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Home My WebLink About224-1537. Property Designation (Lease Number): 1. Operations Performed: 2. Operator Name: 3. Address: 4. Well Class Before Work:5. Permit to Drill Number: 6. API Number: 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): Susp Well Insp Install Whipstock Mod Artificial Lift Perforate New Pool Perforate Plug Perforations Coiled Tubing Ops Other Stimulate Fracture Stimulate Alter Casing Pull Tubing Repair Well Other: Change Approved Program Operations shutdown 11. Present Well Condition Summary: Casing Length Size MD TVD Burst Collapse Exploratory Stratigraphic Development Service 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 16. Well Status after work: 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. OIL GAS WINJ WAG GINJ WDSPL GSTOR Suspended SPLUG Authorized Name and Digital Signature with Date: Authorized Title: Contact Name: Contact Email: Contact Phone: PBU NK-41B Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 224-153 50-029-22778-02-00 14578 Conductor Surface Intermediate Production Liner 6806 80 4158 14100 12936 20" 13-3/8" 9-5/8" 6369 47 - 127 47 - 4205 45 - 14145 47 - 127 47 - 3927 45 - 6692 None 520 2260 4760 12936, 13747, 13791 1530 5020 6870 None 4-1/2" 12.6# L-80 43 - 2622 Structural No Packer N/A N/A Bo York Operations Manager Andy Ogg andrew.ogg@hilcorp.com 907-659-5102 Prudhoe Bay, Sag River Undefined Oil Total Depth Effective Depth measured true vertical feet feet feet feet measured true vertical measured measured feet feet feet feet measured true vertical Plugs Junk Packer Measured depth True Vertical depth feet feet Perforation depth Tubing (size, grade, measured and true vertical depth) Packers and SSSV (type, measured and true vertical depth) 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13a.Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: Subsequent to operation: 15. Well Class after work: Exploratory Development Service StratigraphicDaily Report of Well Operations Copies of Logs and Surveys Run Electronic Fracture Stimulation Data Sundry Number or N/A if C.O. Exempt: ADL 034630, 034634, 034635 43 - 2615 N/A N/A 0 0 0 0 0 0 350 0 0 0 N/A 13b. Pools active after work:Sag River Undefined Oil No SSSV Installed STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS Sr Pet Eng: Sr Pet Geo: Form 10-404 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov Sr Res Eng: Due Within 30 days of Operations By Grace Christianson at 3:30 pm, Jul 24, 2025 Digitally signed by Bo York (1248) DN: cn=Bo York (1248) Date: 2025.07.24 15:10:26 - 08'00' Bo York (1248) DSSR-7/24/25 RBDMS JSB 073125 JJL 8/12/25 ACTIVITY DATE SUMMARY 7/5/2025 T/I/O = 0/0/100. Temp = SI. Suspended well inspection (AOGCC witnessed by Guy Cook). Dry hole tree installed. No AL or Flowline. Plywood flooring covering cellar. Ground water in cellar appears to have no sheens. Tree is clean. Open excavation sign in front of well. SV = C. MV = O. IA,OA = OTG. 10:00 Daily Report of Well Operations PBU NK-41B NK-41B Suspended Well Inspection Review Report Reviewed By: P.I. Suprv Comm ________ JBR 08/05/2025 InspectNo:susGDC250706221323 Well Pressures (psi): Date Inspected:7/5/2025 Inspector:Guy Cook If Verified, How?Other (specify in comments) Suspension Date:3/26/2025 #325-133 Tubing:0 IA:0 OA:100 Operator:Hilcorp North Slope, LLC Operator Rep:Andy Ogg Date AOGCC Notified:6/27/2025 Type of Inspection:Initial Well Name:PRUDHOE BAY UN NIA NK-41B Permit Number:2241530 Wellhead Condition The wellhead is in good condition but at this time no protection from the elements. Old and new wellhead parts combined with a double swab set-up on top of the tubing hanger adapter. Surrounding Surface Condition Clean gravel from what can be seen. Plywood and pit liner present obstructing the view of the pad immediately outside the cellar. Condition of Cellar