -bjm 24 Hole Cleaning: Maintain rheology w/ viscofier as necessary. Sweep hole w/ 20 bbls vicious pill as necessary. Optimize solids control equipment to maintain density and minimize sand content. Maintain programmed mud specs. Recommended flow rate in 6.75” hole is 200 to 330 GPM. The wellbore will be cleaned with a low vis(water), hi vis weighted sweeps. Monitor returns closely for signs of gas and circulate out all gas cut mud before continuing drilling. Anticollision: No close approaches. See directional plan for anticollision analysis. Coal Drilling: The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The need for good planning and drilling practices is also emphasized as a key component for success. x Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. x Use asphalt-type additives to further stabilize coal seams. x Increase fluid density as required to control running coals. x Emphasize good hole cleaning through hydraulics, ROP and system rheology. x Minimize swab and surge pressures. x Minimize back reaming through coals when possible. x Once in a coal seam, maintain the hydraulic pump pressure and GPM until the bit has been reamed back up and is out of the coal seam, EVEN IF MUD LOSSES ARE EXPERIENCED. Then observe the well and the hydraulics “may” need to be reduced to keep from losing circulation and causing the coals to water wet, which may create sloughing problem in the coals, utilizing the water loss additives and asphaltenes to combat the water wetting aspects. Lost circulation materials (a combination of various sizes of calcium carbonates) should be utilized initially. 25 21.FIT Procedure Procedure for FIT: 1. Drill 20-30' of new formation below the casing window. 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. Add casing pressure test data to graph if recent and available. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in I-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure and allowing for an appropriate amount of kick tolerance in case well control measures are required. Statement deleted per Mike Stefanov email 10/18/24 attached. -bjm Casing pressure -bjm See Mike Stefanov email 10/18/24, ref section 21, for change to FIT procedure attached. -bjm 26 22.BOP Schematic 27 23.Choke Manifold Schematic 28 29 24.Wellhead Schematic (Current) 3025.Time vs. Depth Plot30p 3126.Property Plat31111311313111111111313111311113111111131311113133131131311313331311111133331311111111 32 27.Rig Information 33 34 35 28.Casing Design Information Hole Size: 6.75” Mud Density: 9.5-10.7 ppg Planned Top: 3,593’ MD/ 3,350’ TVD Planned TD: 8,525’ MD/ 7,914’ TVD MASP: 3,763 psi (see attached MASP determination and calculation) Collapse Calculation: Normal gradient external stress (0.431 psi/ft) and the casing evacuated for the internal stress. Gas Gradient: 0.055 psi/ft Calculation/Specification Casing OD 3.5” Top (MD) 3,593’ MD Top of Liner Top (TVD) 3,350’ TVD Top of liner Bottom (MD) 8,525’ Bottom (TVD) 7,914’ Length 4,932’ Weight (ppf) 9.2 Grade L-80 Connection JFE Lion Weight w/o buoyancy factor (lbs) 45,375 lbs Tension at top of section (lbs) w/ 10.5 ppg mud (BF= 0.839)38,069 lbs Minimal Tensile Strength (lbs) 207,000 lbs Worst case safety factor (Tension w/o BF) 4.56 Collapse pressure at bottom (psi) – 10.7 ppg mud and gas gradient of 0.055 psi/ft 4,403 Collapse Pressure 10,540 psi Worst case safety factor (Collapse) Gas filled tubing 2.39 36 29.6-3/4” Hole Section for MASP Planned Top: 3,713’ MD/ 3,437’ TVD Planned TD: 8,525’ MD/ 7,914’ TVD Anticipated Formations and Reservoir Pressures Formation MD TVD Est Pressure (psi) Oil/Gas/Wet PPG Gradient Planned KOP 3,713’ 3,437’ 1,472 Gas 8.73 .4540 Planned TD 8,525’ 7,914’ 4,198 Gas 10.2 .530 Assumptions: 1. Fracture gradient is between 13.0 and 17.0 EMW. Fracture gradient at window is based on an FIT of 14.0 ppg EMW at 3,713’ MD/3,437’ TVD. (See pore pressure/frac gradient below). 2. Planned mud density for the 6-3/4” hole section is 9.5-10.7 ppg 3. Calculations assume full evacuation of wellbore to gas from reservoir Maximum Allowable Annular Surface Pressure Assuming Window ( 3,713’ MD/ 3,437’ TVD) is the Weakest Formation: MAASP (psi) = (Fracture MW – Current MW) X .052 X TVD (Window) = = (14.0 – 10.7 ppg) X .052 X 3,437’ TVD = 590 psi Maximum Anticipated Surface Pressure, if there is a complete evacuation of wellbore to gas. MASP (psi) = Formation Pressure psi – [.055(psi/ft) X TVD] = 4,198 psi – [ .055 X 7,914’ TVD] = 3,763 psi Summary: 1. MASP while drilling 6-3/4” production hole is governed by pore pressure and evacuation of entire wellbore to gas at 0.055 psi/ft. Planned TD 8,525’7,914’4,198 Gas 10.2 .530 -see attached emails. -A.Dewhurst 22OCT24 1,560 37 30.Permit to Drill Kick Tolerance Evaluation Well: A-4A Sidetrack <== Data Input Name: Furie <== Data Input Mud Weight (ppg) 10.70 <== Data Input Weak point or LOT - Measured depth (ft) 3,713'<== Data Input Weak point or LOT True vertical depth (ft) 3,437'<== Data Input Weak point or LOT - Hole angle (deg) 45.0º<== Data Input Weak point or LOT - Hole size (in) 6.750"<== Data Input Weak point pressure or LOT - EMW (ppg) 14.00 <== Data Input Zone of interest - Measured depth (ft) 8,525'<== Data Input Zone of interest - True vertical depth (ft) 7,914'<== Data Input Zone of interest - Hole angle (deg) 16.6º<== Data Input Zone of interest - Hole size (in) 6.750"<== Data Input Zone of interest - Pore pressure EMW (ppg) 10.20 <== Data Input Gas gradient (psi/ft) 0.06 <== Data Input Bottom hole assembly OD (in) 4.750"<== Data Input Bottom hole assembly length (ft) 188'<== Data Input Drill pipe OD (in) 4.500"<== Data Input BHA annular vol. @ zone of interest (bbl/ft)0.0223 DP annular vol. @ zone of interest (bbl/ft)0.0246 DP annular vol. @ weak point (bbl/ft)0.0246 Additional safety margin (psi) 100.00 <== Data Input Weak point pressure (psi):Plo 2,502 psi Weak point pressure - Safety margin:Pmax 2,402 psi Pmax EMW 13.44 ppg Max anticipated formation pressure (psi):Pf 4,198 psi Weak Pt to Zone of Interest distance (TVD ft):OH {TVD}4,477' Weak Pt to Zone of Interest distance (MD ft):OH {MD}4,812' Maximum influx height at the bit (TVD ft):H {TVD}1,387' Maximum influx height at the bit (MD ft):H {MD}1,447' Calc. volume of {H} around BHA:V1bha 4.2 bbl Calc. volume of {H} around drill pipe:V1dp 31.0 bbl Calc. volume that H equals @ initial shut in:V1 35.2 bbl Calc. vol. that H equals @ weak point (MD ft):Vwp 48.2 bbl Calc. volume of Vwp @ initial shut in:V2 27.6 bbl Kick Tolerance: V2 27.6 bbl Zone of interest Pore pressure can not be less than mud weight for kick tolerance purposes. See revised KT calculation sheet attached. -bjm KLU A4A Kick Tolerance WP13 13.0 FIT 10.7 10182024 10/18/2024 3:01 PM Well: A-4A Sidetrack <== Data Input Name: Furie <== Data Input Mud Weight (ppg) 10.70 <== Data Input Weak point or LOT - Measured depth (ft) 3,722'<== Data Input Weak point or LOT True vertical depth (ft) 3,443'<== Data Input Weak point or LOT - Hole angle (deg) 45.0º<== Data Input Weak point or LOT - Hole size (in) 6.750"<== Data Input Weak point pressure or LOT - EMW (ppg) 13.00 <== Data Input Zone of interest - Measured depth (ft) 8,525'<== Data Input Zone of interest - True vertical depth (ft) 7,914'<== Data Input Zone of interest - Hole angle (deg) 16.6º<== Data Input Zone of interest - Hole size (in) 6.750"<== Data Input Zone of interest - Pore pressure EMW (ppg) 10.70 <== Data Input Gas gradient (psi/ft) 0.06 <== Data Input Bottom hole assembly OD (in) 5.250"<== Data Input Bottom hole assembly length (ft) 638'<== Data Input Drill pipe OD (in) 4.500"<== Data Input BHA annular vol. @ zone of interest (bbl/ft)0.0175 DP annular vol. @ zone of interest (bbl/ft)0.0246 DP annular vol. @ weak point (bbl/ft)0.0246 Additional safety margin (psi) 0.00 <== Data Input Weak point pressure (psi):Plo 2,327 psi Weak point pressure - Safety margin:Pmax 2,327 psi Pmax EMW 13.00 ppg Max anticipated formation pressure (psi):Pf 4,403 psi Weak Pt to Zone of Interest distance (TVD ft):OH {TVD}4,471' Weak Pt to Zone of Interest distance (MD ft):OH {MD}4,803' Maximum influx height at the bit (TVD ft):H {TVD}821' Maximum influx height at the bit (MD ft):H {MD}857' Calc. volume of {H} around BHA:V1bha 11.2 bbl Calc. volume of {H} around drill pipe:V1dp 5.4 bbl Calc. volume that H equals @ initial shut in:V1 16.5 bbl Calc. vol. that H equals @ weak point (MD ft):Vwp 28.6 bbl Calc. volume of Vwp @ initial shut in:V2 15.1 bbl Kick Tolerance: V2 15.1 bbl NOTE: Spreadsheet revised by: G. S. Walz 3/9/99 38 39 31.KLU A-4A Pore Pressure/Frac Gradient 3939393939339393939393339399 40 32.KLU A-4A Drilling Fluid Program 41 42 43 44 45 46 47 48 49 50 51 52 33.KLU A-4A Directional Program (wp13) 53 54 55 56 57 58 59 60 61 1 Dewhurst, Andrew D (OGC) From:Mike Stefanov <m.stefanov@furiealaska.com> Sent:Tuesday, 22 October, 2024 13:21 To:Dewhurst, Andrew D (OGC) Cc:Trey Kendrick; McLellan, Bryan J (OGC); Davies, Stephen F (OGC); Mike Stefanov Subject:FW: KLU A-4A Revised PTD (224-075): Question Attachments:Page36and39Pressure.pdf Andy, The pore pressure at the kick oī point of 3,713’ MD ( 3,437’ TVD) is 1560 psi, which equates to a gradient of .4540 psi/Ō and an equivalent of 8.73 ppg. I think the previous pore pressure may have been associated with a shallower kick oī point. Please see the Pore Pressure/Frac Gradient diagram aƩached in secƟon 31 on page 39. Our geologist, Trey Kendrick, is available to discuss the methodology behind the pore pressure Įgures. Trey’s phone number is +1 281 217 1284. Thank you for advising us of this issue. Regards, Mike Stefanov Drilling Manager Furie OperaƟng Alaska LLC Tel Alaska +1 907 252 3565 Tel. +1 615 738 8596 E-Mail: m.stefanov@furiealaska.com Alternate E-Mail: mistefanov@my.lonestar.edu 433 W 9th Avenue Anchorage, AK 99501 From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Tuesday, October 22, 2024 10:48 AM To: Mike Stefanov <m.stefanov@furiealaska.com> Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov> Subject: [EXT] KLU A-4A Revised PTD (224-075): Question Mike, I am compleƟng my review of the revised KLU A-4A PTD and have one quesƟon: x Would you please double-check the anƟcipated pore pressure and equivalent pressure gradient at the KOP shown in SecƟon 29 (6-3/4”: Hole SecƟon for MASP). I’m not geƫng a 0.454 psi/Ō gradient. Thanks, Andy Andrew Dewhurst Senior Petroleum Geologist Alaska Oil and Gas ConservaƟon Commission 333 W. 7th Ave, Anchorage, AK 99501 andrew.dewhurst@alaska.gov Direct: (907) 793-1254 ***External Email*** Confidentiality Notice: This email and its attachments (if any) contain confidential information of the sender. The information is intended only for use by the direct addressees of the original sender of this email. If you are not an intended recipient of the original sender (or responsible for delivering the message to such person), you are hereby notified that any review, disclosure, copying, distribution or the taking of any action in reliance of the contents of and attachments to this email is strictly prohibited. If you have received this email in error, please immediately notify the sender at the address shown herein and permanently delete any copies of this email (digital or paper) in your possession. 