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224-027
CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Cody Dinger To:Guhl, Meredith D (OGC); Davies, Stephen F (OGC) Cc:Sean McLaughlin Subject:KU 34-05 PTD#224-027 Date:Wednesday, August 21, 2024 1:46:18 PM Attachments:Permit_224-027_042424.pdf Meredith, Hilcorp is requesting to withdraw the permit to drill for KU 34-05. Plans have changed significantly and that well slot will be used to drill a completely different well path / well name / target. A new application for permit to drill that conductor slot will be submitted in the coming months. Thank you! Cody Dinger Hilcorp Alaska, LLC Drilling Tech 907-777-8389 From: Christianson, Grace K (OGC) <grace.christianson@alaska.gov> Sent: Wednesday, April 24, 2024 10:43 AM To: Abbie Barker <Abbie.Barker@hilcorp.com>; Carrie Janowski <Carrie.Janowski@hilcorp.com>; Casey Morse <casey.morse@hilcorp.com>; Cody Dinger <cdinger@hilcorp.com>; Darci Horner - (C) <dhorner@hilcorp.com>; Donna Ambruz <dambruz@hilcorp.com>; Jerimiah Galloway <jerimiah.Galloway@hilcorp.com>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com>; Josh Allely - (C) <josh.allely@hilcorp.com>; Juanita Lovett <jlovett@hilcorp.com>; Tom Fouts <tfouts@hilcorp.com> Subject: [EXTERNAL] New Permit Number 224-027 Hello, Attached is the new Permit for KU 34-05. Thank you, Grace Christianson Executive Assistant, Alaska Oil & Gas Conservation Commission (907) 793-1230 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 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 Monty M. Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK, 99503 Re: Kenai Gas Field, Tyonek Gas Pool 1, KU 34-05 Hilcorp Alaska, LLC Permit to Drill Number: 224-027 Surface Location: 629' FNL, 874' FEL, Sec 7, T4N, R11W, SM, AK Bottomhole Location: 1463' FSL, 2173' FEL, Sec 8, T4N, R11W, SM, AK Dear Mr. Myers: 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 April 2024. Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2024.04.24 10:21:57 -08'00' 24th 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: 10,927' TVD: 9,584' 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): 83.6 15. Distance to Nearest Well Open Surface: x-275024 y- 2361383 Zone-4 65.6 to Same Pool: 1891' to KBU 23-05 16. Deviated wells:Kickoff depth: 650 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 43 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD Cond 16" 84# X-56 Weld 120' Surface Surface 120' 120' 13-1/2" 10-3/4" 45.5# L-80 VAM 21 1,515' Surface Surface 1,515' 1,500' 9-7/8" 7-5/8" 29.7# L-80/P-110 GBCD 7,307' Surface Surface 7,307' 6,000' 6-3/4" 4-1/2" 13.5# L-80 DWC/C 3,820' 7,107' 5,805' 10,927' 9,584 Tieback 4-1/2" 13.5# L-80 DWC/C 7,107' Surface Surface 7,107' 5,805' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): TVD Hydraulic Fracture planned?Yes No 20. Attachments:Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: Contact Email: Contact Phone: Date: Permit to Drill API Number: Permit Approval Number:Date: Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Samples req'd: Yes No Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 5/1/2024 7222' to nearest unit boundary Sean Mclaughlin sean.mclaughlin@hilcorp.com 907-223-6784 L - 634 ft3 / T - 105 ft3 Tieback Assy. 2494 Cement Volume MD Drilling Manager Monty Myers 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): Conductor/Structural Authorized Title: Authorized Signature: Authorized Name: Production Liner Intermediate LengthCasing Size Plugs (measured): (including stage data) Driven L - 727 ft3 / T - 427 ft3 Effect. Depth MD (ft):Effect. Depth TVD (ft): 18. Casing Program:Top - Setting Depth - BottomSpecifications 4409 GL / BF Elevation above MSL (ft): Total Depth MD (ft):Total Depth TVD (ft): 022224484 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 L - 1707 ft3 / T - 171 ft3 3451 1380' FSL, 2326' FEL, Sec 8, T4N, R11W, SM, AK 1463' FSL, 2173' FEL, Sec 8, T4N, R11W, SM, AK N/A 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Hilcorp Alaska, LLC 629' FNL, 874' FEL, Sec 7, T4N, R11W, SM, AK FEE A028142 KU 34-05 Kenai Gas Field Tyonek Gas Pool 1 Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. s N ype of W L l R L 1b S Class: os N s No s N o D s s sD 84 o well is p G S S 20 S S S s No s No S G y E S s No s Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) Drilling Manager 04/08/24 Monty M Myers By Grace Christianson at 9:01 am, Apr 08, 2024 A.Dewhurst 15APR24 DSR-4/12/24 Submit FIT/LOT results within 48 hrs of obtaining test data Diverter variance granted per 20 AAC 25.035(h)(2) based on Hilcorp and AOGCC review of offset wells. -A.Dewhurst 15APR24 50-133-20721-00-00224-027 BOP test to 3500 psi. Annular test to 2500 psi. BJM 4/23/24*&: Brett W. Huber, Sr.Digitally signed by Brett W. Huber, Sr. Date: 2024.04.24 10:21:30 -08'00' 04/24/24 04/24/24 RBDMS JSB 042524 KU 34-05 Drilling Program Kenai Gas Field Rev. PTD April 4, 2024 KU 34-05 Drilling Procedure Contents 1.0 Well Summary................................................................................................................................2 2.0 Management of Change Information...........................................................................................3 3.0 Tubular Program:..........................................................................................................................4 4.0 Drill Pipe Information:..................................................................................................................4 5.0 Internal Reporting Requirements................................................................................................5 6.0 Planned Wellbore Schematic........................................................................................................6 7.0 Drilling / Completion Summary...................................................................................................7 8.0 Mandatory Regulatory Compliance / Notifications....................................................................8 9.0 R/U and Preparatory Work........................................................................................................10 10.0 KU 34-05 location on KGF 41-7 Pad: ........................................................................................11 11.0 Drill 13-1/2” Surface Hole Section..............................................................................................11 12.0 Run 10-3/4” Surface Casing ........................................................................................................13 13.0 Cement 10-3/4” Surface Casing ..................................................................................................15 14.0 BOP N/U and Test........................................................................................................................18 15.0 Drill 9-7/8” Hole Section..............................................................................................................19 16.0 Run 7-5/8” Intermediate Casing.................................................................................................21 17.0 Cement 7-5/8” Intermediate Casing...........................................................................................23 18.0 Drill 6-3/4” Hole Section..............................................................................................................26 19.0 Run 4-1/2” Production Liner ......................................................................................................28 20.0 Cement 4-1/2” Production Liner ................................................................................................30 21.0 4-1/2” Liner Tieback Polish Run / CBL.....................................................................................34 22.0 4-1/2” Tieback Run ......................................................................................................................34 23.0 BOP Schematic.............................................................................................................................35 24.0 Wellhead Schematic.....................................................................................................................36 25.0 Anticipated Drilling Hazards......................................................................................................37 26.0 Hilcorp Rig 169 Layout...............................................................................................................39 27.0 FIT/LOT Procedure ....................................................................................................................40 