Fluid in the cellar appears to be snow melt/rainwater (no shen). Appears to be drilling mud and pit liner in cellar. Timbers and plywood nailed together preventing a better look into the cellar. Comments Location of the well was verified with a pad map. Supervisor Comments Photos (7) Suspension Approval:Sundry Location Verified? Offshore? Fluid in Cellar? Wellbore Diagram Avail? Photos Taken? VR Plug(s) Installed? BPV Installed? Tuesday, August 5, 2025          jbr 2025-0705_Suspend_PBU_NK-41B_photos_gc Page 1 of 4 Suspended Well Inspection – PBU NK-41B PTD 2241530 AOGCC Inspection Rpt # susGDC250706221323 Photos by AOGCC Inspector G. Cook 7/5/2025 2025-0705_Suspend_PBU_NK-41B_photos_gc Page 2 of 4 Well cellar 2025-0705_Suspend_PBU_NK-41B_photos_gc Page 3 of 4 Tubing pressure gauge IA pressure gauge 2025-0705_Suspend_PBU_NK-41B_photos_gc Page 4 of 4 OA pressure gauge STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________PRUDHOE BAY UN NIA NK-41B JBR 04/29/2025 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:0 Parker 273 Did not complete the well and is running a 4 1/2" kill string. The smallest pipe size tested on the last BOPE test was 5". They are not due until 3-27-25 for full BOPE test. This test reflects the testing of the annular, Upper Rams, 4-1/2"TIW, Man. Choke and Man. Kill. I also had them perform a drawdown while on location. All were tested with 4-1/2" test joint. Test Results TEST DATA Rig Rep:Oliver AmendOperator:Hilcorp North Slope, LLC Operator Rep:Ben Herbert Rig Owner/Rig No.:Parker 273 PTD#:2241530 DATE:3/24/2025 Type Operation:DRILL Annular: 250/3500Type Test:OTH Valves: 250/4500 Rams: 250/4500 Test Pressures:Inspection No:bopSTS250324102522 Inspector Sully Sullivan Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 1 MASP: 3958 Sundry No: Control System Response Time (sec) Time P/F Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Hazard Sec.P Test Fluid W Misc NA Upper Kelly 1 NT Lower Kelly 1 NT Ball Type 1 P Inside BOP 1 NT FSV Misc 0 NA 15 NTNo. Valves 1 NTManual Chokes 1 NTHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 13-5/8"P #1 Rams 1 2-7/8"x5"P #2 Rams 1 blinds NT #3 Rams 1 2-7/8"x5"NT #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 3-1/8"P HCR Valves 2 3-1/8"NT Kill Line Valves 1 3-1/8"P Check Valve 0 NA BOP Misc 0 NA System Pressure P3000 Pressure After Closure P1980 200 PSI Attained P16 Full Pressure Attained P69 Blind Switch Covers:Pall stations Bottle precharge P Nitgn Btls# &psi (avg)P14@2150 ACC Misc NA0 NT NTTrip Tank NT NTPit Level Indicators NT NTFlow Indicator NT NTMeth Gas Detector NT NTH2S Gas Detector NA NAMS Misc Inside Reel Valves 0 NA Annular Preventer P26 #1 Rams P6 #2 Rams P6 #3 Rams P6 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P1 HCR Kill P2 9 9 9 9 9999 9 This test reflects the testing of the annular, Upper Rams, 4-1/2"TIW, Man. Choke and Man. Kill. MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: P.I. Supervisor SUBJECT: FROM: Petroleum Inspector Section: 36 Township: 12N Range: 15E Meridian: Umiat Drilling Rig: Parker 273 Rig Elevation: 45.74 ft Total Depth:14575 ft MD Lease No.: ADL 034630 Operator Rep: Suspend: X P&A: Conductor: 20" O.D. Shoe@ 127 Feet Csg Cut@ Feet Surface: 13 3/8" O.D. Shoe@ 4205 Feet Csg Cut@ Feet Intermediate: 9 5/8" O.D. Shoe@ 14144 Feet Csg Cut@ Feet Production: na O.D. Shoe@ na Feet Csg Cut@ Feet Liner: na O.D. Shoe@ na Feet Csg Cut@ Feet Tubing: na O.D. Tail@ na Feet Tbg Cut@ Feet Type Plug Founded on Depth (Btm) Depth (Top) MW Above Verified Fullbore Retainer 13,747 ft 12,936 ft 10.3 ppg Wireline tag Initial 15 min 30 min 45 min Result 9-5/8" Tubing 2160 2140 2130 IA OA 260 240 240 Initial 15 min 30 min 45 min Result Tubing IA OA Remarks: Attachments: This report reflects the Initial cement plug for the suspension of NK-41B. The top of the 9 5/8-inch casing window for redrill is at 14125 ft