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Do not click links or open attachments unless you recognize the sender and know the content is safe. 1 McLellan, Bryan J (OGC) From:Mike Stefanov <m.stefanov@furiealaska.com> Sent:Friday, October 18, 2024 3:30 PM To:McLellan, Bryan J (OGC) Cc:Mike Stefanov; Dan Robertson; Bob Laule; Hunter Van Wyhe Subject:KLU A-4AProgram Review Original Permit to Drill 224-075 FIT procedure Attachments:KLU A4A Kick Tolerance WP13 13.0 FIT 10.7 10182024.pdf Dear Bryan, Thank you for the feedback, we will incorporate your sugges Ɵons into the program. The blue font is your quesƟon and the black font is our response. SecƟon 13 Drill 6.75” Hole SecƟon Mike, please update your kick tolerance calculations such that Zone of Interest Pore pressure EMW is equal to mud weight. This is a swab kick scenario. AƩached is the work sheet using the same pore pressure as mud weight, which will yield a kick tolerance volume of 15.1 bbls. This was actually arrived at using two diīerent Kick Tolerance worksheets. Also, in section 13, step 37 & 38, you plan to drill to TD with 9.5-10.0 ppg mud, but your anticipated reservoir pressure at TD is 10.2 ppg. The last bullet in section 10 makes it sound like you plan to drill with a low mud weight until the well starts Ʋowing, then weight up after circulating out a kick. Furie needs to plan to drill with mud weight > max anticipated pore pressure. From section 10: “A guiding philosophy will be that it is less risky to weight up a lower weight mud than be overbalanced and have the challenge to mitigate lost circulation while drilling ahead.” I see the pore pressure/frac gradient curve in section 31 also includes planned mud weight starting to increase above 10 ppg starting around 6700’ MD, but the procedure doesn’t reƲect that. I will add a comment on the procedure to follow the mud weight schedule on the PPFG chart, unless you plan to do something diƯerent. 37. Agree the mud weight should be at least .5 ppg higher than the formaƟon pressure. Thus, if we suspect we have a 10.2 ppg formaƟon, our mud weight should 10.7 ppg. Mud weight should be 9.5 – 10.7. Note that the exisƟng A-4 well was drilled with ~10.5 ppg mud without kicks or connecƟon gas at depths near the proposed TD of well A-4a. The A-4a BHL at TD is ~800 laterally distant from the original A-4 well at similar depths. We plan to have a mud logging team on site, along with a geologist to help monitor the pore pressure to ensure that the mud weight is heavier than the pore pressure by at least .5 ppg. Furie concurs with following a mud weight schedule. We can cross out the comment about it being less risky to weight up a lower weight mud, than be overbalanced. We concur with following the mud weight up schedule in Sec Ɵon 31. 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 SecƟon 20 There is mention about possibly drilling into the Tyonek in section 20, anticipated drilling hazards. If that is a possibility, what is the anticipated top depth and pressure? Do you anticipate that it could be full of oil or gas? There are no plans to drill into the Tyonek. The AnƟcipated Drilling Hazards secƟon was prepared by our drilling Ňuids company and is fairly generic. Drilling through the coals is the most important aspect we were concerned with. SecƟon 21 - We concur Mike & Bob, A couple of items regarding FIT/LOT procedure. 1. In step 5 in your FIT procedure (section 21), you should plot casing pressure vs. strokes (not drill pipe pressure). After you stop pumping, you plot casing pressure vs. time. 2. I suggest deleting the following statement because I don’t think it’s correct or necessary: “The pre-determined surface pressure for each formaƟon integrity test is based on achieving an EMW at least 1.0 ppg higher than the esƟmated reservoir pressure and allowing for an appropriate amount of kick tolerance in case well control measures are required.” I can make these changes if you agree. We can change step 5 to “On a graph, plot casing pressure vs Ňuid pumped (Volume – bbls or gallons). AŌer you stop pumping, plot casing pressure vs Ɵme. We can remove the last comment per your recommendaƟon. Mike Stefanov Drilling Manager Furie OperaƟng Alaska LLC Tel. +1 615 738 8596 E-Mail: m.stefanov@furiealaska.com Alternate E-Mail: mistefanov@my.lonestar.edu 433 W 9th Avenue Anchorage, AK 99501 From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Thursday, October 17, 2024 11:33 AM To: Mike Stefanov <m.stefanov@furiealaska.com> Cc: Bob Laule <b.laule@furiealaska.com> Subject: [EXT] KLU A-4A FIT procedure Mike & Bob, A couple of items regarding FIT/LOT procedure. 1. In step 5 in your FIT procedure (section 21), you should plot casing pressure vs. strokes (not drill pipe pressure). After you stop pumping, you plot casing pressure vs. time. 2. I suggest deleting the following statement because I don’t think it’s correct or necessary: 3 “The pre-determined surface pressure for each formaƟon integrity test is based on achieving an EMW at least 1.0 ppg higher than the esƟmated reservoir pressure and allowing for an appropriate amount of kick tolerance in case well control measures are required.” I can make these changes if you agree. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 ***External Email*** Confidentiality Notice: This email and its attachments (if any) contain confidential information of the sender. The information is intended only for use by the direct addressees of the original sender of this email. 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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. 224-075 KITCHEN LIGHTS KLU A-4A KITCHEN LIGHTS, STERLING UNDEFINED GAS - 470500 KITCHEN LIGHTS, BELUGA UNDEFINED GAS - 470510 WELL PERMIT CHECKLISTCompanyFurie Operating Alaska, LLCWell Name:KLU A-4AInitial Class/TypeDEV / PENDGeoArea820Unit11120On/Off ShoreOffProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2240750KITCHEN LIGHTS, STERL UND GAS - 470500 KITCHEN LIGHTS, BLUG UND GNA1 Permit fee attachedYes Surf Loc & Top Prod Int lie in ADL0389197; TD lies in ADL0398196.2 Lease number appropriateYes3 Unique well name and numberNo KITCHEN LIGHTS, STERLING UNDEFINED GAS - 4705004 Well located in a defined poolYes KITCHEN LIGHTS, BELUGA UNDEFINED GAS - 4705105 Well located proper distance from drilling unit boundaryNA6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 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) (For servNA15 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)NA Sidetrack18 Conductor string providedYes19 Surface casing protects all known USDWsNA Sidetrack20 CMT vol adequate to circulate on conductor & surf csgYes21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes24 Adequate tankage or reserve pitYes25 If a re-drill, has a 10-403 for abandonment been approvedYes26 Adequate wellbore separation proposedNA27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes29 BOPEs, do they meet regulationYes MPSP = 3763 psi, BOP rated to 5K (BOP test to 5000 psi initial, 4700 psi subsequent)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 has not been encountered in any nearby well; however, rig has monitoring equipment and35 Permit can be issued w/o hydrogen sulfide measuresYes sequestering agents will be onsite.36 Data presented on potential overpressure zonesNA Expected pressure range is 0.213 to 0.503 psi/ft (4.1 to 9.7 ppg EMW). Operator's planned mud program37 Seismic analysis of shallow gas zonesNA appears sufficient to control anticipated pressures and maintain wellbore stability.38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprADDDate10/22/2024ApprBJMDate10/21/2024ApprADDDate10/22/2024AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateJLC 10/23/2024 NA1 Permit fee attachedYes Surf Loc & Top Prod Int lie in ADL0389197; TD lies in ADL0398196.2 Lease number appropriateYes3 Unique well name and numberNo KITCHEN LIGHTS, STERLING UNDEFINED GAS - 4705004 Well located in a defined poolYes KITCHEN LIGHTS, BELUGA UNDEFINED GAS - 4705105 Well located proper distance from drilling unit boundaryNA6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 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) (For servNA15 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)NA Sidetrack18 Conductor string providedYes19 Surface casing protects all known USDWsNA Sidetrack20 CMT vol adequate to circulate on conductor & surf csgYes21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes24 Adequate tankage or reserve pitYes25 If a re-drill, has a 10-403 for abandonment been approvedYes26 Adequate wellbore separation proposedNA27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes29 BOPEs, do they meet regulationYes MPSP = 3763 psi, BOP rated to 5K (BOP test to 5000 psi initial, 4700 psi subsequent)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 has not been encountered in any nearby well; however, rig has monitoring equipment and35 Permit can be issued w/o hydrogen sulfide measuresYes sequestering agents will be onsite.36 Data presented on potential overpressure zonesNA Expected pressure range is 0.213 to 0.503 psi/ft (4.1 to 9.7 ppg EMW). Operator's planned mud program37 Seismic analysis of shallow gas zonesNA appears sufficient to control anticipated pressures and maintain wellbore stability.38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprADDDate10/22/2024ApprBJMDate10/21/2024ApprADDDate10/22/2024AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate*&: 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 Mike Stefanov Drilling Manager Furie Operating Alaska, LLC 433 W 9th Avenue Anchorage, Alaska 99501 Re: Kitchen Lights Unit, Undefined Beluga and Sterling Natural Gas Pools, KLU A-4A Furie Operating Alaska, LLC Permit to Drill Number: 224-075 Surface Location: 339' FSL, 891' FWL, Sec. 24, T10N, R11W, Seward Bottomhole Location: 1952' FSL, 1475' FWL, Sec. 19, T10N, R10W, Seward Dear Mr. Stefanov: 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, Brett W. Huber, Sr. Chair, Commissioner DATED this day of June 2024. Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2024.06.25 11:14:29 -08'00' 25th 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: 10,750' TVD: 7,836' 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): 107' 15. Distance to Nearest Well Open Surface: x-294325.85 y- 2536121.20 Zone- 4 to Same Pool: See attachments 16. Deviated wells: Kickoff depth: 3,752 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 57.61 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 6.75" 3.5" 9.2# L-80 JFE Lion 7,100' 3,650' 3,392' 10750' 7,836' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): TVD 365' 2,154' 7,451' 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: Mike Stefanov Mike Stefanov Contact Email:m.stefanov@furiealaska.com Drilling Manager Contact Phone:(615) 738-8596 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 KLU A-4A Kitchen Lights Unit Undefined Beluga and Sterling Natural Gas Pools August 15th, 2024 3+ miles to non-Furie property Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. 