28.0 Rig 169 Choke Manifold Schematic...........................................................................................41 29.0 Casing Design Information.........................................................................................................42 30.0 9-7/8” Hole Section MASP ..........................................................................................................43 31.0 6-3/4” Hole Section MASP ..........................................................................................................44 32.0 Spider Plot (Governmental Sections NAD27) ...........................................................................45 33.0 Surface Plat (As-Staked NAD27 & NAD83)..............................................................................46 Page 2 Version PTD April, 2024 KU 34-05 Drilling Procedure PTD 1.0 Well Summary Well KU 34-05 Pad & Old Well Designation KGF 41-7 pad Planned Completion Type 4-1/2”Production Liner w/Tieback Target Reservoir(s)Lower Beluga through Deep Tyonek Planned Well TD, MD / TVD 10927’MD / 9584’ TVD AFE Number AFE Drilling Days 31 AFE Drilling Amount Maximum Anticipated Pressure (Surface)3451 psi Maximum Anticipated Pressure (Downhole/Reservoir)4409 psi Work String 4-1/2” 16.6# S-135 CDS-40 RKB –GL 83.6 Ground Elevation 65.6 BOP Equipment 11” 5M Annular BOP 11” 5M Double Ram 11” 5M Single Ram Page 3 Version PTD April, 2024 KU 34-05 Drilling Procedure PTD 2.0 Management of Change Information Page 4 Version PTD April, 2024 KU 34-05 Drilling Procedure PTD 3.0 Tubular Program: Hole Section OD (in) ID (in) Drift (in) Conn OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) Cond 16”15.01”14.822”17”84 X-56 Weld 2980 1410 - Surface 13-1/2”10-3/4”9.95”9.875”11.75”45.5 L-80 VAM21 5210 2470 1040 Intermediate 9-7/8”7-5/8”6.875”6.750”8.500”29.7 L-80/ P110 GBCD 6890 4790 683 Prod 6-3/4”4-1/2”3.920”3.795”5.0”13.5#L-80 DWC/C 9020 8540 307 4.0 Drill Pipe Information: Hole Section OD (in)ID (in)TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) All 4-1/2”3.826 2.6875”5.25”16.6 S-135 CDS40 17,693 16,769 468k Page 5 Version PTD April, 2024 KU 34-05 Drilling Procedure PTD 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on Wellview. x Report covers operations from 6am to 6am x Ensure time entry adds up to 24 hours total. x Capture any out of scope work as NPT. 5.2 Afternoon Updates x Submit a short operations update each work day to KenaiCIODrilling@hilcorp.com 5.3 Intranet Home Page Morning Update x Submit a short operations update each morning by 7am on the company intranet homepage. 5.4 EHS Incident Reporting x Notify EHS field coordinator. 1. Brad Duwe (907-398-6558) 2. Jacob Nordwall: O: (907) 777-8418 C: (907) 748-0753 3. For Spills: Jason Hobart –907-598-5889 © 907-283-1358 (O) x Notify Drlg Manager 1. Monty M Myers: O: 907-777-8431 C: 907-538-1168 x Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally x Send final “As-Run” Casing tally to sean.mclaughlin@hilcorp.com, and cdinger@hilcorp.com 5.6 Casing and Cmt report x Send casing and cement report for each string of casing to sean.mclaughlin@hilcorp.com, and cdinger@hilcorp.com Page 6 Version PTD April, 2024 KU 34-05 Drilling Procedure PTD 6.0 Planned Wellbore Schematic Page 7 Version PTD April, 2024 KU 34-05 Drilling Procedure PTD 7.0 Drilling / Completion Summary KU 34-05 will target the lower Beluga through deep Tyonek sands drilled from Pad 41-7. The Lower Beluga through Deep Tyonek section at KGF needs down spacing. The grassroots well will be drilled to the NE with a maximum hole angle of 43 degrees. The TD of the three string well will be 10927’ TMD/ 9584’ TVD. Drilling operations are expected to commence in May 2024. The Hilcorp Rig #169 will be used to drill the wellbore then run casing and cement. 10-3/4” surface casing will be run and cemented to surface to ensure protection of any shallow freshwater resources. Cement returns to surface will confirm TOC at surface. All waste & mud generated during drilling and completion operations will be hauled to the Kenai Gas Field G&I facility for disposal / beneficial reuse depending on test results. General sequence of operations: 1. MOB Hilcorp Rig # 169 to KGF 41-7 pad x No diverter required 2. Drill 13-1/2”hole to 1515’ MD. Run and cmt 10-3/4”surface casing. 3.N/U & test 11” x 5M BOP to 3500 psi 4. Test Surface casing to 2700 psi. 5. Drill out shoe and perform a FIT to 12.8 ppg EMW 6. Drill 9-7/8” intermediate hole to 7307’MD 7. RIH w/ 7-5/8” casing and cement to surface. 8. Perform casing test to 3500 psi. Swap rams to 4-1/2”.Test BOPE to 3500 psi 9. PU 6-3/4” motor drilling assembly and TIH to window. 10.Mill shoe track and 20’ of new hole. 11. Perform FIT to 13.6 ppg EMW 12. Drill 6-3/4” production hole to 10927’MD 13. Run and cmt 4-1/2”production liner. 14. PU polish mill assembly and RIH to polish sealbore 15. Displace well above liner top to CI water. 16.RU eline and Run CBL across 7-5/8” and 4-1/2” tubing strings. 17. RIH and land 4-1/2” tieback string in liner top. 18. MIT Tubing and IA to 3500 psi. 19. N/D BOP, N/U dry hole tree, RDMO. Reservoir Evaluation Plan: 1. Surface hole: GR + Res LWD 2. Intermediate hole: GR + Res LWD 3. Production Hole: Triple Combo LWD pg No diverter required Page 8 Version PTD April, 2024 KU 34-05 Drilling Procedure PTD 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that 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 the drilling. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be to 250/3500 psi & subsequent tests of the BOP equipment will be to 250/3500 psi for 5/10 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. x If the BOP is used to shut in on the well in a well control situation or could be assumed damaged, test all BOP components utilized for well control 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 program and 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 Ensure AOGCC drilling permit is posted on the rig floor and in Co Man office. x Review all conditions of approval of the AOGCC PTD. Ensure that the conditions of approval are captured in shift handover notes until they are executed and complied with. AOGCC Regulation Variance Request: x 20 AAC 25.035(h)(2) -Diverter waiver request requested due to the recent drilling of KU 13-06A, KU 11-07X , KU 24-05B, KU 24-32, KU 42-12, KU 44-08, KU 44-01B, KU 41-08, and KU 33-08. No issues or shallow gas was experienced on these wells while drilling surface hole. Surface casing will be set at a similar depth of these wells. o Divert waiver requests granted on KU 14-05, KBU 31-06X, KBU 42-06Y, KDU 10, KBU 23- 05, and KU 41-08 (all on 41-7 pad). Recommend approving requested diverter waiver: in addition abovementioned Hilcorp analysis, AOGCC reviewed records for 15 offset wells: KU 41-18, KBU 13-08, KU 11-17, KU 24-07, KU 24-7RD, KBU 33-07, KBU 24-7X, KBU 41-18X, KBU 14-8, KU 12-17, KBU 11-17X, KBU 32-08, KBU 43-07Y, KBU 31-18, and KBU 44-08. None of these wells reported encountering significant gas while drilling to surface casing points at depths. However, well KU 41-18 (PTD 171-010 and over 1 mile away) encountered over 200 units of gas in intermediate hole at ~1,600-1,700' MD (-1,500 to -1,600' TVDSS). Monitoring of gas and caution are advised while drilling to surface casing point. -A.Dewhurst 23FEB24 q Diverter waiver request requested Page 9 Version PTD April, 2024 KU 34-05 Drilling Procedure PTD Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure (psi) 13-1/2”x 21-1/4” x 2M Riser N/A 9-7/8” and 6-3/4” x 11” x 5M Annular BOP x 11” x 5M Double Ram o Blind ram in btm cavity x Mud cross x 11” x 5M Single Ram x 3-1/8” 5M Choke Line x 2-1/16” x 5M Kill line x 3-1/8” x 2-1/16” 5M Choke manifold x Standpipe, floor valves, etc Initial Test: 250/3500 (Annular 2500 psi) Subsequent Tests: 250/3500 (Annular 2500 psi) x Primary closing unit: Control Technologies accumulator unit, 5 station, 120 gallon (12 x 11 gal bottles). x Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency pressure is provided by bottled nitrogen. Required AOGCC Notifications: x Well control event (BOPs utilized to shut in the well to control influx of formation fluids). x 24 hours notice prior to testing BOPs. x Any other notifications required in APD. Additional requirements may be stipulated on APD and Sundry. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email: jim.regg@alaska.gov Bryan McLellan / Petroleum Engineer / (O): 907-793-1226 / Email: bryan.mclellan@alaska.gov Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email: victoria.loepp@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) 2016 Waste Prevention Rule - Waste Minimization Plan for Drilling: Hilcorp Alaska will not be venting or flaring any gas while drilling this well. The only waste produced from this well will be used mud and cuttings and will be handled at the Kenai Gas Field G&I facility for injection disposal. Page 10 Version PTD April, 2024 KU 34-05 Drilling Procedure PTD 9.0 R/U and Preparatory Work 9.1 Set 16” conductor at +/-120’ below ground level. 9.2 Dig out and set impermeable cellar. 9.3 Install Seaboard slip-on 16-3/4” 3M “A” section. Ensure to orient wellhead so that tree will line up with flowline later. 9.4 Level pad and ensure enough room for layout of rig footprint and R/U. 9.5 Layout Herculite on pad to extend beyond footprint of rig. 9.6 R/U Hilcorp Rig # 169, spot service company shacks, spot & R/U company man & toolpusher offices. 9.7 After rig equipment has been spotted, R/U handi-berm containment system around footprint of rig. 9.8 Mix mud for 13-1/2”hole section. 9.9 Install 5-1/2” liners in mud pumps. x HHF-1000 mud pumps are rated at 3036 psi (85%) / 370 gpm (100%) at 120 strokes with 5-1/2” liners. Page 11 Version PTD April, 2024 KU 34-05 Drilling Procedure PTD 10.0 KU 34-05 location on KGF 41-7 Pad: 11.0 Drill 13-1/2”Surface Hole Section 11.1 P/U directional drilling assy: x 13-1/2” Openhole, 8” drilling tools x Ensure BHA components have been inspected previously. x Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. x Workstring will be 4.5” 16.6# S-135 CDS40 11.2 Begin drilling out from 16”conductor at reduced flow rates to avoid broaching the conductor. 11.3 Drill surface hole section to 1515’MD/ 1500’ TVD. Confirm this setting depth with the geologist and Drilling Engineer while drilling the well. Page 12 Version PTD April, 2024 KU 34-05 Drilling Procedure PTD x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at ~700 gpm. Ensure shaker screens are set up to handle this flowrate. x Utilize Kenai and Inlet experience to drill through coal seams efficiently. x Keep swab and surge pressures low when tripping. x Make wiper trips every 800’ or every couple days unless hole conditions dictate otherwise. x Ensure shale shakers are functioning properly. Check for holes in screens on connections. x Adjust MW as necessary to maintain hole stability. x Take MWD surveys every stand drilled (60’ intervals). 11.4 13-1/2”hole mud program summary: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 9.0 ppg. 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. System Type: 8.8 –9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud Properties: Depths Density Viscosity Plastic Viscosity Yield Point API FL pH 120-1515’ 8.8 – 9.5 85-150 20 - 40 25 - 45 <10 8.5-9.0 System Formulation: Aquagel + FW spud mud Product Concentration FRESH WATER SODA ASH AQUAGEL CAUSTIC SODA BARAZAN D+ BAROID 41 PAC-L /DEXTRID LT ALDACIDE G X-TEND II 0.905 bbl 0.5 ppb 12-15 ppb 0.1 ppb (9 pH) as needed as required for weight if required for <12 FL 0.1 ppb 0.02 ppb 11.5 At TD; pump sweeps, CBU, and pull a wiper trip back to the 16”conductor shoe. 11.6 TOH with the drilling assy, handle BHA as appropriate. Page 13 Version PTD April, 2024 KU 34-05 Drilling Procedure PTD 12.0 Run 10-3/4”Surface Casing 12.1 R/U and pull wear bushing. 12.2 R/U Parker 10-3/4”casing running equipment. x Ensure 10-3/4”VAM21 x CDS 40 XO on rig floor and M/U to FOSV. x R/U fill-up line to fill casing while running. x Ensure all casing has been drifted on the location prior to running. x Be sure to count the total # of joints on the location before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 12.3 P/U shoe joint, visually verify no debris inside joint. 12.4 Continue M/U & thread locking shoe track assy consisting of: x (1) Shoe joint w/ float shoe bucked on (thread locked). x (1) Joint with coupling thread locked. x (1) Joint with float collar bucked on pin end & thread locked. x Install (2) centralizers on shoe joint over a stop collar. 10’ from each end. x Install (1) centralizer, mid tube on thread locked joint and on FC joint. x Ensure proper operation of float equipment. 12.5 Continue running 10-3/4”surface casing x Fill casing while running using fill up line on rig floor. x Use “API Modified” thread compound. Dope pin end only w/ paint brush. x Note M/U torque values required to achieve this position. x Install (1) centralizer every other joint to 200’. Do not run any centralizers above 200’ in the event a top job is needed. x Utilize a collar clamp until weight is sufficient to keep slips set properly. Page 14 Version PTD April, 2024 KU 34-05 Drilling Procedure PTD Page 15 Version PTD April, 2024 KU 34-05 Drilling Procedure PTD 12.6 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. Slow in and out of slips. 12.7 P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint while it is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the hanger. 12.8 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. 12.9 R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume. Elevate the hanger offseat to avoid plugging the flutes. Stage up pump slowly and monitor losses closely while circulating. 12.10 After circulating, lower string and land hanger in wellhead again. 13.0 Cement 10-3/4”Surface Casing 13.1 Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cmt unit at acceptable rates. x Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to cuttings bin, prior to pumping any fluid downhole x Discuss how to handle cmt returns at surface. x Confirm which pump will be utilized for displacement, and how fluid will be fed to displacement pump. x Determine positions and expectations of personnel involved with the cmt operation. 13.2 Document efficiency of all possible displacement pumps prior to cement job 13.3 R/U cmt head (if not already done so). Ensure top and bottom plugs have been loaded correctly. 13.4 Pump 5 bbls spacer. Test surface cmt lines. 13.5 Pump remaining spacer. 13.6 Drop bottom plug. Mix and pump cmt per below recipe. 13.7 Cement volume based on annular volume + 100% open hole excess. Job will consist of lead & tail, TOC brought to surface. Page 16 Version PTD April, 2024 KU 34-05 Drilling Procedure PTD Estimated Total Cement Volume: Cement Slurry Design: Lead Slurry (1015’ MD to surface)Tail Slurry (1515’ to 1015’ MD) System Extended Conventional Density 12 lb/gal 15.4 lb/gal Yield 2.40 ft3/sk 1.16 ft3/sk Mixed Water 14.25 gal/sk 5.04 gal/sk Mixed Fluid 14.25 gal/sk 5.04 gal/sk Additives Code Description Code Description Type I/II Cement Class A Type I/II Cement Class A Halad-344 Fluid Loss Halad-344 Fluid Loss CalSeal Accelerator CalSeal Accelerator VersaSet Thixotropic CFR-3 Dispersant D-Air 5000 Anti Foam UCS Slurry Conditioner Econolite Light-weight add.Super CBL Anti-Gas Migration SA-1015 Suspension Agent BridgeMaker II Lost Circulation Verified cement volumes -bjm Page 17 Version PTD April, 2024 KU 34-05 Drilling Procedure PTD 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hanger elevated above the wellhead while working. If the hole gets “sticky”, land the hanger on seat and continue with the cement job. 13.9 After pumping cement, drop top plug and displace cement with spud mud. 13.10 Ensure cement unit is used to displace cmt so that volume tracking is more accurate. 13.11 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. 13.12 Do not overdisplace by more than 1 shoe track volume. Total volume in shoe track is 11 bbls. 13.13 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held. 13.14 R/D cement equipment. Flush out wellhead with FW. 13.15 Back out and L/D landing joint. Flush out wellhead with FW. 13.16 M/U pack-off running tool and pack-off to bottom of Landing joint. Set casing hanger packoff. Run in lock downs and inject plastic packing element. 13.17 Lay down landing joint and pack-off running tool. Ensure to report the following on wellview: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Page 18 Version PTD April, 2024 KU 34-05 Drilling Procedure PTD Send final “As-Run” casing tally & casing and cement report to cdinger@hilcorp.com and sean.mclaughlin@hilcorp.com. 14.0 BOP N/U and Test 14.1 ND Riser 14.2 N/U multi-bowl wellhead assy. Install 10-3/4” packoff P-seals. Test to 3000 psi. 14.3 N/U 11” x 5M BOP as follows: x BOP configuration from Top down: 11” x 5M annular BOP/11” x 5M double ram /11” x 5M mud cross/11” x 5M single ram x Double ram should be dressed with 7-5/8” fixed bore rams in top cavity, blind ram in btm cavity. x Single ram should be dressed with 2-7/8” x 5” variable bore rams x N/U bell nipple, install flowline. x Install (2) manual valves & a check valve on kill side of mud cross. x Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. 