MD with a cement retainer set at 13,747 ft. They tagged cement on top of the retainer twice with 20k lbs down weight @ 12,936 ft MD March 24, 2025 Sully Sullivan Well Bore Plug & Abandonment PBU NK-41B Hilcorp Alaska LLC PTD 2241530; Sundry 325-156 none Test Data: P Casing Removal: Brian Lafleur Casing/Tubing Data (depths are MD): Plugging Data (depths are MD): rev. 3-24-2022 2025-0324_Plug_Verification_PBU_NK-41B_ss 9 9 9 9 9 9 999 9 9 9 9 9 9 9 99 9 9 9 9 James B. Regg Digitally signed by James B. Regg Date: 2025.04.28 12:42:08 -08'00' David Douglas Hilcorp North Slope, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Hilcorp North Slope, LLC Date: 04/09/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL: PBU NK-41B + PB1 + PB2 PTD: 224-153 API: 50-029-22778-02-00 (PBU NK-41B) API: 50-029-22778-02-73 (PBU NK-41BPB1) API: 50-029-22778-02-74 (PBU NK-41BPB2) FINAL LWD FORMATION EVALUATION LOGS (02/02/2025 to 03/04/2025) x BaseStar, DGR & ABG Gamma Ray, ResiStar & M5-EWR Resistivity (2” & 5” MD/TVD Color Logs) x Final Definitive Directional Survey SFTP Transfer – Main Folders: PBU NK-41B + PB1 + PB2 LWD Subfolders: Please include current contact information if different from above. T40284 T40285 T40286 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.04.10 08:17:41 -08'00' From:Lau, Jack J (OGC) To:AOGCC Records (CED sponsored) Subject:FW: [EXTERNAL] Re: NK-41B Forward Plan UPDATE: Drillstring/Stinger at Surface (PTD: 224-153) Date:Sunday, March 23, 2025 10:11:14 AM From: Lau, Jack J (OGC) Sent: Sunday, March 23, 2025 10:02 AM To: Frank Roach <Frank.Roach@hilcorp.com> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: RE: [EXTERNAL] Re: NK-41B Forward Plan UPDATE: Drillstring/Stinger at Surface (PTD: 224- 153) Frank – You are approved for the alternate plan to set and test a bridge plug, followed by a cement on the plug as outlines below. Please give the AOGCC inspector and opportunity to witness the PT and Tag of TOC. Thanks Jack From: Frank Roach <Frank.Roach@hilcorp.com> Sent: Saturday, March 22, 2025 6:39 PM To: Lau, Jack J (OGC) <jack.lau@alaska.gov> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: RE: [EXTERNAL] Re: NK-41B Forward Plan UPDATE: Drillstring/Stinger at Surface (PTD: 224- 153) Jack, Good evening. I just left a message on your phone and sending this email to bump this to the top of your inbox. Repeating the note below: We are out of the hole with the stinger. The retainer is compromised as we also retrieved the inner sleeve that’s supposed to still be in the retainer downhole (explains why we couldn’t get circulation through the drillpipe). With the compromised retainer below us and the inability to get the retainer down to our desired depth, we propose abandonment of the lower section of the well as follows: RIH with a bridge plug and set in the joint above where the retainer is set (retainer is set at 13,791’ mid-element. Plan to set bridge plug at ~13,750’ mid-element). Once bridge plug is set, confirm set with weight and pressure. Pick up above the bridge plug and pump the planned 50 bbls cement as a balanced plug. Once spotted, pull out of balanced plug, plus 5 stands to ensure clearance from cement top. Circulate to clean up drillpipe. POOH & LD bridge plug running tool. Back on plan at 17.7 (attached program is the same as what I sent you on 3/20, but with a red line between steps 17.6 and 17.7, noting where we get back on plan). Let me know if you have any questions or need anything additional. Regards, Frank V Roach Drilling Engineer Hilcorp Alaska, LLC 907.854.2321 mobile 907.777.8413 office From: Frank Roach Sent: Saturday, March 22, 2025 12:01 PM To: Lau, Jack J (OGC) <jack.lau@alaska.gov> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: RE: [EXTERNAL] Re: NK-41B Forward Plan: Attempting to Establish Injection Below Retainer (PTD: 224-153) Jack, Apologies, I had a typo