8,481'9-5/8" Total Depth MD (ft): Total Depth TVD (ft): 402-081A STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 Tail: 85 bbl 15.3 lb/gal 3,338 psi 304' FSL, 2119' FWL, Sec. 24, T10N, R11W, Seward 1952' FSL, 1475' FWL, Sec. 19, T10N, R10W, Seward 433 W. 9th Avenue, Anchorage, AK 99501 Furie Operating Alaska, LLC 339' FSL, 891' FWL, Sec. 24, T10N, R11W, Seward ADL 389197, ADL 389196 2,560 18. Casing Program:Top - Setting Depth - BottomSpecifications 3,750 psi GL / BF Elevation above MSL (ft): Plugs (measured): (including stage data) Lead 1: 50 bbl 13 lb/gal Lead 2: 167 bbl 13 lb/gal Authorized Signature: Stage 1: 205.8 bbl, Stage 2: 268.8 bbl Production Liner 8,423' Intermediate Authorized Name: See attached well schematic Conductor/Structural 20"304' Authorized Title: LengthCasing Size See attached well schematic Driven 365' 2,154'Lead: 300 bbl,Tail: 94.3 bbl Effect. Depth MD (ft): Effect. Depth TVD (ft): Cement Volume MD 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):Perforation Depth MD (ft): 2,022' 13-3/8" s N ype of W L l R L 1b S Class: Noq'ddd: Yes s No eess:Yes q o DDrill tssss Se issss tssss T DDrill Dril Se A N well is .005 S S S S S s No q'ddd: Yes N y E S s No s KLU A-4A 10-401 Form Page 1 Mike Stefanov Drilling Manager ssion Use Only By Grace Christianson at 12:46 pm, May 31, 2024 DSR-6/4/24 Initial BOP test to 5000 psi, subsequent tests to 4700 psi. All annular tests to 2500 psi. BJM 6/24/24 224-075 50-733-20682-01-00 Submit FIT/LOT results within 48 hrs of obtaining data. Submit CBL log within 48 hrs of obtaining log. Subsea sonar survey and email attached. SFD 6/20/2024*&:JLC 6/25/2024 Brett W. Huber, Sr.Digitally signed by Brett W. Huber, Sr. Date: 2024.06.25 11:14:49 -08'00'06/25/24 06/25/24 x RBDMS JSB 062624 1 May 31, 2024 Bryan McLellan Sr. Petroleum Engineer Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Re: Furie Operating Alaska KLU A-4 ST Permit to Drill (10-401) Submittal Mr. McLellan, Please see attached application for the permit to drill the above referenced well. Well KLU A-4 is planned to be sidetracked to access alternative Sterling and Beluga formation production. The well will be completed with a 3-1/2” gas lift tie-back completion. Separate sundry notices will be submitted for the KLU A-4 plug back and perforating operations. Drilling operations are expected to commence approximately August 2024. Regards, Mike Stefanov Drilling Manager Furie Operating Alaska, LLC 3 KLU A-4A Permit to Drill (10-401) Julius R Platform May 31 st, 2024 4 Contents 1. Well Information...........................................................................................................................................5 2. Tubular Program ...........................................................................................................................................5 3. Drill Pipe Information....................................................................................................................................5 4. Current Wellbore Schematic..........................................................................................................................6 5. Pre-Sidetrack Schematic................................................................................................................................7 6. Planned Wellbore Schematic.........................................................................................................................8 7. Drilling Summary...........................................................................................................................................9 8. Mandatory Regulatory Compliance / Notifications......................................................................................11 9. BOP N/U and Test........................................................................................................................................12 10. 6.75" Production hole mud program summary:...........................................................................................13 11. Make Up the Baker Mechanical Set Whipstock. ..........................................................................................13 12. Mill Window Plus 30' of New Hole ..............................................................................................................15 13. Drill 6.75” Hole Section................................................................................................................................16 14. Run 3-1/2” Production Liner........................................................................................................................19 15. Cement 3-1/2” Production Liner..................................................................................................................21 16. Run 3-1/2" Upper Completion Assembly.....................................................................................................24 17. Run Cement Bond Log.................................................................................................................................25 18. ND BOPE/RDMO..........................................................................................................................................25 19. Anticipated Drilling Hazards........................................................................................................................26 20. FIT Procedure..............................................................................................................................................28 21. BOP Schematic ............................................................................................................................................29 22. Choke Manifold Schematic.........................................................................................................................29 23. Wellhead Schematic (Current).....................................................................................................................32 24. Time vs. Depth Plot .....................................................................................................................................33 25. Property Plat...............................................................................................................................................34 26. Rig Information ...........................................................................................................................................35 27. Casing Design Information...........................................................................................................................38 28. 6-3/4” Hole Section for MASP .....................................................................................................................39 29. Permit to Drill Kick Tolerance Evaluation.....................................................................................................39 30. KLU A-4 Pore Pressure/Frac Gradient..........................................................................................................41 31. KLU A-4A Directional Program (wp12).........................................................................................................42 32. KLU A-4A Fluid Program ..............................................................................................................................55 5 1. Well Information Well Name KLU A-4A Drilling Rig Enterprise 151 Slot Name Slot C (KLU A-4) Directional Plan wp12 Pad and Old Well Designation Sidetrack of existing KLU A-4 (PTD: 218-069) Planned Completion Type 3-1/2” monobore w/ GLM Target Reservoirs Sterling/Beluga Kick Off Point +/- 3,713’ MD (wp12), Set WS anchor at 3,732’ MD Planned Well TD, MD/TVD 10,754 MD/7,836’ TVD Surface Location (Governmental) 339’ FSL, 891’ FWL, Sec. 24, T10N, R11W, SM Surface Location (NAD 27) X=294325.85, Y=2536121.2 AFE Number 24-04ST AFE Days 30 Work String 4.5” Delta 425 16.60# RT – Mean Sea Level (MSL) 144.10 ft RT – Mud Line (ML) 232.10 ft RA Tag 3,698’ MD Water Depth Tidal Difference - +/- 20’ 88.00’ ft 2. Tubular Program Hole Section OD WT (#/ft) Couple OD ID (in)Drift (in)Grade Conn Top Bottom 6.75” 3.5” 9.2 3.96” 2.949” 2.867” L-80 JFE LION Surface 10,750’ **Minimum of 100’ overlap required between casing strings 3. Drill Pipe Information Hole Section OD ID TJ ID TJ OD WT (#/ft)Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) 6.75” 4.5” 3.826 3.0 5.25 16.6 S-135 Delta 425 17690 16800 468 AFFECTED POOLS: KITCHEN LIGHTS, STERLING UNDEFINED GAS - 470500 KITCHEN LIGHTS, BELUGA UNDEFINED GAS - 470510 SFD 6 4. Current Wellbore Schematic 7 5. Pre-Sidetrack Schematic 8 6. Planned Wellbore Schematic 9 7. Drilling Summary KLU A-4 at the time this program is being prepared, is producing a limited amount of gas in the Beluga in the range of 1 MMSCFD of gas. The well is planned to be sidetracked to targets in the Beluga and Sterling formations. Except for limited production in the Beluga, the production intervals of KLU A-4 have been abandoned. A cement retainer will be set at 3,732’ MD which is 138’ above top of the packer at 3,870’ and 115 bbl of cement will be squeezed in the Sterling and Beluga perforations. The casing and the retainer will be tested to 4,200 psi. The parent wellbore will be sidetracked, and new wellbore drilled to 10,750’ MD. A 3.5” L-80 9.2# JFE Lion production liner will be run, cemented, and perforated based on data obtained while drilling the interval. The well will be completed with a 3-1/2” gas lift upper completion tied-back to the 3-1/2” lower completion. Drilling operations are expected to commence approximately August 2024. General sequence of operations pertaining to this drilling operation conducted under 10-401 Sundry: 1. Run 9-5/8” casing scraper to top of retainer. CBU. 2. RIH and set 9-5/8” whipstock anchor at 3,732’ MD and 30 L deg. Displace well to 9.5-10 ppg LSND mud. 3. Mill window and 30’ of new formation. 4. Perform FIT to 14 ppg EMW. POH. 5. PU 6.75” cleanout drilling assembly and TIH to the 9-5/8” window. Drill enough hole to bury MWD/LWD BHA assembly, which will be about 210’. Circulate until returns are free of metal cuttings. Anticipate about 300# of steel cuttings. POOH. 6. Drill 6.75” production hole to 10,750’ MD, performing short trips as needed. 7. Condition mud. 8. POOH. Conduct Geo-Tap surveys as dictated by the G&G team. 9. RIH for wiper trip to TD. 10. Condition mud. POOH. 11. RIH with 3-1/2” liner. Set liner, pump cement. and set liner top packer. 12. Perform liner lap test to 3,500 psi. 13. Perform polish mill and scraper run to dress top of PBR. 14. Pull wear bushing. 15. Install upper 3-1/2” completion with GLM’s. 16. Space out and land tubing hanger and test. Plug for redrill activity is approved under sundry 324-217. 10 17. Perform CBL via E-Line. 18. Sequentially perforate selected Beluga intervals as per G&G team. 19. ND BOPE, NU tree and test. 11 8. Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. x BOPs shall be tested at 2-week intervals during drilling and at 1 week intervals during abandonment operations. Ensure to provide AOGCC 48 hours’ notice prior to testing BOPs. x The initial test of BOP equipment will be to 250/5,000 psi and subsequent tests of BOP equipment will be to 250/4,700 psi for 5/5 min (annular to 50% rated WP, 2,500 psi on the high test for initial and subsequent tests). o Confirm that these pressures match those specified on the APD. o The highest reservoir pressure expected is 3,750 psi in the Beluga lower sand (7,500’ TVD). MASP (MPSP) is 3,338 psi with 0.055 psi/ft gas in the wellbore. o A casing test to 4,200 psi is planned as part of the pre rig work. o Pressure test Mechanical Integrity Test Inner Annulus (MITIA) to 3,500 psi, which is greater than the MPSP (MASP) of 3,338 psi. x Minimum required Rated Working Pressure (RWP) of the BOPE and wellhead must exceed: 3,700 psi. The wellhead and BOPE system will be rated to 5,000 psi. x If the BOP is used to shut in on the well in a well control situation, ALL BOP components utilized for well control must be tested prior to the next trip into the wellbore. This pressure test will be charted same as the 14-day BOP test. x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid system”. x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements” x Review all conditions of approval of the PTD on 10-401 form. Ensure that the conditions of approval are captured in shift handover notes until they are executed and complied with. x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. 12 Required AOGCC Notifications: x Well control event (BOPs utilized to shut in the well to control influx of formation fluids). x 48-hour notice prior to full BOPE test. x Any other notifications required in APD conditions of approval. AOGCC Contact Information: x Jim Regg / AOGCC Inspector/ (O): 907-793-1236 / Email: jim.regg@alaska.gov x Bryan McLellan / Petroleum Engineer/ (O): 907-793-1226 / (C): 907-250-9193 / Email: bryan.mclellan@alaska.gov x Melvin Rixse / Petroleum Engineer/ (O): 907-793-1231 Email: melvin.rixse@alaska.gov Primary Contact for Opportunity to Witness: x Test/Inspection notification standardization format: Test Witness Notification - Alaska Oil and Gas Conservation Commission (state.ak.us) x Notification/ Emergency Phone: 907-793-1236 (During normal Business Hours) x Notification/ Emergency Phone: 907-659-2714 (Outside normal Business Hours) 9. BOP N/U and Test 1. N/D Tree master valve and adapter (BPV installed as part of pre-rig work), inspect landing threads in tubing hanger. Make dummy run to check threads. Install plug off tool. 2. Check the full drift of any spacer spools used several days prior to installation. 3. N/U to 13-5/8" 5M X 13-5/8” 10M spool. 4. N/U 13-5/8" x 10M BOP as follows (top down): o 13-5/8" x 5M Shaffer spherical annular BOP. o 13-5/8" Cameron Type "U" Double ram. (2-7/8" X 5" VBR in top cavity, blind ram in bottom cavity). o 13-5/8" mud cross. o 13-5/8" Cameron Type "U" single ram. (2-7/8" X 5" VBR). o N/U bell nipple, install flowline. o Install (2) manual valves on kill side of mud cross. Manual valve used as inside or "master valve". 13 o Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. 5. Test BOPE. o Test BOP to 250/5,000 psi for 5/5 min. Test annular to 250/2,500 psi for 5/5 min. o Ensure to leave "A" section side outlet valves open during BOP testing so pressure does not build up beneath the back pressure valve with plug off tool. Confirm the correct valves are opened!!! o Test VBRs on 4.5" test joint (5,000 psi) See attached permit to drill. o Test Annular on 4.5" test joint (2,500 psi). o Ensure gas monitors are calibrated and tested in conjunction w/ BOPE. 10.6.75" Production hole mud program summary: o Primary weighting material to be used for the hole section will be barite to minimize solids. Ensure enough barite is on location to weight up the active system 1ppg above highest anticipated MW in the event of a well control situation. o Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, and Toolpusher office and mudlogging unit if on rig. o Program mud weights are generated by reviewing data from producing & shut-in offset wells, estimated BHP's from formations capable of producing fluids or gas and formations which could require mud weights for hole stabilization. o A guiding philosophy will be that it is less risky to weight up a lower weight mud than be overbalanced and have the challenge to mitigate lost circulation while drilling ahead. 11.Make Up the Baker Mechanical Set Whipstock. x A bond log and CCL has been recorded over the whipstock anchor setting depth of 3,730’ MD. o RA tag at 3,698’ MD. o 3,700’ – 3,740’ MD looks like good cement. (Per SLB) o Joint 99 - 3,697’ – 3,738’ MD. o Set plug as close to bottom as possible. 14 x Anticipated metal cuttings from window will be about 300 lbs. x Baker to provide ditch magnets/string magnets (4). x Weight of 20,000 lbs to be set on the retainer. o Anchor pinned, ~15K to set. Verify 15K can be set with no movement x The whipstock should be set closer to bottom of casing connection. Check pipe tally and space out. (WS Anchor 3,732’ MD and collar at 3,738’ MD) x NOTE the 9-5/8” casing was run with one centralizer per joint. x The whipstock run will be made with an MWD survey. x Simulation Run BHA: o 8-1/2” Bit\Bit Sub\Full Size Watermelon Mill\Scraper\4-3/4” Drill Collar \full drift stabilizer\HWDP\ Jars o Baker 4.5” IF connections 6. Optional: Run wireline gauge ring in lieu of casing scraper run to verify all SS bands are pushed to bottom. 7. RIH with Simulation run and tag cement retainer at 3,732’ MD. 8. Reciprocate the assembly across the whipstock setting depth. o Note any tight spots during this operation and advise Drilling Manager and Drilling Engineer in Anchorage 9. Circulate bottoms up, to ensure the hole is clean. 10. POOH with Simulation BHA. 11. Make up the Whipstock assembly in the rotary, using the whipstock handling bar. o Lower Whipstock BHA: TorqueMaster mechanical set anchor\WindowMaster Whipstock o Upper Whipstock Milling Assembly: Window Mill\Lower Watermelon mill\flex joint\ Upper Watermelon mill\Float Sub\XO\MWD tool\HWDP(s)\Drill Pipe 12. Install the milling assembly. 13. Remove the whipstock handling bar, RIH and set the slips on the Drill Collar above the upper watermelon mill. 14. Pick up the MWD assembly. 15 o Measure and record MWD tool face from the scribed line from the whipstock shear stud. This will ensure the alignment of the whipstock. 15. Hold a pre-trip meeting with the drilling crew, directional driller, and Baker whipstock hand etc. 16. Run string at 2 to 3 minutes per stand. 17. Take care running assembly through the BOPs and other potentially tight spots. 18. TIH with string to the whipstock. Shallow test the MWD. 19. TIH with DP to the whipstock anchor setting depth at 3,730’ MD. Exercise caution when RIH and setting slips with whipstock assembly. 20. Fill the drill pipe a minimum of every 10 stands on the trip in the hole with the whipstock assembly. o These precautions are required to avoid any weakening of the whipstock shear mechanisms and/ or to avoid parting/ presetting of the packer. 21. Orient whipstock as directed by the directional driller. The directional plan specifies 30 deg LOHS. o Orient at least 30’ - 90’ above retainer. 22. Set the top of the whipstock at 3,713’ MD.WS anchor at 3,730’ MD. o 13-3/8” 68# L-80 surface casing set at 2,172’ MD. o 9-5/8" 47# L-80 production casing run from surface to 8,482’ MD. o Ref log: FURIE-KLU_A1_IBC-CBL-GR-CCL_ 4 Oct 2018 12.Mill Window Plus 30' of New Hole (DO NOT EXCEED 50' OF NEW HOLE BEFORE RUNNING THE PLANNED FIT) 23. Use ditch magnets (Baker) to collect the metal shavings. Clean regularly. 24. Ensure any personnel working around metal shavings wear proper PPE, including goggles, face shield and Kevlar gloves. 25. Work the upper mill through the window to confirm the window milling is complete and circulate well clean (circulate a minimum of 1-1/2 bottoms up). 16 26. Pump a high-vis sweep to remove metal shavings and make every effort to remove all of the hi-vis sweep from the mud system as it is circulated to surface. o Pump sweep every 3-5 feet (10-15 bbls). 27. Condition mud. 28. Pull starter mill into casing above top of whipstock, flow check the well for 10 minutes and conduct a FIT to 14 ppg. Any FIT greater than 13 ppg is sufficient to continue operations. o Baker recommends 30’ of open hole to get upper watermelon mill through window. o **Assuming the kick zone is at TD, a FIT of 14 ppg EMW gives a Kick Tolerance volume of 11.87 bbls with 10 ppg mud weight, with a kick intensity of 2.7 ppg. o Monitor 9-5/8 x 13-3/8” annulus during FIT and report any change in pressure. o Contact AOGCC to witness FIT 48 hours in advance. Submit FIT results to AOGCC. 29. POOH and LD milling assembly. o Flow check well for 10 minutes to confirm no flow: Before pulling off bottom. Before pulling the BHA through the BOPE. 30. Once out of the hole, inspect mill gauge and record. Record weight of milled cuttings recovered. If upper watermelon mill is more than 1/8” under gauge, PU second set of mills (polish BHA). 31. Flush the stack/lines to remove metal debris that may have settled out in these areas. Ensure BOP equipment is operable. 32. At least one Baker hand to stay on location until milling BHA is pulled out of window and is laid down and drilling and logging assembly is run through the window. 13.Drill 6.75” Hole Section 33. PU 11,000’ of 4.5" Delta 425 drill pipe for drilling 6.75" hole section. 34. P/U 4.75" Sperry motor with a 1.5 degree bend and drilling cleanout assembly, with no logging tools. 35. Drill ~230’ to have sufficient hole to bury MWD/LWD BHA (length determined by total length of logging tools) with this assembly to ensure hole is clean. 36. POOH and pick up MWD/LWD BHA. 17 37. TIH. Clear the rig floor while installing nuclear sources in the Density (ALD) and Neutron (CTN) tools Shallow test MWD/LWD on trip in. Ensure Sperry MWD/LWD service rep on rig floor during this operation. Fill pipe every 10 stands while running in the hole. 38. Circulate well with 10 ppg LSND to warm up mud until good 9.5-10 ppg in and out. 39. Drill 6.75" hole to 10,750' MD using (see BHA attachment). o Plan to run triple combo (DENSITY, POROSITY, RESISTIVITY).+Sonic and Geotap tool. Motor bend of 1.15 to 1.5 deg. Plan to acquire pressures with Geotap tool after reaching TD, while tripping out. TIH, circulate until clean, TOH. If any stickiness may need to backream some intervals. Preferred option is to drill to stand down, then mad pass each stand to acquire density data; this allows earlier acquisition of density data to identify sands for Geotap pressure measurements. Short trips every 600’ to 1000’. Use caution backreaming due to fragile coals. o Top of the Sterling is anticipated to be 3,721’ MD RKB. o Top of the Beluga is anticipated to be 6,845’ MD RKB. o No major anticipated faults expected to be encountered. o Pump sweeps and maintain mud rheology to ensure effective hole cleaning. o Utilize Inlet experience to drill through coal seams efficiently. Coal seam log will be provided by Geo team, try to avoid sliding through coal seams. Work through coal seams once drilled. o Keep swab and surge pressures low when tripping. Minimize the number of short trips unless wellbore problems such as torque, pickup/slackoff increases. o Ensure solids control equipment is functioning properly and utilized to keep LGS to a minimum without excessive dilution. o Adjust MW as necessary to maintain hole stability. o Ensure mud engineer set up to perform HTHP fluid loss. o Maintain API fluid loss < 6 ml/30 minutes. HPHT < 11 ml/30 minutes at 200° o Ensure Low Gravity Solids (LGS) are maintained at less than 6 %. o Take MWD surveys every stand drilled. o Minimize backreaming when working tight hole. o Drilling fluid Use thicker, more viscous milling fluid for window milling. Thin it back for drilling below the casing window with same fluid. 