14.4 Run BOP test assy, land out test plug (if not installed previously). x Utilize 7-5/8” and 4-1/2” test joints. x Test BOP to 250/3500 psi for 5/10 min. x Test annular to 250/2500 psi for 5/10 min with a 4-1/2” test joint x Ensure to leave “B” section side outlet valves open during BOP testing so pressure does not build up beneath the test plug. 14.5 R/D BOP test assy. 14.6 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.7 Mix 9.1 ppg 6% KCL PHPA mud system. 14.8 Rack back as much 4-1/2”DP in derrick as possible to be used while drilling the hole section. Page 19 Version PTD April, 2024 KU 34-05 Drilling Procedure PTD 15.0 Drill 9-7/8” Hole Section 15.1 Pull test plug, run and set wear bushing 15.2 Ensure BHA components have been inspected previously. 15.3 Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 15.4 TIH, Conduct shallow hole test of MWD and confirm all LWD functioning properly. 15.5 Ensure TF offset is measured accurately and entered correctly into the MWD software. 15.6 Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. 15.7 Workstring will be 4.5” 16.6# S-135 CDS40. Ensure to have enough 4-1/2” DP in derrick to drill the entire open hole section without having to pick up pipe from the pipeshed. 15.8 9-7/8” hole section mud program summary: Starting mud weight for the production interval is 9.1ppg. Weighting material to be used for the hole section will be barite, salt and calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. 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. System Type: 9.1 ppg 6% KCL PHPA fresh water based drilling fluid. Properties: MD Mud Weight Viscosity Plastic Viscosity Yield Point pH HPHT 1515’-7307’9.0 –9.7 40-53 15-25 15-25 8.5-9.5 11.0 Page 20 Version PTD April, 2024 KU 34-05 Drilling Procedure PTD System Formulation: 6% KCL EZ Mud DP Product Concentration Water KCl Caustic BARAZAN D+ EZ MUD DP DEXTRID LT PAC-L BARACARB 5/25/50 BAROID 41 ALDACIDE G BARACOR 700 BARASCAV D 0.905 bbl 22 ppb (29 K chlorides) 0.2 ppb (9 pH) 1.25 ppb (as required 18 YP) 0.75 ppb (initially 0.25 ppb) 1-2 ppb 1 ppb 15 - 20 ppb (5 ppb of each) as required for a 9.0 –10.0 ppg 0.1 ppb 1 ppb 0.5 ppb (maintain per dilution rate) 15.9 TIH w/ 6-3/4” directional BHA assy to TOC. Shallow test MWD and LWD on trip in. Note depth TOC tagged on AM report. 15.10 R/U and test casing to 2700 psi / 30 min. Ensure to record volume / pressure and plot on FIT graph. AOGCC requirement is 50% of burst. 10-3/4” burst is 5210 psi / 2 = 2605 psi. 15.11 Drill out shoe track and 20’ of new formation. 15.12 CBU and condition mud for FIT. 15.13 Conduct FIT to 12.8 ppg EMW. (12.5 FIT, 8.5 ppg BHP, 9.1 ppg MW = 21 bbl KTV) 15.14 Drill 9-7/8” hole section to 7307’ MD / 6000’ TVD x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at ~400 gpm. Ensure shaker screens are set up to handle this flowrate. x Keep swab and surge pressures low when tripping. x Make wiper trips every 1000’ unless hole conditions dictate otherwise.Halfway through the hole section make a wiper back to the shoe. x Ensure shale shakers are functioning properly. Check for holes in screens on connections. x Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10. x Take MWD surveys every 100’drilled. Surveys can be taken more frequently if deemed necessary. x Low BHP between Pool 4 and 6 (4581’ –5820’). To minimize LC risk keep MW at 9.1 ppg, minimize ECD, stage up pumps on connections, add Black products and sized Calcium Carbonate to the mud, Control drill at 40 fph. 15.15 At TD; pump sweeps, CBU, and pull a wiper trip back to the 10-3/4”shoe. 15.16 TOH with the drilling assy, standing back enough drill pipe for the upcoming liner run 15.17 POOH LDDP and BHA. Page 21 Version PTD April, 2024 KU 34-05 Drilling Procedure PTD 15.18 Ensure 7-5/8” FBRs previously installed in BOP stack and tested with 7-5/8” test joint. 16.0 Run 7-5/8” Intermediate Casing 1. R/U and pull wear bushing. 2. R/U Parker 7-5/8” casing running equipment. x Ensure 7-5/8” GBCD x CDS40 XO on rig floor and M/U to FOSV. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x Ensure all casing has been drifted to 6.75” on the location prior to running. x Note that 29.7# drift is 6.75” x Be sure to count the total # of joints on the location before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 3. P/U shoe joint, visually verify no debris inside joint. 4. Continue M/U & thread locking 80’ shoe track assembly consisting of: 7-5/8” Float Shoe 1 joint –7-5/8” BTC, 1 Centralizer 10’ from bottom w/ stop ring 7-5/8” Float Collar 1 joint –7-5/8” BTC, 1 Free floating centralizer 7-5/8” Landing collar 5. Continue running 7-5/8” intermediate casing x Centralization: x 1 centralizer every joint to 1000’ MD (Planned TOC) x Utilize a collar clamp until weight is sufficient to keep slips set properly. Page 22 Version PTD April, 2024 KU 34-05 Drilling Procedure PTD 6. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 7. Slow in and out of slips. 8. P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint while it is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the hanger. 9. Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. Conventional circulation is not permissible once casing hanger is landed. Page 23 Version PTD April, 2024 KU 34-05 Drilling Procedure PTD 10. P/U and R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume. Elevate the hanger off seat to avoid plugging. Stage up pump slowly and monitor losses closely while circulating. 11. After circulating, lower string and land hanger in wellhead again. Cement to surface is not expected. However, in the event cement is circulated out ensure hose is in place to take returns to the cellar. 17.0 Cement 7-5/8” Intermediate Casing 1. Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cementing unit at acceptable rates. x Which pumps will be utilized for displacement, and how fluid will be fed to displacement pump. x Ensure adequate amount of water for mix fluid is heated and available in the water tanks. x Positions and expectations of personnel involved with the cementing operation. i. Extra hands in the pits to strap during the cement job to identify any losses x Review test reports and ensure pump times are acceptable. x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor. 2. Document efficiency of all possible displacement pumps prior to cement job. 3. Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cement pump or treating iron will not be pumped downhole. 4. R/U cement line (if not already done so). 5. Fill surface cement lines with water and pressure test. 6. Pump remaining 60 bbls 10.5 ppg tuned spacer. 7. Mix and pump cement per below calculations, confirm actual cement volumes with cementer after TD is reached. 8. Cement volume based on annular volume + 40% open hole excess. Job will consist of lead & tail, TOC brought to 1000’. Page 24 Version PTD April, 2024 KU 34-05 Drilling Procedure PTD Estimated Cement Volume: Cement Slurry Design: 9. Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation, land hanger, and continue with the cement job. 10. After pumping cement, drop wiper plug and displace cement with mud out of mud pits. a. Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. Lead Slurry 6807’-1000’ Tail Slurry 7307’-6807’ System EconoCem HalCem Density 12.0 lb/gal 15.3 lb/gal Yield 2.35 ft3/sk 1.16 ft3/sk Mix Water 13.92 gal/sk 4.98 gal/sk Verified cement calcs Page 25 Version PTD April, 2024 KU 34-05 Drilling Procedure PTD 11. Ensure rig pump is used to displace cement. 12. Land hanger. 13. Displacement volume is in Table above. 14. Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. 15. If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 1 shoe track volume, ±4 bbls before consulting with Drilling Engineer. 16. Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened. 17. Be prepared for cement returns to surface. Cement return to be taken to cellar. Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact with the cement. 18. R/D cement equipment. Flush out wellhead with FW. 19. Back out and L/D landing joint. Flush out wellhead with FW. 20. M/U pack-off running tool and pack-off to bottom of Landing joint. Set casing hanger packoff. Run in lock downs and inject plastic packing element. 21. Lay down landing joint and pack-off running tool. Ensure to report the following on wellview: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Page 26 Version PTD April, 2024 KU 34-05 Drilling Procedure PTD Send final “As-Run” casing tally & casing and cement report to sean.mclaughlin@hilcorp.com and cody.dinger@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. 