on my bridge plug depth. That should read 13,750’. Corrected below in bold. Regards, Frank V Roach Drilling Engineer Hilcorp Alaska, LLC 907.854.2321 mobile 907.777.8413 office From: Frank Roach <Frank.Roach@hilcorp.com> Sent: Saturday, March 22, 2025 10:07 AM To: Lau, Jack J (OGC) <jack.lau@alaska.gov> Subject: RE: [EXTERNAL] Re: NK-41B Forward Plan: Attempting to Establish Injection Below Retainer (PTD: 224-153) Jack, We are out of the hole with the stinger. The retainer is compromised as we also retrieved the inner sleeve that’s supposed to still be in the retainer downhole (explains why we couldn’t get circulation through the drillpipe). With the compromised retainer below us and the inability to get the retainer down to our desired depth, we propose abandonment of the lower section of the well as follows: RIH with a bridge plug and set in the joint above where the retainer is set (retainer is set at 13,791’ mid-element. Plan to set bridge plug at ~13,750’ mid-element). Once bridge plug is set, confirm set with weight and pressure. Pick up above the bridge plug and pump the planned 50 bbls cement as a balanced plug. Once spotted, pull out of balanced plug, plus 5 stands to ensure clearance from cement top. Circulate to clean up drillpipe. POOH & LD bridge plug running tool. Back on plan at 17.7 (attached program is the same as what I sent you on 3/20, but with a red line between steps 17.6 and 17.7, noting where we get back on plan). Let me know if you have any questions or need anything additional. Regards, Frank V Roach Drilling Engineer Hilcorp Alaska, LLC 907.854.2321 mobile 907.777.8413 office From: Lau, Jack J (OGC) <jack.lau@alaska.gov> Sent: Saturday, March 22, 2025 9:13 AM To: Frank Roach <Frank.Roach@hilcorp.com> Subject: Re: [EXTERNAL] Re: NK-41B Forward Plan: Attempting to Establish Injection Below Retainer CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. (PTD: 224-153) Thanks for the update Frank. Jack From: Frank Roach <Frank.Roach@hilcorp.com> Sent: Saturday, March 22, 2025 7:48:10 AM To: Lau, Jack J (OGC) <jack.lau@alaska.gov> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: RE: [EXTERNAL] Re: NK-41B Forward Plan: Attempting to Establish Injection Below Retainer (PTD: 224-153) Jack, Thanks for the response. I was writing an update on how things transpired last night when this email arrived in my inbox. We were unable to gain circulation through the drillstring so we are currently pulling to see what we have on the end of the drillstring. We did attempt a pressure test to 2,000psi on the retainer, but it appeared that we were starting to inject at ~1,200psi. The trend was bending over and acting like an FIT into permeable formation. We stopped the pressure test at ~1,740psi and watched the trend for 30 minutes. Pressure bled down and started to stabilize at our previous FIT pressure at 975psi. With the positive set and pressure test on the backside of the retainer right after setting, we believe there is some debris inside the retainer sleeve that is holding it open. Getting out of the hole with the drillstring should give us an indication whether the debris is a damaged stinger or formation/cuttings. Immediate plan forward is to run in with a cleanout assembly with casing scraper and clean up the hole. We’ll see what we get back when circulating, but that will influence our plan forward from there. Let me know if you have any questions. Regards, Frank V Roach Drilling Engineer Hilcorp Alaska, LLC CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 907.854.2321 mobile 907.777.8413 office From: Lau, Jack J (OGC) <jack.lau@alaska.gov> Sent: Saturday, March 22, 2025 7:38 AM To: Frank Roach <Frank.Roach@hilcorp.com> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: [EXTERNAL] Re: NK-41B Forward Plan: Attempting to Establish Injection Below Retainer (PTD: 224-153) Thanks for the detailed