18 Drilling/milling fluids have to be approved for discharge. Any different additives have to be approved for discharge prior to use. Additives include KCl, amine salt, etc. for inhibition. Inhibited polymer mud, seawater based. Review Baroid provided coal drilling recommendations. Mud will include LCM in recipe. o Directional drilling Run a stabilizer right above the motor to prevent hole angle building more than desired. Stay within 100’ radius of directional plan. Control drill at 40-60 ft/hr if losses encountered. Non fibrous LCM limited to no more than 40 lb/bbl. o Sonic tool 250-280 gpm desirable range for logging tools. Typically have a float in motor, to be provided by directional company . Turbine in logging tools generates power while circulating for LWD\MWD tools. Battery is primarily a back up power source when not circulating. o Bits GTD54DM primary, GT64D backup recommended x (5 and 6 refer to number of blades, 5 blade has larger junk slots for coals and clays) WOB 6-10 Klbs, up to 15K+ lbs if needed. RPM 240-380 total bit RPM, string rpm between 50 to 70. Cutters on back of blades to allow for backreaming if desired. Optimize bit weight and rotation to minimize vibration on logging tool. o Electric line/Slickline Pipe recovery will be prepared for as needed. Unit available that can be used for slickline on platform. Different diameters of E-Line available. o Cementing - Centralizers Use stop collars on shoe track to keep centralizers in place. Centralizers may be free floating on rest of liner or can use stop collars. Slip on type, as opposed to clamp on. Bridgemaker with multiple types and particle sizes of LCM will be added to the tail end of the lead cement slurry to cure losses. Bridgemaker will be mixed with the bulk cement at the bulk plant and sent to rig. 19 40. At TD pump a sweep and a marker, to be used as a fluid caliper to determine annular volume for cement calculations. CBU and pull a short trip back to the window back to TD. 41. TOH with drilling assembly, handle BHA as appropriate. 14.Run 3-1/2” Production Liner 42. The float shoe, float collar and landing collar should be premade up with thread lock compound, prior to shipment to the rig. Prepare and rack back the liner cement head (Halliburton). 43. Note the liner hanger and running tool have been pre-made up at the Frontier facility in Houston. 44. R/U 3-1/2" liner running equipment including torque turn equipment (Parker) for JFE Lion 3-1/2” 9.2# L-80 tubing. 45. P/U shoe joint, visually verify no debris inside joint. 46. Continue to M/U and thread lock shoe track assembly consisting of float shoe, three joints of tubing, and float collar joint. 47. Continue running 3-1/2" production liner in the hole. 48. RIH w/ liner no faster than 30 seconds per joint. Watch displacement carefully to avoid surging the hole. Slow down running speed if necessary, to minimize surge pressures and chances of losing circulation. 49. Fill pipe while lowering string every 10 joints. 50. Set string slowly in and pull slowly out of slips. 51. Circulate 1-1/2 string volumes at the 9-5/8” casing window prior to going into open hole. Stage pumps up slowly and monitor for losses. Do not exceed 60 % of the nominal liner hanger setting pressure of 1,544 psi, which is roughly 1,000 psi. 52. Obtain up and down weights of the liner before entering open hole. 53. Run enough liner to provide at least 100' overlap inside casing. Ensure setting sleeve will not be set in a connection. 20 54. Before picking up liner hanger/ packer assembly, count the number of joints on the pipe deck to make sure it coincides with the pipe tally. 55. M/U liner hanger and top packer assembly. Fill liner tieback sleeve with viscous mud, that is thin enough to travel past the running tool down to the packoff. 56. RIH one stand and circulate a minimum of one string volume. Note weight of liner. 57. Check to see that the liner shoe is opposite a competent formation before circulating based on LWD logs. Consider reciprocating liner to prevent washout as shoe is in open hole. 58. Record weight of liner. This is the approximate weight to be lost when hanger is set. 59. Continue to fill the string every 10 stands while running liner. Do not stop to fill casing. 60. PU the cement stand and tag bottom with the liner shoe. PU 10' off bottom. Note slack-off and pick-up weights. 61. Stage pump rates up slowly to circulating rate without exceeding 60% of the liner hanger setting pressure of 1,544 psi. Circ and condition mud with the liner on bottom. Reduce the low-end rheology of the drilling fluid by adding water and thinners. 62. Reciprocate if hole conditions allow. Circ until hole and mud is in good condition for cementing. 63. Set liner 10-15’ off bottom. 64. Release 1.125” setting ball from the liner cement head and displace at 1-3 bbl/min. Pressure up to 1,544 psi to shear the hanger cylinder, hold pressure for one minute. Set the liner hanger slips by slacking off 30 K lbs. Bleed off pressure. 65. For setting the hanger, hold hanger running tool in compression. Pressure up to 2,520 psi to shear setting tool and hold pressure for 2 minutes. Bleed off to 500 psi and pick up to release the running tool. Do not pick up more than 4 feet to ensure that the liner hanger packer is not set. If running tool does not release, 21 pressure up to 2,750 psi, 3,000 psi and 3,200 psi. After each try to confirm release. If running tool does not hydraulically release, it can be mechanically released. Rotate string to the left ¼ turn at tool with 2,550 ft-lbs of torque. After rotation shear, then set down 16,200 lbs to shear. Tool will then be released. 66. Set back down 20K lbs. Pressure up to 3,668 psi to shear out ball seat. 67. Proceed pre-cement job circulation and cement job. 15.Cement 3-1/2” Production Liner 68. Hold a pre-job safety meeting for the upcoming cementing operations. 69. Pump 5 bbls of fresh water. 70. Test surface cement lines to 4,500 psi. 71. Pump 60 bbls 12.0 ppg spacer. 72. Mix and pump 50 bbls of lead cement without bridgemaker LCM (Interval 6,750 to 3,632’ MD), followed by 167 bbls of lead slurry with 5 lb/bbl bridge maker lost circulation material (Interval 6,750’ to 9,000’ MD), and a tail slurry of 85 bbls of 15.3 ppg tail cement (Interval 9,000’ to 10,750’ MD). Verify cement volume with actual inputs. Ensure cement is pumped at designed weight, using a pressurized mud balance. Job is designed to pump 40 % OH excess (based on caliper), but if wellbore conditions dictate otherwise decrease or increase excess volumes. Ensure cement with Bridgemaker does not make it to liner top. Cement volume is designed to bring cement to TOL. 73. Displacement fluid will be clean drilling mud. Program displacement is estimated at 110 bbls (Drill pipe and liner). Please independently verify with actual inputs. 74. Pump cement at max rate of 5 bpm maximum, monitor pump pressures. Reduce pump rate to 3 bpm prior to latching DP dart into liner wiper plug. Note plug departure from liner hanger running tool and resume pumping at full displacement rate. Displacement volume can be re-zeroed at this point. Drill pipe displacement is about 47.9 bbl (3,632’ X .0132 bbl/ft) and liner displacement is tail slurry of 85 bbls of 15.3 ppg tail cement (Interval 9,000’ to 10,750’ MD). followed by 167 bbls of lead slurry with 5 lb/bbl bridge makerSee attached email with corrected cement volumes. -BJM pump 50 bbls of lead cement without bridgemaker LCM 22 61.92 bbls.(7,118’*.008699 bbl/ft). Follow cement with 10 bbls freshwater, 45 bbls mud and 30 bbls spacer and 25 bbls mud behind to bump the plug. This will place spacer across the liner top. 75. Monitor returns & pressure closely while circulating. Notify Well Site Supervisor immediately of any changes. Reduce pump rate as required to avoid packoff. 76. Do not over displace by more than 5 bbls = 154’ of liner X OH volume. Review this value based on lowest possible perf interval. Current estimate for Beluga BL1 upper is 10,428’ MD 7,580’ (10,750-310=10,440’). Lead #1: No LCM System SBM CEM ECONOCEM Density 13 lb/gal Design Volume 50 bbls Yield 1.85 ft3/sk Mixed Water 10.15 gal/sk Expected Thickening 5-7 hrs API Fluid Loss < 100 Additives Code Description Concentration Type I/II Halad 344 HR-5 D-Air 5000 SA-1015 Cement Fluid Loss Retarder Defoamer Suspension Aid 94 lbs/sk 0.4 % 0.3 % 0.2 % 0.125 % 23 Lead #2: Bridgemaker LCM System SBM CEM ECONOCEM Density 13 lb/gal Design Volume 167 bbls Yield 1.87 ft3/sk Mixed Water 10.21 gal/sk Expected Thickening 5-7 hrs API Fluid Loss < 100 Additives Code Description Concentration Type I/II Halad 344 HR-5 D-Air 5000 SA-1015 BridgeMaker II Cement Fluid Loss Retarder Defoamer Suspension Aid LCM 94 lbs/sk 0.4 % 0.3 % 0.2 % 0.125 % 5 lb/bbl Tail System SBM CEM VERSACEM TAIL Density 15.3 lb/gal Design Volume 85 bbls Yield 1.24 ft3/sk Mixed Water 5.57 gal/sk Expected Thickening 4-5 hrs API Fluid Loss < 100 Additives Code Description Concentration Type I/II Halad 344 HR-5 CFR-3 FDP-C1446-21 Cement Fluid Loss Retarder Dispersant Gelation inhibitor 94 lbs/sk 0.3 % 0.35 % 0.3 % 0.3 % 77. Bleed pressure to zero to check float equipment. 78. Pick up to release liner running tool and set packer. 79. To set packer. PU to neutral weight. Pick up a minimum of 9 feet, maximum of 11 feet. This will release Setting Dogs. Slack off 50K to shear packer setting pins with 24 30,240 lbs. Set down stoke should be only a few feet. If it strokes fully back down, the Setting Dogs did not release outside of Tie Back Receptacle. Pick up 2 feet further than prior pick up and slack off again. 80. Circulate surface to surface to remove any spacer and cement. 81. Test packer by pressuring down the backside 3,500 psi for 30 minutes. Record test on chart recorder. 82. Bleed off pressure. Slack off to neutral to weight. 83. Circulate well. 84. Pick up lower PBR polish mill and 9-5/8” casing scraper assy and RIH to liner top CBU. Change over to inhibited sea water. POOH. o Note: Caliper OD’s and ID’S and strap all components going below the rotary. We need to have fishing dimensions and sketches for anything that goes below the rotary. 85. Be sure to have rabbits for all tubulars used in the completion. 86. Rabbit 3-1/2” as picked up and get good strap. Only one rabbit on the floor and nothing rabbited near the rotary. 87. Optional: Slickline run with gauge ring to total depth. 16.Run 3-1/2" Upper Completion Assembly 88. Confirm the GLM’s, chemical injection mandrel, and SSSV are stenciled as being dummied off. Ensure seal assembly has been redressed and is on site. 89. MU seal stem assembly install standing valve in X nipple. 90. RIH dry to provide underbalance for perforating. 91. RU torque turn equipment for JFE Lion 3-1/2” 9.2# L-80 connection specification. 92. MU 3-1/2” 9.2 #L-80 monobore completion with GLM’s, chemical injection mandrel, SSSV and seal stem. RIH while spooling chemical and control lines. Make up control lines and test at 5,000 psi after connections are made. Maintain 2,500 psi pressure on chemical injection line and SSSV control line while running. Establish space out. 25 93. PU and space out. Set down 10K. Mark pipe to establish space out pup requirements. Pressure Inner Annulus (3-1/2”x9-5/8”) to 2,500 psi to confirm seal engagement. 