18.0 Drill 6-3/4” Hole Section 1. Set test plug, Swap 7-5/8” FBR to 2-7/8” x 5” VBR, test all rams to 3500 psi.,Pull test plug, run and set wear bushing 2. Ensure BHA components have been inspected previously. 3. Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 4. TIH, conduct shallow hole test of MWD and confirm all LWD functioning properly (triple combo and GeoTap). 5. Ensure TF offset is measured accurately and entered correctly into the MWD software. 6. Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. 7.Workstring will be 4.5” 16.6# S-135 CDS40. Ensure to have enough 4-1/2” DP in derrick to drill the entire open hole section without having to pick up pipe from the pipeshed. 8. 6-3/4” hole section mud program summary: Starting mud weight for the production interval is 9.8 ppg or the intermediate interval mud weight at TD, whichever is heavier.(10.7 ppg required at 7000’ TVD, 11.5 ppg required at TD) Weighting material to be used for the hole section will be barite, salt and calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. 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. System Type: 11.5 ppg 6% KCL PHPA fresh water based drilling fluid. Page 27 Version PTD April, 2024 KU 34-05 Drilling Procedure PTD Properties: MD Mud Weight Viscosity Plastic Viscosity Yield Point pH HPHT 7307’- 10927’9.8 –12.5 40-53 15-25 15-25 8.5-9.5 11.0 System Formulation: 6% KCL EZ Mud DP Product Concentration Water KCl Caustic BARAZAN D+ EZ MUD DP DEXTRID LT PAC-L BARACARB 5/25/50 BAROID 41 ALDACIDE G BARACOR 700 BARASCAV D 0.905 bbl 22 ppb (29 K chlorides) 0.2 ppb (9 pH) 1.25 ppb (as required 18 YP) 0.75 ppb (initially 0.25 ppb) 1-2 ppb 1 ppb 15 - 20 ppb (5 ppb of each) as required for a 9.0 –10.0 ppg 0.1 ppb 1 ppb 0.5 ppb (maintain per dilution rate) 9. TIH w/ 4-3/4” directional assy to TOC. Shallow test MWD and LWD on trip in. Note depth TOC tagged on AM report. 10. R/U and test casing to 3500 psi / 30 min. Ensure to record volume / pressure and plot on FIT graph. AOGCC requirement is 50% of burst. 7-5/8”L-80 burst is 6880 psi / 2 = 3440 psi. 11.Drill out shoe track and 20’ of new formation. 12. CBU and condition mud for FIT. 13. Conduct FIT to 13.6 ppg EMW. (13.3 FIT, 8.8 ppg BHP, 11.5 ppg MW = 20 bbl KTV) 14. Drill 6-3/4” hole section to 10927’ MD / 9584’ TVD x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at ~200-270 gpm. Ensure shaker screens are set up to handle this flowrate. x Keep swab and surge pressures low when tripping. x Make wiper trips every 1000’ unless hole conditions dictate otherwise. Halfway through to interval make a wiper trip to the shoe. x Ensure shale shakers are functioning properly. Check for holes in screens on connections. x Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10. x Take MWD surveys every 100’ drilled. Surveys can be taken more frequently if deemed necessary. x Mud Weight: 10.7 ppg required at 7000’ TVD, 11.5 ppg required at TD 15. At TD; pump sweeps, CBU, and pull a wiper trip back to the 7-5/8” shoe. Page 28 Version PTD April, 2024 KU 34-05 Drilling Procedure PTD 16. TOH with the drilling assy, standing back enough drill pipe for the upcoming liner run 17. POOH LDDP and BHA. 18. Ensure 2-7/8” x 5” VBRs previously installed in BOP stack and tested with 4-1/2” test joint 19.0 Run 4-1/2”Production Liner 1. R/U Parker 4-1/2”casing running equipment. x Ensure 4-1/2”DWC/C x CDS 40 crossover on rig floor and M/U to FOSV. x R/U fill up line to fill casing while running. x Ensure all casing has been drifted prior to running. x Be sure to count the total # of joints before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 2. P/U shoe joint, visually verify no debris inside joint. 3. Continue M/U & thread locking shoe track assy consisting of: x (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked). x (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked). x (1) Joint with Baker landing collar bucked on pin end & threadlocked. x Solid body centralizers will be pre-installed on shoe joint an FC joint. x Leave centralizers free floating so that they can slide up and down the joint. x Ensure proper operation of float shoe and float collar. x Utilize a collar clamp until weight is sufficient to keep slips set properly. x MU a marker joint (short joint with RA tag) every 500’. 4. Continue running 4-1/2”production liner x Fill liner while running using fill up line on rig floor. x Use “API Modified” thread compound. Dope pin end only w/ paint brush. x Install solid body centralizers on every joint x Differential sticking risk: Keep Mud “clean” as possible, remove low gravity solid (drilled solids), Centralizers every joint, Minimize connection time, Slow running speeds to reduce surge, Keep pipe moving whenever possible Page 29 Version PTD April, 2024 KU 34-05 Drilling Procedure PTD 5. Run in hole w/ 4-1/2” liner to the 7-5/8” casing shoe. 6. Fill the casing with fill up line and break circulation every 1,000 feet to the shoe or as the hole dictates. 7. Obtain slack off weight, PU weight, rotating weight and torque of the casing. 8. Circulate 2X bottoms up at shoe, ease casing thru shoe. 9. Continue to RIH w/ casing no faster than 1 jt./minute. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. Page 30 Version PTD April, 2024 KU 34-05 Drilling Procedure PTD 10. Set casing slowly in and out of slips. 11. PU 4-1/2” X 7-5/8” Baker liner hanger/LTP assembly. RIH 1 stand and circulate one liner volume to clear string. Obtain slack off weight, PU weight, rotating weight and torque parameters of the liner. 12. Continue running in hole at slow speeds to avoid surging well. Target 20 ft/min and adjust slower as hole conditions dictate. 13. Swedge up and wash last stand to bottom. P/U 5’ off bottom. Note slack-off and pick-up weights. 14. Stage pump rates up slowly to circulating rate. Circ and condition mud with liner on bottom. Circulate 2X bottoms up or until pressures stabilize and mud properties are correct and the shakers are clean. Reduce the low end rheology of the drilling fluid by adding water and thinners. 15. Rotate and reciprocate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. 20.0 Cement 4-1/2”Production Liner 1. Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cmt unit at acceptable rates. x Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to cuttings bin, prior to pumping any fluid downhole x Plan for cmt returns at surface, regardless of how unlikely it is that this should occur. x Determine which pump will be utilized for displacement, and how fluid will be fed to displacement pump. x Positions and expectations of personnel involved with the cmt operation. x Document efficiency of all possible displacement pumps prior to cement job. 2. Attempt to rotate and reciprocate the liner during cmt operations until hole gets sticky 3. Pump 5 bbls spacer. 4. Test surface cmt lines to 4500 psi. 5. Pump remaining spacer. 6. Mix and pump lead and tail cement per below recipe. Ensure cement is pumped at designed weight. Job is designed to pump 40% OH excess. Page 31 Version PTD April, 2024 KU 34-05 Drilling Procedure PTD Estimated Total Cement Volume: Cement Slurry Design: Lead Slurry (10427’ MD to 7107’ MD)Tail Slurry (10927’ to 10427’ MD) System Extended Conventional Density 12 lb/gal 15.4 lb/gal Yield 2.46 ft3/sk 1.22 ft3/sk Mixed Water 14.349 gal/sk 5.507 gal/sk Mixed Fluid 14.469 gal/sk 5.507 gal/sk Additives Code Description Concentration Code Description Concentration G Cement 94#/sk A Cement 94#/sk D110 Retarder 0.15 gal/sk BWOC D046 Anti Foam 0.2 % BWOC D046 Anti Foam 0.2 % BWOC D065 Dispersant 0.4 % BWOC D079 Extender 2.0 % BWOC S002 CaCl2 0.35 % BWOC D020 Extender 3.0 % BWOC D177 CaCl2 0.1 % BWOC Verified cement calcs. -bjm Page 32 Version PTD April, 2024 KU 34-05 Drilling Procedure PTD 7. Drop drillpipe dart and displace with drilling mud. If hole conditions allow –continue rotating and reciprocating liner throughout displacement. This will ensure a high quality cement job with 100% coverage around the pipe. 8. Displace cement at max rate of 4 bbl/min. Reduce pump rate to 2-3 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. 9. If elevated displacement pressures are encountered, position casing at setting depth and cease reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman immediately of any changes. 10. Bump the plug and pressure up to up as required by Baker procedure to set the liner hanger (ensure pressure is above nominal setting pressure, but below pusher tool activation pressure). Hold pressure for 3-5 minutes. 