verbal and written update Frank. You are approved to move forward with a cement plug of a minimum of 50’ above the cement retainer. I will be in and out of service this afternoon. Thanks Jack From: Frank Roach <Frank.Roach@hilcorp.com> Sent: Friday, March 21, 2025 7:24 PM To: Lau, Jack J (OGC) <jack.lau@alaska.gov> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: RE: NK-41B Forward Plan: Attempting to Establish Injection Below Retainer (PTD: 224-153) Jack, Thank you for the below note. Also, apologies for the late call this evening, but I appreciated the discussion. Recapping our discussion, we did get the retainer set at 13,791’ MD (mid-element). Plug set was confirmed by staking 20k on the plug and also pressuring up to 1,000psi down the drillpipe x 9-5/8” casing annulus. The stinger was then sheared free from the retainer and circulation established above the retainer. The rig then stung back into the retainer and attempted to establish injection below. As we were pressuring up on the drillpipe/stinger, flow was observed on the backside, indicating communication between the stinger and the annulus. We closed around the drillpipe and observed pressures on the backside tracking pressure inside the drillpipe, further indicating we have communication above the retainer. We then unstung from the retainer and was unable to establish circulation. It took a bit to regain circulation as it was assumed we had debris plugging the stinger. Once circulation was reestablished, we attempted to establish injection below the retainer again with the same results (flow/pressure on the backside tracking drillpipe and unable to circulate once unstung from the retainer). These observations are indicating that we are not stinging into the retainer and have damaged the stinger. We are currently attempting to reestablish circulation down the drillpipe/stinger. We’ll work on establishing circulation for a couple more hours. Whether successful or not, we will pressure test the retainer for 30 minutes (closing upper pipe rams and pressuring up on both the drillpipe and the annulus). Once complete, we’ll pull out of the hole to check the stinger. With the challenges of stinging back into the retainer, we will not be able to inject cement below the retainer. With a tested plug (retainer), we would like to pump and spot the planned cement job volume on top of the plug. This would be well over the 50’ of cement required on top of the retainer and would provide a lateral barrier to include the 9-5/8” cement job on 3/12/25. Again, thank you for the discussion and let me know if you need anything additional or if I need to do anything additional. Regards, Frank V Roach Drilling Engineer Hilcorp Alaska, LLC 907.854.2321 mobile 907.777.8413 office CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From: Lau, Jack J (OGC) <jack.lau@alaska.gov> Sent: Friday, March 21, 2025 5:11 PM To: Frank Roach <Frank.Roach@hilcorp.com> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: Re: [EXTERNAL] RE: NK-41B Forward Plan (PTD: 224-153) Frank, You are approved for the modified retainer set depth and cement volume. Jack From: Frank Roach <Frank.Roach@hilcorp.com> Sent: Friday, March 21, 2025 3:05:58 PM To: Lau, Jack J (OGC) <jack.lau@alaska.gov> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: RE: [EXTERNAL] RE: NK-41B Forward Plan (PTD: 224-153) Jack, Appreciate the quick phone call earlier. As we discussed over the phone, we started taking weight (~20k drag) around 13,731’. We made it to 13,810’ and the drag increased to 30k. We then attempted to circulate and started seeing packoffs and overpulls. With the prospect of the cones from our bit below us somewhere, the risk of getting down to 14,050’ is pretty high and could put us in a worse situation. I would like approval to set the retainer at ~13,791’ (mid-element). This puts us away from a collar