94. PU install space out pups one joint below tubing hanger. 95. Terminate control lines and tie into tubing hanger. PT control lines to 5,000 psi. 96. Install ¼” Swagelok fitting and ¼ turn valve. Pressure up to 5,000 psi and lock in pressure to keep SSSV open while landing the tubing hanger. 97. Land tubing hanger. Test SSSV control line and chemical injection line at 5,000 psi. 98. PT annulus to 3,500 psi per AOGCC requirement and record on chart for 15 minutes. 17. Run Cement Bond Log 99. Recover standing valve from X-nipple. 100. Contact Halliburton cementer for impedance value for the cement versus time. 101. R/U E-line and run 1-11/16”CBL. Put log on depth tying into the original open hole log dated October 4, 2018. 18. ND BOPE/RDMO 102. Install BPV. 103. ND 13-5/8” BOP. Install plug off tool in BPV. 104. Confirm correct orientation of flow cross prior to tightening studs and nuts. NU and pressure test 4-1/16” 5K tree to 5000 psi. 105. Retrieve BPV and plug off tool. 106. Release to Production. Submit CBL to AOGCC within 48 hrs of obtaining log. -bjm 26 19.Anticipated Drilling Hazards Lost Circulation: Drilling depleted reservoir may cause loss circulation events x Maintain sufficient mud volumes while drilling. x Maintain ability to take on fresh water during drilling phase x If a LC event occurs pumping cement will be the last resort Ensure 500 lbs. of medium/coarse fibrous material, 500 lbs. SteelSeal (Angular, dual- composition carbon-based material), & 500 lbs. different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. No LC events occurred during the original drilling of KLU A1 x KLU A2/A2A: Lost circulation in production with a loss rate of 120bph. Losses cured with 30ppb LCM sweeps. x KLU A-4: Lost circulation in Production hole with a loss rate of 105bph. Losses cured with 16ppb LCM sweeps o 6,282’ MD Well Control: x Prior to drilling into the Sterling, Beluga, and Tyonek (if any), hold a pre-reservoir meeting to outline heightened awareness for kick detection and lost circulation. x Following any Tyonek formation penetration, pick up off bottom, shut off the pumps and perform a flow check to verify there isn’t any overpressure. x Review Kick tolerance based on actual FIT data. Hydrates and Shallow gas x No hydrates are expected in this area. x No H2S are expected in this area. x Ensure H2S monitoring equipment as specified in 20 AAC 25.065(1) will be functioning on the rig as standard operating procedure. x Ensure products for treating H2S contamination in the drilling mud system will be maintained on the rig. 27 Hole Cleaning: Maintain rheology w/ viscofier as necessary. Sweep hole w/ 20 bbls vicious pill as necessary. Optimize solids control equipment to maintain density and minimize sand content. Maintain programmed mud specs. Recommended flow rate in 6.75” hole is 200 to 330 GPM. The wellbore will be cleaned with a low vis(water), hi vis weighted sweeps. Monitor returns closely for signs of gas and circulate out all gas cut mud before continuing drilling. Anticollision: No close approaches. See directional plan for anticollision analysis. Coal Drilling: The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The need for good planning and drilling practices is also emphasized as a key component for success. x Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. x Use asphalt-type additives to further stabilize coal seams. x Increase fluid density as required to control running coals. x Emphasize good hole cleaning through hydraulics, ROP and system rheology. x Minimize swab and surge pressures. x Minimize back reaming through coals when possible. x Once in a coal seam, maintain the hydraulic pump pressure and GPM until the bit has been reamed back up and is out of the coal seam, EVEN IF MUD LOSSES ARE EXPERIENCED. Then observe the well and the hydraulics “may” need to be reduced to keep from losing circulation and causing the coals to water wet, which may create sloughing problem in the coals, utilizing the water loss additives and asphaltenes to combat the water wetting aspects. Lost circulation materials (a combination of various sizes of calcium carbonates) should be utilized initially. 28 20.FIT Procedure Procedure for FIT: 1. Drill 30' of new formation below the casing window. 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. Add casing pressure test data to graph if recent and available. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in I-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure and allowing for an appropriate amount of kick tolerance in case well control measures are required. 29 21.BOP Schematic 22.Choke Manifold Schematic 30 31 32 23.Wellhead Schematic (Current) 3324.Time vs. Depth Plot 3425.Property Plat 35 26.Rig Information 36 37 38 27.Casing Design Information Hole Size: 6.75” Mud Density: 10 ppg Planned Top: 3,630’ MD/ 3,378’ TVD Planned TD: 10,754’ MD/ 7,836’ TVD MASP: 3,338 psi (see attached MASP determination and calculation) Collapse Calculation: Normal gradient external stress (0.431 psi/ft) and the casing evacuated for the internal stress. Gas Gradient: 0.055 psi/ft Calculation/Specification Casing OD 3.5” Top (MD) 3,630’ MD Top of Liner Top (TVD) 3,378’ TVD Top of liner Bottom (MD) 10,754’ Bottom (TVD) 7,832’ Length 7,124’ Weight (ppf) 9.2 Grade L-80 Connection JFE Lion Weight w/o buoyancy factor (lbs) 65,504 lbs Tension at top of section (lbs) w/ 10.5 ppg mud (BF= 0.839)55,003 lbs Minimal Tensile Strength (lbs) 207,000 lbs Worst case safety factor (Tension w/o BF) 3.16 Collapse pressure at bottom (psi) – 10.5 ppg mud and gas gradient of 0.055 psi/ft 3845 Collapse Pressure 10,540 psi Worst case safety factor (Collapse) Gas filled tubing 2.74 39 28.6-3/4” Hole Section for MASP 1. Expected Reservoir Pressure x 3,750 psi @ 7,500 TVD 2. Maximum anticipated surface pressure x 3,338 psi (complete evacuation of wellbore to gas) 29.Permit to Drill Kick Tolerance Evaluation Calculation method: “Rules of Thumb for the Man on the Rig” by William Murchison Copy right 1988 Revised 1993. Attached Kick Tolerance supplement from Rules of Thumb. Input Data: 1) FIT targeted @ 14.0 ppg. Based on historical Cook Inlet Data attached. 2) Window depth per Directional plan KLUA4a sidetrack. 3) Mud weight 10.0 ppg MW/Pore pressure curve. 4) Length of bubble. Assumed 500’ in length. 5) Gas gradient .055 psi/ft 6) BHA length and Diameter 188’ 4.75” O.D. (Sperry planned BHA) Annular OH capacity .02235 bbl/ft. 7) 4.5” Drillpipe/ 6.75” diameter Annular OH capacity .02459 bbl/ft. Kick tolerance 2.7 ppg with a gas kick of 11.87 bbls Max Allowable Surface pressure= (FIT -MW) X .052 X Shoe TVD = (14.0 – 10 ppg) X .052 X 3450’ = 717 psi BHP Max = ((Shoe TVD – Length of Influx) X .052 X MW) + Max Allowable Surface Pressure + (Length of influx X gas gradient) = ((3450’ – 500’) X.052 X 3450’) + 717 psi + (500’ X .055 psi/ft) = 2,278.8 psi BHP Max MW = BHP Max / .052 X Shoe TVD 2278.8 / .052 X 3450’ = 12.7 ppg 40 Kick Tolerance = BHP Max MW – MW = 12.7 ppg – 10.0 ppg = 2.7 ppg Height of influx OH X BHA = .02235 bbl/ft X 188’ = 4.2 bbls Height of influx OH X DP = .02459 bbl/ft X (500’-188’) = 7.67 bbl 11.87 bbl gain Length of influx (ft) Kick intensity (ppg) Gain (bbls) 500 2.7 11.87 1000 1.4 24.16 1250 0.7 26.11 1542 0.0 37.2 Results were verified by independent Kick Tolerance program by Ding Hsu – Drilling Consultant (BP and Exxon experience) 41 30.KLU A-4 Pore Pressure/Frac Gradient 42 31.KLU A-4A Directional Program (wp12) 43 44 45 46 47 48 49 50 51 52 53 54 55 32.KLU A-4A Fluid Program Noble Energy Inc.Furie Operating Alaska KLU A-04A Alaska / U.S.A 2 Owner: Global Operations Manager Document #: TEM-GL-HAL-DF-102-L1 Approved by: Keith Terry Revision: D Date: 08-Oct-21 Halliburton appreciates the opportunity to present this proposal and looks forward to being of service to you. Program Briefing Enclosed is our recommended procedure for Drilling Fluid Services in the referenced well. The information in this proposal includes well data, calculations, material requirements, and cost estimates. This proposal is based on information from our field personnel, customer information and previous services in the area. Halliburton appreciates the opportunity to present this proposal for your consideration and we look forward to being of service to you. Our Services for your well will be coordinated through the Service Center listed below. If you require any additional information or additional designs, please feel free to contact myself or our field representatives listed below. Prepared and Submitted by: Derek Rader Technical Advisor SERVICE CENTER: Anchorage, Alaska ACCOUNT REPRESENTATIVE: Chris MacKinnon TECHNICAL PROFESSIONAL: Derek Rader PHONE NUMBER: 907.275.2626 Noble Energy Inc.Furie Operating Alaska KLU A-04A Alaska / U.S.A 3 Owner: Global Operations Manager Document #: TEM-GL-HAL-DF-102-L1 Approved by: Keith Terry Revision: D Date: 08-Oct-21 Table of Contents 1.0 Program Briefing 1.1 Well Data 1.2 Reservoir Data 1.3 Baroid Project Support team 2.0 Well Design 2.1 Well Objectives 2.2 Casing design 2.3 Drilling Fluid Target Properties 2.4 Drilling Fluid Objectives 3.0 Interval Discussions 3.1 6 ¾”Production Interval 3,750’ – 10,754’MD 3.1.1 Interval Goals 3.1.2 Hazards / Concerns 3.1.3 Mud Type/Operation Summary 3.1.4 System Formulation: 2% KCL/BARASURE W-988/GEM GP 3.1.5 Suggested Drilling Parameters 4.0 Coal Drilling 5.0 Solids Control Equipment 6.0 Well Cost on approval of program 6.1 Interval I Cost 6.2 Total Well Cost 7.0 Lost Circulation Tree Noble Energy Inc.Furie Operating Alaska KLU A-04A Alaska / U.S.A 4 Owner: Global Operations Manager Document #: TEM-GL-HAL-DF-102-L1 Approved by: Keith Terry Revision: D Date: 08-Oct-21 1.0 Program Briefing 1.1 Well Data Operator Furie Operating Alaska Well No.KLU A-04A Field/Block Cook Inlet Location Alaska / U.S.A Well Type Sidetrack Maximum Expected Mud Density 10.0 ppg Estimated Days 30 Estimated Total Project Cost 1.2 Reservoir Data Primary Target #1 10,754’MD / 7,836’ TVD Primary Target #1 Depth 10,754’ MD / 7,836’ TVD Estimated Mud Weight for Target #1 10.0 ppg 1.3 Baroid Project Support Team Baroid Support Team Title Name Cell Number Office Number Email address Technical Professional Derek Rader (907) 351-3772 (907) 275-2626 derek.rader@halliburton.com Operations Leader Chris MacKinnon (907) 227-5045 (907) 275-2617 chris.mackinnon@halliburton.com Stock-point Supervisor Avery Hieber (907) 690-3495 NA avery.hieber@halliburton.com Noble Energy Inc.Furie Operating Alaska KLU A-04A Alaska / U.S.A 5 Owner: Global Operations Manager Document #: TEM-GL-HAL-DF-102-L1 Approved by: Keith Terry Revision: D Date: 08-Oct-21 2.0 Well Design Noble Energy Inc.Furie Operating Alaska KLU A-04A Alaska / U.S.A 6 Owner: Global Operations Manager Document #: TEM-GL-HAL-DF-102-L1 Approved by: Keith Terry Revision: D Date: 08-Oct-21 2.1 Well Objectives The following mud program was prepared for a sidetrack well on the Spartan 151 platform in Cook Inlet, Alaska. The preexisting A-04 well will be decompleted and a whipstock will be set in the 9 5/8” casing at +/- 3,750 MD. A 6 ¾” production hole section will then be drilled to 10,754’MD where a 3 ½” production liner will be run. A 2% KCL/BARASURE W-988/GEM GP mud system weighted at 10.0 ppg will be maintained while drilling the production hole section. This mud is formulated with three mechanisms to provide waste minimization and effective wellbore stabilization: glycol (GEM GP), ionic inhibition (KCl) and amine inhibition (BARASURE W-988). This mud system offers good LCM responses if losses are encountered. BARACARB 5/25/50 and STEELSEAL 50/100/400 will be utilized in this system to maintain wellbore stability. A combination of BAROTROL PLUS and BARAFLC-903 will be used to stabilize coal formations while drilling the production hole section. Special emphasis should be placed on maintaining low ECD’s and surge/swab pressures to minimize the potential for lost circulation and disturbing the coal beds. DFG 6.9 will be run at a minimum of every 12 hours while drilling using real time ROP, RPM and pump rates to monitor hole cleaning. The listed mud formulations have been tested and approved to meet all APDES compliance regulations and are listed in IFACTS reports 18288-HTC and 2026277. 