11. Slack off total liner weight plus 30k to confirm hanger is set. 12. Do not overdisplace by more than 2 shoe track volumes. Shoe track volume is 1 bbls. 13. Continue pressuring up to activate LTP pusher tool and set packer with running tool in compression. 14. Pressure up to 4,500 psi to neutralize the pusher tool and release the running tool (HRD-E) from the liner. 15. Bleed pressure to zero to check float equipment. Watch for flow. Note amount of fluid returned after bumping plug and releasing pressure. 16. P/U past free-travel verify setting tool is released, confirmed by loss of liner weight 17. Pressure up drill pipe to 500 psi and pick up to remove the RS packoff bushing from the RS nipple. Bump up pressure as req’d to maintain 500 psi DP pressure while moving pipe until the pressure drops rapidly, indicating pack-off is above the sealing area (ensure that 500 psi will be enough to overcome hydrostatic differential at liner top). 18. Immediately with the loss of pressure and before DP reaches zero, initiate circulation while picking up to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to wellbore clean up rate until the sleeve area is thoroughly cleaned. Page 33 Version PTD April, 2024 KU 34-05 Drilling Procedure PTD 19. Pick up to the high-rate circulation point above the tieback extension, mark the pipe for reciprocation, do not re-tag the liner top, and circulate the well clean. Watch for cement returns and record the estimated volume. Rotate & circulate to clear cmt from DP. 20. RD cementers and flush equipment. POOH, LDDP and running tool. Verify the liner top packer received the required setting force by inspecting the rotating dog sub. Backup release from liner hanger: 21. If the HRD-E tool still does not release hydraulically, left-hand (counterclockwise) torque will have to be applied to the tool. This torque acts to shear brass screws. Bleed off pump pressure and ensure that the tool is in the neutral position. Apply left-hand torque as required to shear screws. 22.NOTE: Some hole conditions may require movement of the drillpipe to “work” the torque down to the setting tool. 23. After screws have sheared, the top sub and body of the setting tool will turn 1/4 turn. Then proceed slacking off set-down weight to shear second set of shear screws. The top sub will drop 1-3/4 inches. At this point, the bottom sub no longer supports the collet fingers. Pick straight up with workstring to release collet from the profile. Ensure to report the following on wellview: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to cdinger@hilcorp.com and sean.mclaughlin@hilcorp.com. Page 34 Version PTD April, 2024 KU 34-05 Drilling Procedure PTD 21.0 4-1/2”Liner Tieback Polish Run / CBL 1. PU liner tieback polish mill assy per Baker rep and RIH on drillpipe. 2. RIH to top of liner assembly and establish parameters. Polish tieback receptacle per Baker procedure. 3. CBU and displace well to CI water. 4. POOH LDDP and BHA 5.RU eline and run CBL across the 7-5/8” casing and 4-1/2” liner. 6. If not completed, test 4-1/2” liner lap to 3500 psi for 10 minutes 22.0 4-1/2” Tieback Run 1. PU 4-1/2” tieback assembly and RIH with 4-1/2” 13.5# L-80 DWC/C tubing x No SSSV, GLM, or CIM required. 2. No-go tieback seal assembly in liner PBR and mark pipe. PU pup joint(s) if necessary to space out tieback seals in PBR. 3. PU hanger and land string in hanger bowl. Note distance of seals from no-go. 4. Install packoff and test hanger void. 5. Test 4-1/2” liner and tieback to 3500 psi and chart for 30 minutes. 6. Test 7-5/8” x 4-1/2” annulus to 3500 psi and chart for 30 minutes. 7. Install BPV in wellhead 8. N/D BOPE 9. N/U dry hole tree or full tree (if available). 10. RDMO Hilcorp Rig #169 Page 35 Version PTD April, 2024 KU 34-05 Drilling Procedure PTD 23.0 BOP Schematic Page 36 Version PTD April, 2024 KU 34-05 Drilling Procedure PTD 24.0 Wellhead Schematic Page 37 Version PTD April, 2024 KU 34-05 Drilling Procedure PTD 25.0 Anticipated Drilling Hazards 9-7/8”Hole Section: Lost Circulation: High risk in Pool 3-6 due to Low BHP. To minimize LC risk keep MW at 9.1 ppg, minimize ECD, stage up pumps on connections, add Black products and sized Calcium Carbonate to the mug, Control drill at 40 fph. Drilling through low pressure intervals: Ensure 500 lbs of medium/coarse fibrous material & 500 lbs different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Hole Cleaning: Maintain rheology w/ gel and gel extender. Sweep hole with gel or flowzan sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Maintain YP between 25 –45 to optimize hole cleaning and control ECD. Wellbore stability: Lithology through this zone is a composite of pebble conglomerate and sand in the upper intervals with intermittent clay matrix. Carbonaceous material and coal may be noted. Gravel sizes that are larger than normal can cause hole-cleaning problems. If encountered, be prepared to increase the viscosity. Excessive quantities of gravel and sand may indicate wellbore instability. Increase properties up to a YP of ~50 - ~60 lbs/100ft2 to combat this issue. Maintain low flow rates for the initial 200’ of drilling to reduce the likelihood of washing out the conductor shoe. To help insure good cement to surface after running the casing, condition the mud to a YP of 25 –30 prior to cement operations. Do not lower the YP beyond 25 to avoid trouble with sands that may be found on this well. Have Desco DF, SAPP, and water on hand to ensure the desired rheologies can be achieved. H2S: H2S is not present in this hole section. Abnormal pressures or temperatures: None Page 38 Version PTD April, 2024 KU 34-05 Drilling Procedure PTD 6-3/4” Hole Section: Lost Circulation: Ensure 1000 lbs of each of the different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Hole Cleaning: Maintain rheology w/ viscosifier as necessary. Sweep hole w/ 20 bbls hi-vis pills as necessary. Optimize solids control equipment to maintain density and minimize sand content. Maintain YP between 20 - 30 to optimize hole cleaning and control ECD. Wellbore stability: Maintain MW as necessary using additions of Calcium Carbonate as weighting material. A torque reduction lube may be used in this hole section in concentrations up to 3% if needed. Maintain 6% KCl in system for shale inhibition. 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. H2S: H2S is not present in this hole section. Reservoir Pressure: Abnormal pressures expected in the deep Tyonek inteval Page 39 Version PTD April, 2024 KU 34-05 Drilling Procedure PTD 26.0 Hilcorp Rig 169 Layout Page 40 Version PTD April, 2024 KU 34-05 Drilling Procedure PTD 27.0 FIT/LOT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 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 with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-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. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Page 41 Version PTD April, 2024 KU 34-05 Drilling Procedure PTD 28.0 Rig 169 Choke Manifold Schematic Page 42 Version PTD April, 2024 KU 34-05 Drilling Procedure PTD 29.0 Casing Design Information Page 43 Version PTD April, 2024 KU 34-05 Drilling Procedure PTD 30.0 9-7/8” Hole Section MASP Page 44 Version PTD April, 2024 KU 34-05 Drilling Procedure PTD 31.0 6-3/4” Hole Section MASP Page 45 Version PTD April, 2024 KU 34-05 Drilling Procedure PTD 32.0 Spider Plot (Governmental Sections NAD27) Page 46 Version PTD April, 2024 KU 34-05 Drilling Procedure PTD 33.0 Surface Plat (As-Staked NAD27 & NAD83) Page 47 Version PTD April, 2024 KU 34-05 Drilling Procedure PTD ! " !"#$ -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 Tr u e V e r t i c a l D e p t h ( 1 5 0 0 u s f t / i n ) -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 Vertical Section at 69.00° (1500 usft/in) KU 34-05 tgt1 10 3/4" Casing 7 5/8" Casing 4 1/2" Casing 500 1 0 0 0 1 5 0 0 2 0 0 0 2 5 0 0 3 0 0 0 3 5 0 0 4 0 0 0 4 5 0 0 5 0 0 0 5 5 0 0 6 0 0 0 6 5 0 0 7 0 0 0 7 5 0 0 8 0 0 0 8 5 0 0 9 0 0 0 9 5 0 0 1 0 0 0 0 1 0 5 0 0 1 0 9 2 7 KU 34-05 wp04 Start Dir 2º/100' : 650' MD, 650'TVD Start Dir 3º/100' : 1250' MD, 1245.62'TVD End Dir : 2268.22' MD, 2139.99' TVD Start Dir 3º/100' : 6276.37' MD, 5093.05'TVD End Dir : 7427.82' MD, 6118.6' TVD Total Depth : 10926.88' MD, 9583.6' TVD Top Pool 3_A6 Top Pool 4 Top Pool 5 Top Pool 6 Top Upper Beluga Top Middle Beluga Top Lower Beluga Top Upper Tyonek Top Tyonek D1 TD: Tyonek D5 Hilcorp Alaska, LLC Calculation Method:Minimum Curvature Error System:ISCWSA Scan Method: Closest Approach 3D Error Surface: Ellipsoid Separation Warning Method: Error Ratio WELL DETAILS: Plan: KU 34-05 65.60 +N/-S +E/-W Northing Easting Latitude Longitude 0.00 0.00 2361383.10 275024.60 60° 27' 28.0804 N 151° 14' 46.6212 W SURVEY PROGRAM Date: 2024-04-03T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 18.00 1515.00 KU 34-05 wp04 (KU 34-05) 3_MWD+IFR1+MS+Sag 1515.00 7310.00 KU 34-05 wp04 (KU 34-05) 3_MWD+IFR1+MS+Sag 7310.00 10926.88 KU 34-05 wp04 (KU 34-05) 3_MWD+IFR1+MS+Sag FORMATION TOP DETAILS TVDPath TVDssPath MDPath Formation 3334.60 3251.00 3889.65 Top Pool 3_A6 3843.60 3760.00 4580.51 Top Pool 4 3968.60 3885.00 4750.17 Top Pool 5 4520.60 4437.00 5499.39 Top Pool 6 4756.60 4673.00 5819.71 Top Upper Beluga 5392.60 5309.00 6651.63 Top Middle Beluga 6153.60 6070.00 7463.17 Top Lower Beluga 7229.60 7146.00 8549.74 Top Upper Tyonek 8720.60 8637.00 10055.39 Top Tyonek D1 9487.60 9404.00 10829.93 TD: Tyonek D5 REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: KU 34-05, True North Vertical (TVD) Reference:Permit RKB @ 83.60usft Measured Depth Reference:Permit RKB @ 83.60usft Calculation Method: Minimum Curvature Project:Kenai Gas Field Site:KGF 41-7 Pad Well:Plan: KU 34-05 Wellbore:KU 34-05 Design:KU 34-05 wp04 CASING DETAILS TVD TVDSS MD Size Name 1500.00 1416.40 1514.80 10-3/4 10 3/4" Casing 6000.00 5916.40 7307.44 7-5/8 7 5/8" Casing 9583.60 9500.00 10926.88 4-1/2 4 1/2" Casing SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 18.00 0.00 0.00 18.00 0.00 0.00 0.00 0.00 0.00 2 650.00 0.00 0.00 650.00 0.00 0.00 0.00 0.00 0.00 Start Dir 2º/100' : 650' MD, 650'TVD 3 1250.00 12.00 70.00 1245.62 21.41 58.83 2.00 70.00 62.59 Start Dir 3º/100' : 1250' MD, 1245.62'TVD 4 2268.22 42.54 68.86 2139.99 185.65 489.62 3.00 -1.51 523.63 End Dir : 2268.22' MD, 2139.99' TVD 5 6276.37 42.54 68.86 5093.05 1162.92 3017.39 0.00 0.00 3233.74 Start Dir 3º/100' : 6276.37' MD, 5093.05'TVD 6 7427.82 8.00 68.62 6118.60 1337.84 3468.85 3.00 -179.94 3717.89 KU 34-05 tgt1 End Dir : 7427.82' MD, 6118.6' TVD 7 10926.88 8.00 68.62 9583.60 1515.37 3922.31 0.00 0.00 4204.85 Total Depth : 10926.88' MD, 9583.6' TVD -6 7 5 -4 5 0 -2 2 5 0 22 5 45 0 67 5 90 0 11 2 5 13 5 0 15 7 5 18 0 0 20 2 5 22 5 0 South(-)/North(+) (450 usft/in) -2 2 5 0 2 2 5 4 5 0 6 7 5 9 0 0 1 1 2 5 1 3 5 0 1 5 7 5 1 8 0 0 2 0 2 5 2 2 5 0 2 4 7 5 2 7 0 0 2 9 2 5 3 1 5 0 3 3 7 5 3 6 0 0 3 8 2 5 4 0 5 0 We s t ( - ) / E a s t ( + ) ( 4 5 0 u s f t / i n ) KU 3 4 - 0 5 t g t 1 10 3 / 4 " C a s i n g 7 5 / 8 " C a s i n g 4 1 / 2 " C a s i n g 25 0 50 0 7 5 0100 01250 1 5 0 0 1 7 5 0 2 0 0 0 2 2 5 0 2 5 0 0 2 7 5 0 3 0 0 0 3 2 5 0 3 5 0 0 3 7 5 0 4 0 0 0 4 2 5 0 4 5 0 0 4 7 5 0 5 0 0 0 5 2 5 0 5 5 0 0 5 7 5 0 6 0 0 0625065006750700072507500775080008250850087509000925095009584 K U 3 4 -0 5 w p 0 4 St a r t D i r 2 º / 1 0 0 ' : 6 5 0 ' M D , 6 5 0 ' T V D St a r t D i r 3 º / 1 0 0 ' : 1 2 5 0 ' M D , 1 2 4 5 . 6 2 ' T V D En d D i r : 2 2 6 8 . 2 2 ' M D , 2 1 3 9 . 9 9 ' T V D St a r t D i r 3 º / 1 0 0 ' : 6 2 7 6 . 3 7 ' M D , 5 0 9 3 . 0 5 ' T V D En d D i r : 7 4 2 7 . 8 2 ' M D , 6 1 1 8 . 6 ' T V D To t a l D e p t h : 1 0 9 2 6 . 8 8 ' M D , 9 5 8 3 . 6 ' T V D CA S I N G D E T A I L S TV D TV D S S M D Si z e N a m e 15 0 0 . 0 0 1 4 1 6 . 4 0 1 5 1 4 . 8 0 1 0 - 3 / 4 1 0 3 / 4 " C a s i n g 60 0 0 . 0 0 5 9 1 6 . 4 0 7 3 0 7 . 4 4 7 - 5 / 8 7 5 / 8 " C a s i n g 95 8 3 . 6 0 9 5 0 0 . 0 0 1 0 9 2 6 . 8 8 4 - 1 / 2 4 1 / 2 " C a s i n g Pr o j e c t : K e n a i G a s F i e l d Si t e : K G F 4 1 - 7 P a d We l l : P l a n : K U 3 4 - 0 5 We l l b o r e : K U 3 4 - 0 5 Pl a n : K U 3 4 - 0 5 w p 0 4 WE L L D E T A I L S : P l a n : K U 3 4 - 0 5 65 . 6 0 +N / - S + E / - W No r t h i n g Ea s t i n g La t i t u d e Lo n g i t u d e 0. 0 0 0 . 0 0 23 6 1 3 8 3 . 1 0 2 7 5 0 2 4 . 6 0 6 0 ° 2 7 ' 2 8 . 0 8 0 4 N 1 5 1 ° 1 4 ' 4 6 . 6 2 1 2 W RE F E R E N C E I N F O R M A T I O N Co - o r d i n a t e ( N / E ) R e f e r e n c e : We l l P l a n : K U 3 4 - 0 5 , T r u e N o r t h Ve r t i c a l ( T V D ) R e f e r e n c e : Pe r m i t R K B @ 8 3 . 6 0 u s f t Me a s u r e d D e p t h R e f e r e n c e : Pe r m i t R K B @ 8 3 . 6 0 u s f t Ca l c u l a t i o n M e t h o d : Mi n i m u m C u r v a t u r e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" ) + ) ' ( . " ) + ) ' ( . " ) + %+ & 0 . / " 0 & + 1 % & 0 " / . & / / 0 & / + /" 0 & + 1 2 ) '( . " ) + ) ' ( . " ) + ) ' ( . " ) + %+ & 0 % / % & % & + 0 / 0 & + 0 & / % / % & ) '( . " ) + ) ' ( . " ) + ) ' ( . " ) + 1 & + / / % & % . & . / / + & . 0 & . / . // % & 2 ) '( . - ) / ) ' ( . - ) / ) ' ( . - ) / %+ & + " 3 / 1 & % % . - & % % " 3 " " - & / % - & + % 1 "3 / 1 & % % 2 ) ( # $ % ! & ! % ! & ' . ( / > . ( / - @ # - > "+ & " 3 % & ' ( - . ) % . - 7 8 9 ! " ! 8 ! : "3 % " % & " 3 % & ' ( - . ) % . - 7 8 9 ! " ! 8 ! : /3 - " & " 3 0 1 & + + ' ( - . ) % . - 7 8 9 ! " ! 8 ! : ; < = > ) & < ? & 2 < < $ & 2 @ $ # * $ ) , & : ? ? & < < : 8 ; < ; 2 < = < ; & 0. 0 0 0. 7 5 1. 5 0 2. 2 5 3. 0 0 Separation Factor 0 6 0 0 1 2 0 0 1 8 0 0 2 4 0 0 3 0 0 0 3 6 0 0 4 2 0 0 4 8 0 0 5 4 0 0 6 0 0 0 6 6 0 0 7 2 0 0 7 8 0 0 8 4 0 0 9 0 0 0 9 6 0 0 1 0 2 0 0 1 0 8 0 0 1 1 4 0 0 Me a s u r e d D e p t h ( 1 2 0 0 u s f t / i n ) KB U 1 1 - 8 Y KD U 0 2 ( 2 1 - 8 ) No - G o Z o n e - S t o p D r i l l i n g Co l l i s i o n A v o i d a n c e R e q u i r e d Co l l i s i o n R i s k P r o c e d u r e s R e q . NO E R R O R S WE L L D E T A I L S : P l a n : K U 3 4 - 0 5 N A D 1 9 2 7 ( N A D C O N C O N U S ) A l a s k a Z o n e 0 4 65 . 6 0 +N / - S +E / - W N o r t h i n g Ea s t i n g La t i t u d e L o n g i t u d e 0. 0 0 0. 0 0 23 6 1 3 8 3 . 1 0 2 7 5 0 2 4 . 6 0 6 0 ° 2 7 ' 2 8 . 0 8 0 4 N 1 5 1 ° 1 4 ' 4 6 . 6 2 1 2 W RE F E R E N C E I N F O R M A T I O N Co - o r d i n a t e ( N / E ) R e f e r e n c e : We l l P l a n : K U 3 4 - 0 5 , T r u e N o r t h Ve r t i c a l ( T V D ) R e f e r e n c e : P e r m i t R K B @ 8 3 . 6 0 u s f t Me a s u r e d D e p t h R e f e r e n c e : Pe r m i t R K B @ 8 3 . 6 0 u s f t Ca l c u l a t i o n M e t h o d : Mi n i m u m C u r v a t u r e CA S I N G D E T A I L S TV D T V D S S M D S i z e N a m e 15 0 0 . 0 0 1 4 1 6 . 4 0 1 5 1 4 . 8 0 1 0 - 3 / 4 1 0 3 / 4 " C a s i n g 60 0 0 . 0 0 5 9 1 6 . 4 0 7 3 0 7 . 4 4 7 - 5 / 8 7 5 / 8 " C a s i n g 95 8 3 . 6 0 9 5 0 0 . 0 0 1 0 9 2 6 . 8 8 4 - 1 / 2 4 1 / 2 " C a s i n g SU R V E Y P R O G R A M Da t e : 2 0 2 4 - 0 4 - 0 3 T 0 0 : 0 0 : 0 0 V a l i d a t e d : Y e s V e r s i o n : De p t h F r o m D e p t h T o Su r v e y / P l a n To o l 18 . 0 0 1 5 1 5 . 0 0 K U 3 4 - 0 5 w p 0 4 ( K U 3 4 - 0 5 ) 3 _ M W D + I F R 1 + M S + S a g 15 1 5 . 0 0 7 3 1 0 . 0 0 K U 3 4 - 0 5 w p 0 4 ( K U 3 4 - 0 5 ) 3 _ M W D + I F R 1 + M S + S a g 73 1 0 . 0 0 1 0 9 2 6 . 8 8 K U 3 4 - 0 5 w p 0 4 ( K U 3 4 - 0 5 ) 3 _ M W D + I F R 1 + M S + S a g 0. 0 0 40 . 0 0 80 . 0 0 12 0 . 0 0 16 0 . 0 0 20 0 . 0 0 Centre to Centre Separation (80.00 usft/in) 60 0 1 2 0 0 1 8 0 0 2 4 0 0 3 0 0 0 3 6 0 0 4 2 0 0 4 8 0 0 5 4 0 0 6 0 0 0 6 6 0 0 7 2 0 0 7 8 0 0 8 4 0 0 9 0 0 0 9 6 0 0 1 0 2 0 0 1 0 8 0 0 1 1 4 0 0 Me a s u r e d D e p t h ( 1 2 0 0 u s f t / i n ) KU 1 4 - 0 5 KU 1 4 - 0 5 KB U 1 1 - 8 Y KB U 3 1 - 0 6 X KU 4 1 - 0 8 KB U 1 1 - 0 8 Z KU 2 4 - 0 5 B KU 2 4 - 0 5 B KD U 1 0 KU 4 3 - 7 GL O B A L F I L T E R A P P L I E D : A l l w e l l p a t h s w i t h i n 2 0 0 ' + 1 0 0 / 1 0 0 0 o f r e f e r e n c e 18 . 0 0 T o 1 0 9 2 6 . 8 8 Pr o j e c t : K e n a i G a s F i e l d Si t e : K G F 4 1 - 7 P a d We l l : P l a n : K U 3 4 - 0 5 We l l b o r e : K U 3 4 - 0 5 Pl a n : K U 3 4 - 0 5 w p 0 4 La d d e r / S . F . P l o t s CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From:Sean McLaughlin To:McLellan, Bryan J (OGC) Cc:Dewhurst, Andrew D (OGC); Roby, David S (OGC) Subject:RE: [EXTERNAL] KU 34-05 PTD questions Date:Tuesday, April 23, 2024 9:25:34 AM Bryan, Loss circulation will remain a risk on future KGF wells. If loss circulation occurs fluid will be pumped into the well, followed by LCM, then cement if necessary. It is the same practice we have used for Beluga River and Tyonek drilling. The response differs from KU 33-08 in that we will not proactively shut a preventor. The shutting of the preventor caused the stuck pipe, not the loss circulation. There were no differences between the KU 33-08 redrill and the plugback other than the 68’ of separation. In both cases we adhered to our best practices while drilling low EDC, background LCM, Black products, and control drilling. Losses occurred while drilling ahead and was not the result of back reaming or pump control after a connection. Regards, sean From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Tuesday, April 23, 2024 8:34 AM To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Roby, David