2.2 Casing Design Hole Size Casing Size Depth NA 9 5/8”3,750’ 6 ¾”3 ½”10,754’ 2.3 Drilling Fluid Target Properties 6 ¾”Production Interval from 3,750’to 10,754’ MD Mud Weight Viscosity Plastic Viscosity Yield Point pH HPHT 3,750’- 10,754’ 10.0 40-53 6-15 13-24 8.5-9.5 11.0 2.4 Drilling Fluid Objectives Primary Objective: Drill the well safely, both with respect to personnel and the environment. Noble Energy Inc.Furie Operating Alaska KLU A-04A Alaska / U.S.A 7 Owner: Global Operations Manager Document #: TEM-GL-HAL-DF-102-L1 Approved by: Keith Terry Revision: D Date: 08-Oct-21 Primary Drilling Fluids Objectives: 1) Zero fluid related HSE incidents. 2) Achieve wellbore stability. 3) Lost circulation mitigation/control. 4) Achieve good zonal isolation as per plan. 5) Achieve minimal formation damage. 6) Zero fluids related NPT. 7) Minimize drilling wastes. 8) Maximize ROP. Critical Fluid Issues: 1) Eliminating/Controlling losses. 2) Wellbore stability. 3) Maintain a low ECD to reduce the risk of losses. 4) Reducing drilling wastes with the inhibited drilling fluid. 5)Follow all APDES compliance regulations. 3.0 Interval Discussions 3.1 6 ¾”Production Interval 3,750’ –10,754’MD 3.1.1 Interval Goals x Provide Borehole Stability. x Efficient hole cleaning. x Run production liner. 3.1.2 Hazards / Concerns x Preventing lost circulation. x Optimize solids control equipment to maintain density and sand content. x Maintain YP between 13-24 to optimize hole cleaning and to control ECD. x Pump high viscosity sweeps to enhance hole-cleaning efforts. Monitor sweep effectiveness. x Successfully land and cement liner. Noble Energy Inc.Furie Operating Alaska KLU A-04A Alaska / U.S.A 8 Owner: Global Operations Manager Document #: TEM-GL-HAL-DF-102-L1 Approved by: Keith Terry Revision: D Date: 08-Oct-21 3.1.3 Mud Type/Operation Summary Mud Type 2% KCl/BARASURE W-988/GEM GP 1. Mud weight Maintain the density at 10.0 ppg or as directed; use solids control and whole mud dilution. Increase the density as required for hole stability/coal sloughing. Maximize solids control usage. 2. Rheology Maintain a YP between 13 - 24 or as needed to achieve adequate hole cleaning. Pump high viscosity sweeps throughout the interval as needed, particularly prior to POH for casing. Optimized mud rheology and flow rate will be the primary mechanisms for achieving hole cleaning in this wellbore. Maximize pipe rotation (ideally > 100 RPM). 3. Lubricity:BARALUBE GOLDSEAL is the only lubricants available for use while discharging overboard. Lubricant level must stay <2% to achieve APDES compliance. 4. Other Issues The use of good drilling practices to minimize excessive swab and surge pressure should be employed to reduce the chances for losses and differential sticking. LCM (BARACARBs 5/25/50 and STEELSEAL 50/100/400) and shale stabilizers (BAROTROL PLUS and BARAFLC-903) should be maintained at elevated concentrations while drilling coals to help strengthen the wellbore. Operations Summary Soda ash and citric acid should be used to pretreat for any negative effects of the cement. BARAZAN D+ should be used to maintain rheological parameters. BARACARB 5/25/50 should be maintained at 5 ppb and STEELSEAL 50/100/400 should be maintained at 2 ppb for a total of 7 ppb LCM. BAROTROL PLUS and BARAFLC-903 should be added to help control coal seams. Maintain the mud as clean as possible while drilling. Should sweeps be required, a high viscosity sweep is recommended. Daily additions of X-CIDE 207/ALDACIDE G MUST be made to control bacterial action. PAC L/DEXTRID LT should be used for filtrate control. While drilling, monitor the torque and drag to determine if liquid lubricant is required. If so, approval from town will be required prior to additions of lubricants. When penetrating high-clay content sections, the addition of CON DET PREMIX is recommended to reduce the incidence of bit balling and shaker blinding. Maintain the pH in the 8.5 –9.5 range with caustic soda or KOH. The system rheology may be relaxed as hole conditions allow. This will also lower the ECD for any possible loss zones which might be found and reduce swab tendencies. However, be prepared to increase the YP if hole cleaning becomes an issue. Stress slow pipe movement to the drillers to reduce surge/swab. Stage pumps up slowly after connections and begin rotation prior to pumping (this will break the gels and reduce the pressure required to break the gels). If any trips are required, consider spotting a 20 bbl, 20 ppb LCM pill across the loss zone. The pill should consist of base mud with 10 ppb BARACARB 50 and 10 ppb STEELSEAL added. This pill would reduce the effects of tripping back in and allow time for the LCM to “soak” into the zone. BARACARB’s and STEELSEAL’s will not dehydrate the mud which will allow for lower ECD on the first bottoms up after TIH. Reduce system YP as required for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value they have targeted). Consider spotting a STEELSEAL/BAROTROL PLUS/BARAFLC- 903 pill (20 ppb of the different sizes of STEELSEAL, 4 ppb BAROTROL PLUS, 4 ppb BARAFLC-903) prior to running the casing if losses or coal sloughing have been seen in this interval. Noble Energy Inc.Furie Operating Alaska KLU A-04A Alaska / U.S.A 9 Owner: Global Operations Manager Document #: TEM-GL-HAL-DF-102-L1 Approved by: Keith Terry Revision: D Date: 08-Oct-21 Sweeps Utilize high viscosity sweeps or weighted sweeps as needed to clean the hole. Monitor all sweeps pumped and report their effectiveness. The objective of the sweep is to change the flow characteristics/carrying capacity that are inherent with the mud system. Select sweep type accordingly. Target Properties MD Mud Weight Viscosity Plastic Viscosity Yield Point pH HPHT 3,750’- 10,754’ 10.0 40-53 6-15 13-24 8.5-9.5 11.0 3.1.4 System Formulation: 2% KCL/BARASURE W-988/GEM GP Product Concentration Water KCl Caustic BARAZAN D+ DEXTRID LT PAC L BARASURE W-988 GEM GP BARACARB 5/25/50 STEELSEAL 50/100/400 BAROTROL PLUS BARAFLC-903 BAROID 41 ALDACIDE-G 0.905 bbl 7 ppb 0.2 ppb (9 pH) 1.0 ppb (as required 18 YP) 1-2 ppb 1 ppb 4 ppb 1.0% by volume 5 ppb (1.7 ppb of each) 2 ppb 2 -4ppb 2 -4 ppb as needed 10.0 ppg 0.1 ppb Primary Products: PRODUCTS Product Description Product Function Potassium chloride Potassium chloride Weighting agent Caustic soda Sodium Hydroxide Alkalinity Source BARAZAN D+Dispersion Enhanced xanthan gum Primary viscosifier DEXTRID LT Modified potato starch Filtration Control PAC-L Polyanionic cellulose Filtration Control Agent BARASURE W-988 Amine Inhibitor Shale Inhibition GEM GP Polyalkylene glycol Shale Stabilizer BARACARB Sized Calcium Carbonate Loss Circulation Material STEELSEAL Angular Graphite Loss Circulation Material BAROTROL PLUS Fine-grind Blended Hyrdocarbon Powder Shale Stabilizer BARAFLC-903 Hyrocarbon Powder Shale Stabilizer BAROID 41 Ground barium sulfate Weighting Agent ALDACIDE G Glutaraldehyde solution Microbiocide Noble Energy Inc.Furie Operating Alaska KLU A-04A Alaska / U.S.A 10 Owner: Global Operations Manager Document #: TEM-GL-HAL-DF-102-L1 Approved by: Keith Terry Revision: D Date: 08-Oct-21 3.1.5 Suggested Drilling Parameters Pump rate and drill string rotation should be optimized through the real-time use of the DFG software for the actual ROP while drilling. The tables below highlights the maximum ROP recommendations above which hole cleaning will become an issue in these intervals. Maximum Acceptable ROP in fph at Specified GPM and RPM GPMĺ 150 225 300 80 rpm 75 110 150 100 rpm 80 125 165 120 rpm 85 130 175 Calculated at 2.0% Cuttings Load. Pump rate and rotation are the most critical factors in cleaning this wellbore. Maximize rpms at all times. ROPs above these levels or with no rotation (sliding) or low rpm will require an increased frequency of the following remedial hole cleaning practices: x extended periods of circulation (with maximum pipe rpm, targeting > 100 rpm) x hole cleaning sweeps (change flow regime of base mud by using fibers, density or rheology for carrying capacity) x connection practices - employing extended gpm, rpm and back reaming during the connection 4.0 Coal Drilling The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The need for good planning and drilling practices is also emphasized as a key component for success. x Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. x Use asphalt-type additives to further stabilize coal seams (BARO-TROL PLUS and BARAFLC-903 at 4 ppb). Increase concentrations if sloughing coal in encountered. x Increase fluid density as required to control running coal. x Emphasize good hole cleaning through hydraulics, ROP and system rheology. x Minimize swab and surge pressures. x Minimize back reaming through coals when possible. In the event that sloughing coal is encountered, consider spotting a 30 ppb balck product (BAROTROL and BARAFLC- 903) pill across the coal seam. The pill can be safely “squeezed” into the coal by closing the bag and applying pressure not to exceed the total annular pressure loss. Noble Energy Inc.Furie Operating Alaska KLU A-04A Alaska / U.S.A 11 Owner: Global Operations Manager Document #: TEM-GL-HAL-DF-102-L1 Approved by: Keith Terry Revision: D Date: 08-Oct-21 5.0 Solids Control Equipment Maximize the use of all solids control equipment to ensure that the solids content of the system is kept to a minimum during this interval. 1. Run the shale shakers with as fine a screen size as possible. x Size shakers screens with coarse mesh initially x Adjust screen size as solids loading, mud rheology and flowrates allow x Inspect the shakers frequently, taking time to repair / replace damaged screens 2. Maximize the use of the centrifuge, keeping the fluid as clean as possible. 