S (OGC) <dave.roby@alaska.gov> Subject: RE: [EXTERNAL] KU 34-05 PTD questions Sean, I’m not understanding your contingency for lost circulation to avoid a repeat of KU 33-08. Please explain how Hilcorp plans to react to a complete loss of returns when drilling into Pool 6, and how that differs from the response on KU 33-08? On the preventative side, was there a difference in drilling practices that allowed Hilcorp to re-drill KU 33-08 without losses after experiencing complete losses on KU 33-08PB1? What was different? Thank you Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Monday, April 22, 2024 1:42 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Roby, David S (OGC) <dave.roby@alaska.gov> Subject: RE: [EXTERNAL] KU 34-05 PTD questions Bryan, There is no plan to drill ahead without fluid to surface. Hilcorp will continuously fill the hole in attempt to keep it full. The rig had 200 bbls more mud than what is typical during the KU 33-08 pool 6 redrill. This mud was in an upright tank so volume could be added if needed. We were planning on the same configuration for future KGF wells, until the LC risk is better understood. sean From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Monday, April 22, 2024 1:14 PM To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Roby, David S (OGC) <dave.roby@alaska.gov> Subject: RE: [EXTERNAL] KU 34-05 PTD questions Sean, Is Hilcorp planning to drill ahead with complete losses and without fluid level at surface? Will Hilcorp have excess mud on location and ability to replace it at a rate sufficient to keep the hole full until the losses can be cured? Bryan McLellan 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. Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Monday, April 22, 2024 11:24 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Roby, David S (OGC) <dave.roby@alaska.gov> Subject: RE: [EXTERNAL] KU 34-05 PTD questions Bryan, Losses did not occur during drilling though pool 6 on the two previous KGF wells, nor did it occur during the redrilling of KU 33-08 (68’ away). We are looking at a 25% change of losses with the current data set. On KU 33-08, the stuck pipe event was due to closing the BOPE as a preventative measure. In the future, the BOPE equipment will be left open and the hole fill will be controlled. Dump flooding the reservoir at 300 barrels per hour has little value. The focus will be to feed the well at a minimum of 2000ft/hr to stay ahead of the gas migration rate. On KU 33-08, this would have doubled the fill time. The KU 33-08 intermediate section had been redrilled and cemented. No losses occurred while drilling using the same mud system, ECD’s, and drilling parameters. The casing was cemented this morning. I know we got 40 bbls of cement to surface but haven’t got the loss volume yet (if any). We will move to KU 34-05 around May 1st if road restriction prevent rig 169 from moving to CLU-16. Regards, sean From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Monday, April 22, 2024 10:07 AM To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Roby, David S (OGC) <dave.roby@alaska.gov> Subject: [EXTERNAL] KU 34-05 PTD questions Sean, I’ve reviewed the PTD application for KU 34-05. After this application was submitted, Hilcorp encountered a major difficulty on the offset well KU 33-08 including sticking the drillstring and abandoning the wellbore while leaving multiple pools uncemented. The plans for these two wells and the lithology look nearly identical, including penetrating the severely depleted gas storage pool that led to the problems. What will Hilcorp do differently to avoid a repeat of the experience on KU 33-08? Please provide an update on the status of the KU 33-08 redrill of the Intermediate hole section? Was Hilcorp able to drill, case, cement the intermediate hole section without incident? What is your anticipated spud date for KU 34-05? Thank you Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the 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. 224-027 KU 34-05 TYONEK GAS 1KENAI EC K L I S T pa n y Hi l c o r p A l a s k a , L L C We l l N a m e : KE N A I U N I T 3 4 - 0 5 In i t i a l C l a s s / T y p e DE V / P E N D Ge o A r e a 82 0 Un i t 51 1 2 0 On / O f f S h o r e On Pr o g r a m DE V Fi e l d & P o o l We l l b o r e s An n u l a r D i s KE N A I , T Y O N E K G A S - 4 4 8 5 7 0 NA Pe r m i t f e e a t t a c h e d Ye s F E E A 0 2 8 1 4 2 Le a s e n u m b e r a p p r o p r i a t e Ye s Un i q u e w e l l n a m e a n d n u m b e r Ye s K E N A I , T Y O N E K G A S 1 - 4 4 8 5 7 0 - g o v e r n e d b y 5 1 0 B We l l l o c a t e d i n a d e f i n e d p o o l Ye s We l l l o c a t e d p r o p e r d i s t a n c e f r o m d r i l l i n g u n i t b o u n d a r y NA We l l l o c a t e d p r o p e r d i s t a n c e f r o m o t h e r w e l l s Ye s Su f f i c i e n t a c r e a g e a v a i l a b l e i n d r i l l i n g u n i t Ye s If d e v i a t e d , i s w e l l b o r e p l a t i n c l u d e d Ye s Op e r a t o r o n l y a f f e c t e d p a r t y Ye s 0 Op e r a t o r h a s a p p r o p r i a t e b o n d i n f o r c e Ye s Pe r m i t c a n b e i s s u e d w i t h o u t c o n s e r v a t i o n o r d e r Ye s 2 Pe r m i t c a n b e i s s u e d w i t h o u t a d m i n i s t r a t i v e a p p r o v a l Ye s 3 Ca n p e r m i t b e a p p r o v e d b e f o r e 1 5 - d a y w a i t NA 4 We l l l o c a t e d w i t h i n a r e a a n d s t r a t a a u t h o r i z e d b y I n j e c t i o n O r d e r # ( p u t I O # i n c o m m e n t s ) ( F o r s e r v NA 5 Al l w e l l s w i t h i n 1 / 4 m i l e a r e a o f r e v i e w i d e n t i f i e d ( F o r s e r v i c e w e l l o n l y ) NA 6 Pr e - p r o d u c e d i n j e c t o r : d u r a t i o n o f p r e - p r o d u c t i o n l e s s t h a n 3 m o n t h s ( F o r s e r v i c e w e l l o n l y ) NA 7 No n c o n v e n . g a s c o n f o r m s t o A S 3 1 . 0 5 . 0 3 0 ( j . 1 . A ) , ( j . 2 . A - D ) Ye s 8 C o n d u c t o r s t r i n g p r o v i d e d Ye s 9 Su r f a c e c a s i n g p r o t e c t s a l l k n o w n U S D W s Ye s 0 CM T v o l a d e q u a t e t o c i r c u l a t e o n c o n d u c t o r & s u r f c s g Ye s P r o d u c t i o n c a s i n g C e m e n t w i l l b e p l a c e d ~ 5 0 0 ' i n t o s u r f a c e c a s i n g ( 1 0 0 0 ' f r o m s u r f a c e ) CM T v o l a d e q u a t e t o t i e - i n l o n g s t r i n g t o s u r f c s g Ye s 2 CM T w i l l c o v e r a l l k n o w n p r o d u c t i v e h o r i z o n s Ye s 3 Ca s i n g d e s i g n s a d e q u a t e f o r C , T , B & p e r m a f r o s t Ye s 4 Ad e q u a t e t a n k a g e o r r e s e r v e p i t NA 5 If a r e - d r i l l , h a s a 1 0 - 4 0 3 f o r a b a n d o n m e n t b e e n a p p r o v e d Ye s 6 Ad e q u a t e w e l l b o r e s e p a r a t i o n p r o p o s e d NA D i v e r t e r w a i v e r a p p r o v e d . S e e p a g e # 1 0 o f P T D a p p l i c a t i o n p a c k a g e f o r j u s t i f i c a t i o n . 7 If d i v e r t e r r e q u i r e d , d o e s i t m e e t r e g u l a t i o n s Ye s 8 Dr i l l i n g f l u i d p r o g r a m s c h e m a t i c & e q u i p l i s t a d e q u a t e Ye s 9 BO P E s , d o t h e y m e e t r e g u l a t i o n Ye s M P S P = 3 4 5 1 p s i , B O P r a t e d t o 5 k p s i ( B O P t e s t t o 3 5 0 0 p s i ) 0 BO P E p r e s s r a t i n g a p p r o p r i a t e ; t e s t t o ( p u t p s i g i n c o m m e n t s ) Ye s Ch o k e m a n i f o l d c o m p l i e s w / A P I R P - 5 3 ( M a y 8 4 ) Ye s 2 Wo r k w i l l o c c u r w i t h o u t o p e r a t i o n s h u t d o w n No 3 Is p r e s e n c e o f H 2 S g a s p r o b a b l e NA 4 Me c h a n i c a l c o n d i t i o n o f w e l l s w i t h i n A O R v e r i f i e d ( F o r s e r v i c e w e l l o n l y ) Ye s H 2 S n o t a n t i c i p a t e d b a s e d o n o f f s e t w e l l s . 5 Pe r m i t c a n b e i s s u e d w / o h y d r o g e n s u l f i d e m e a s u r e s Ye s O v e r p r e s s u r e ( 1 0 . 2 p p g E M W ) a n t i c i p a t e d i n T y o n e k . S e v e r a l i n t e r v a l s o f s e v e r l e y u n d e r p r e s s u r e i n 6 Da t a p r e s e n t e d o n p o t e n t i a l o v e r p r e s s u r e z o n e s NA 7 Se i s m i c a n a l y s i s o f s h a l l o w g a s z o n e s NA 8 Se a b e d c o n d i t i o n s u r v e y ( i f o f f - s h o r e ) NA 9 Co n t a c t n a m e / p h o n e f o r w e e k l y p r o g r e s s r e p o r t s [ e x p l o r a t o r y o n l y ] Da t e : En g i n e e r i n g Co m m i s s i o n e r : Da t e Pu b l i c Co m m i s s i o n e r Da t e St e r l i n g G a s P o o l s 2 a n d 6 s e v e r e l y u n d e r p r e s s u r e d ( 1 . 7 3 a n d 0 . 7 7 p p g E M W ) *& :