6.0 Well Cost 6.1 Interval I Cost Interval: 3,750’ – 10,754’MD 6 ¾”Production Hole Section 10.0 ppg 2% KCL/BARASURE W-988/GEM GP I.D.Depth BBLS Pit Volume 650 Cased Hole 8.861”3,750’275 Open Hole 6.75”10,754’310 Washout %10%31 Dilution (total x 1.6)2026 3292Total Volume *Price may vary depending on required dilution rates and adjustments in fluid formulation while drilling. Noble Energy Inc.Furie Operating Alaska KLU A-04A Alaska / U.S.A 12 Owner: Global Operations Manager Document #: TEM-GL-HAL-DF-102-L1 Approved by: Keith Terry Revision: D Date: 08-Oct-21 7.0 Lost Circulation Tree Losses Seepage 5-20 bbl/hr Static Treat Active System with 5 sx/hr Baracarb 50/150 Dynamic Losses < 15 bbl/hr Increase Treatment to 10 sx/hr Baracarb 50/ 150 20 ppb LCM/Mud Pill: 20 bbls base mud 10 ppb Baracarb 50 10 ppb Baracarb 150 Proceed to 'Partial Losses' Pill Drill Ahead Drill Ahead Yes No Yes No Drill Ahead Yes No Partial 20-60 bbl/hr Static Treat Active System with 10 sx/hr Baracarb 150 Drill Ahead Yes 50 ppb LCM/Mud Pill: 20 bbls Base mud 10 ppb Baracarb 25 20 ppb Baracarb 50 20 ppb Baracarb 150 Drill Ahead Yes Contact the Engineer on call to determine if additional LCM treatments are to be made or to proceed to reverse gunk squeeze pill No Severe 60-200 bbl/hr Static 60-150 bbl/hr Static 150-200 bbl/hr Static Drill Across Fault Drill Across Fault Dynamic Losses < 15 bbl/hr Dynamic Losses < 15 bbl/hr Dynamic Losses < 15 bbl/hr No Dynamic Losses < 20 bbl/hr 100 ppb LCM/Mud Pill: 20 ppb Baroseal f 20 ppb Baracarb 50 30 ppb Barofibre 20 ppb SteelSeal 10 ppb Baracarb 150 Pump reverse gunk squeeze pill (Volume to be determined based upon losses Pump reverse gunk squeeze pill to allow POH (Volume to be determined based upon losses) Total > 200 bbl/hr Static Drill Across Fault Pump reverse gunk squeeze pill to allow POH (Volume to be determined based upon losses Plan to pump a second 50-80 bbl reverse gunk squeeze pill if massive losses continue. Consider cement / plugback contingency Chevron Lost Circulation Decision Tree f/ Payzone Mud Systems Contact Drilling Engineer or Engineer "On Call" Contact Drilling Engineer or Engineer on call Contact Drilling Engineer or Engineer on call 1)Chevron must approve any steps past PARTIAL losses. 2) Drill across fault or loss zone 1.5 - 2.0 times the length of the throw before spotting reverse gunk squeeze pills. 3) PBL sub should be run in BHA to spot pills if 'Partial Loss' cases or above are anticipated prior to drilling to allow the spotting of LCM pills. 4) LCM pill volume = 300'-600' column based upon actual hole diameter. 5)PRIOR TO ANY LCM PILL, APPROPRIATE DISCUSSIONS AT THE RIG MUST BE MADE TO MINIMIZE THE POTENTIAL FOR PLUGGING THE DRILL STRING. 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:Mike Stefanov To:McLellan, Bryan J (OGC) Cc:Bob Laule; Mike Stefanov Subject:RE: KLU A-4A cement calcs for KLU A4 Liner Cement Job Date:Wednesday, June 19, 2024 5:02:40 PM Bryan, We concur, we calculated 324 bbls also. Shoe Volume: .8 bbls ( 3 joints of 3-1/2” tbg) = .8 bbls 3-1/2” by 6-3/4” annulus plus 40 % excess : 227.8 X 1.4 = 318 bbls Cement in 100’ of liner lap: = 6.1 bbl. Total = 324.9 bbl. Thank you for your assistance in this matter. Sincerely, Mike Stefanov Drilling Manager Furie Operating Alaska LLC Telephone: 615 738 8596 E-mail: m.stefanov@furiealaska.com From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Wednesday, June 19, 2024 3:08 PM To: Mike Stefanov <m.stefanov@furiealaska.com> Subject: [EXT] KLU A-4A cement calcs Mike, Could you double check your cement calcs? I get a total of 324 bbls required based on your objectives and 40% excess assumption. You calculated 302 bbls total. Thanks Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 ***External Email*** Confidentiality Notice: This email and its attachments (if any) contain confidential information of the sender. The information is intended only for use by the direct addressees of the original sender of this email. If you are not an intended recipient of the original sender (or responsible for delivering the message to such person), you are hereby notified that any review, disclosure, copying, distribution or the taking of any action in reliance of the contents of and attachments to this email is strictly prohibited. If you have received this email in error, please immediately notify the sender at the address shown herein and permanently delete any copies of this email (digital or paper) in your possession. 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:Mike Stefanov To:Davies, Stephen F (OGC) Cc:Andrew Dewhurst; Mike Stefanov; Trey Kendrick Subject:RE: KLU A-4A (PTD 224-075) - Question Date:Wednesday, June 19, 2024 5:08:40 PM Attachments:KLUA-4PorePressurePlot20240619.pdf ContinousImprovementPorePressureTK20240619.pdf You don't often get email from m.stefanov@furiealaska.com. Learn why this is important Steve, The units of measurement on the Y axis are Feet True Vertical Depth from RKB (ft TVD – RKB). Mud weight will be monitored continuously while drilling and adjusted as necessary to maintain an overbalance. In addition, we will have mud loggers on site. Our geologist is continuing to update the pore pressure plot as we continue to analyze production data. Thank you for your assistance in this matter. Sincerely, Mike Stefanov Drilling Manager Furie Operating Alaska LLC Telephone: 615 738 8596 E-mail: m.stefanov@furiealaska.com From: Davies, Stephen F (OGC) <steve.davies@alaska.gov> Sent: Tuesday, June 18, 2024 4:58 PM To: Mike Stefanov <m.stefanov@furiealaska.com> Cc: Andrew Dewhurst <dewhursta@mac.com> Subject: [EXT] KLU A-4A (PTD 224-075) - Question Mike, I’m reviewing Furie’s Permit to Drill application for KLU A-4A. Could you please provide the units of measurement for the Y-axis of the pore pressure chart provided in the application so that I can confirm that Furie’s planned mud weight of 10.0 ppg is sufficient? Thanks and Be Well, Steve Davies Senior Petroleum Geologist AOGCC 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 Steve Davies at 907-793-1224 or steve.davies@alaska.gov ***External Email*** Confidentiality Notice: This email and its attachments (if any) contain confidential information of the sender. The information is intended only for use by the direct addressees of the original sender of this email. If you are not an intended recipient of the original sender (or responsible for delivering the message to such person), you are hereby notified that any review, disclosure, copying, distribution or the taking of any action in reliance of the contents of and attachments to this email is strictly prohibited. If you have received this email in error, please immediately notify the sender at the address shown herein and permanently delete any copies of this email (digital or paper) in your possession. 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Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Mike Stefanov To:McLellan, Bryan J (OGC) Cc:Mike Stefanov; Hunter Van Wyhe Subject:KLU A-4A PTD - Well Site Surveys and the Spartan 151 Rig Date:Friday, June 21, 2024 2:06:43 PM Attachments:image002.png Furie_2024_Subsea Pipeline Sonar Survey Report - Platform Only.pdf Bryan, Below is a note from our engineer, Hunter Van Wyhe, regarding the multi-beam surveys we recently performed. An additional side scan survey for the rig will be performed about 30 days before the scheduled rig arrival. Attached is the survey that was performed for the platform in late April into May of this year. We do not see any obstructions that would prevent bringing the rig on to location, but want to ensure adequate site clearance prior to rig arrival. We have been working with Hilcorp to get an agreed schedule. Sincerely, Mike Stefanov Drilling Manager Furie Operating Alaska LLC Telephone: 615 738 8596 E-mail: m.stefanov@furiealaska.com NOTE from Hunter Van Wyhe – Operations Engineer Mike, We performed a multibeam survey of the pipeline and 300’ radius around the platform with E-Trac early May and found no obstructions. Per Donny Durham with Enterprise, the plan is to perform a side scan survey 30 days prior to mobilizing the rig to ensure there are no obstructions. We have E- Trac lined up to perform this work and will get it on the schedule once we finalize the rig acceptance date with Hilcorp. Attached is an excerpt related to the platform scan from the final report. Let me know if you have any questions or need additional information. Thanks, Hunter Van Wyhe Operations Engineer 433 W. 9th Avenue Anchorage AK 99501 Cell: (907) 378-3354 From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Friday, June 21, 2024 10:40 AM To: Mike Stefanov <m.stefanov@furiealaska.com> Subject: [EXT] KLU A-4A PTD - Well Site Surveys Mike, Has Furie performed a sidescan sonar survey or other to identify potential seabed hazards at the location of the jackup per 20 AAC 25.061(b) or (c)? If so, please send it for inclusion with the PTD. Thank you Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 ***External Email*** Confidentiality Notice: This email and its attachments (if any) contain confidential information of the sender. The information is intended only for use by the direct addressees of the original sender of this email. If you are not an intended recipient of the original sender (or responsible for delivering the message to such person), you are hereby notified that any review, disclosure, copying, distribution or the taking of any action in reliance of the contents of and attachments to this email is strictly prohibited. If you have received this email in error, please immediately notify the sender at the address shown herein and permanently delete any copies of this email (digital or paper) in your possession. 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. KITCHEN LIGHTS, STERLING UNDEFINED GAS - 470500 KITCHEN LIGHTS, BELUGA UNDEFINED GAS - 470510 KLU A-4A KITCHEN LIGHTS 224-075 WELL PERMIT CHECKLISTCompanyFurie Operating Alaska, LLCWell Name:KLU A-4AInitial Class/TypeDEV / PENDGeoArea820Unit11120On/Off ShoreOffProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2240750KITCHEN LIGHTS, STERL UND GAS - 470500 KITCHEN LIGHTS, BLUG UND NA1 Permit fee attachedYes Surf Loc & Top Prod Int lie in ADL0389197; TD lies in ADL0398196.2 Lease number appropriateYes3 Unique well name and numberNo KITCHEN LIGHTS, STERLING UNDEFINED GAS - 4705004 Well located in a defined poolYes KITCHEN LIGHTS, BELUGA UNDEFINED GAS - 4705105 Well located proper distance from drilling unit boundaryNA6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 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)NA Sidetrack18 Conductor string providedYes19 Surface casing protects all known USDWsNA Sidetrack20 CMT vol adequate to circulate on conductor & surf csgYes21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes24 Adequate tankage or reserve pitYes25 If a re-drill, has a 10-403 for abandonment been approvedYes26 Adequate wellbore separation proposedNA27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes29 BOPEs, do they meet regulationYes MPSP = 3338 psi, BOP rated to 5K (BOP test to 5000 psi initial, 4700 psi subsequent)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 has not been encountered in any nearby well; however, rig has monitoring equipment and35 Permit can be issued w/o hydrogen sulfide measuresYes sequestering agents will be onsite.36 Data presented on potential overpressure zonesNA Expected pressure range is 0.213 to 0.503 psi/ft (4.1 to 9.7 ppg EMW). Operator's planned mud program37 Seismic analysis of shallow gas zonesNA appears sufficient to control anticipated pressures and maintain wellbore stability.38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate6/20/2024ApprBJMDate6/21/2024ApprSFDDate6/20/2024AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate*&:JLC 6/25/2024