and gives us a better shot of sealing. With backing up the retainer depth, my cement volume below the retainer increased to 34 bbls. We have 55bbls worth of cement on location so we’ll pump the remaining 21 bbls on top of the retainer. Regards, Frank V Roach Drilling Engineer Hilcorp Alaska, LLC 907.854.2321 mobile CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 907.777.8413 office From: Lau, Jack J (OGC) <jack.lau@alaska.gov> Sent: Friday, March 21, 2025 10:20 AM To: Frank Roach <Frank.Roach@hilcorp.com> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: [EXTERNAL] RE: NK-41B Forward Plan (PTD: 224-153) Frank – You have verbal approval to move forward with the suspension on NK-41B per the procedure sent 3/20/25. Please include the following CoA. AOGCC witnessed tag TOC AOGCC witnessed MIT post cement to 2000 psi Jack From: Frank Roach <Frank.Roach@hilcorp.com> Sent: Friday, March 21, 2025 10:03 AM To: Lau, Jack J (OGC) <jack.lau@alaska.gov> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: RE: NK-41B Forward Plan (PTD: 224-153) Jack, Thanks for the callback and discussion a little while ago. I just talked with Joe over here and the 10-403 should be over there shortly. In the meantime, we would like verbal approval to proceed with the retainer set and cement job per the plan that was sent yesterday. We’re currently in the hole with the retainer, running to set at 14,050’. Let me know if you need anything additional. Thank you, sir. Regards, Frank V Roach Drilling Engineer Hilcorp Alaska, LLC 907.854.2321 mobile 907.777.8413 office From: Frank Roach Sent: Thursday, March 20, 2025 8:08 PM To: Lau, Jack J (OGC) <jack.lau@alaska.gov> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: NK-41B Forward Plan (PTD: 224-153) Jack, Thank you for the phone discussion earlier today about our status with NK-41B. Please see the attached plan to set up the well for suspension as we work out the plan on how to return and make another attempt in the future. This is what we’ll use for the 10-403, but I wanted to get this in front of you ASAP. Let me know if you have any questions or need anything additional. Regards, Frank V Roach Drilling Engineer Hilcorp Alaska, LLC 907.854.2321 mobile 907.777.8413 office 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 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 theonward 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. 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, 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 theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. 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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. UNDEFINED SAG RIVER AND IVISHAK RUSH Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2025.03.21 10:09:44 - 08'00' Sean McLaughlin (4311) 325-156 By Grace Christianson at 1:27 pm, Mar 21, 2025 Jack Lau 03/21/25 DSR-3/28/25 AOGCC witnessed tag TOC AOGCC witnessed MIT post cement to 2000 psi 10-407 JJL 3/21/25 X SFD 3/24/2025*&: April 7, 2030 Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.04.07 16:39:43 -08'00' 04/07/25 RBDMS JSB 040825 17.0 Set 9-5/8” Retainer and Pump Cement Plug 17.1 MU 9-5/8” cement retainer and RIH t/~14,050’. Ensure retainer is spaced out such that it won’t be set across a connection. Set retainer and slack off string weight to confirm retainer is set. 17.2 Establish injection below the retainer. Once pressure breaks over, pump additional 5 bbls to confirm injection. 17.3 Unsting from the retainer and spot 50 bbls 15.8ppg Class G cement within 5 bbls of the end of the stinger. Estimated Total Cement Volume: Cement Slurry Design: 17.4 Once spotted, sting back into the retainer and squeeze 19 bbls below the retainer. 17.5 With 31 bbls left in the workstring/stinger, unsting and spot remaining 31 bbls on top of the retainer. 17.6 Pull up above the cement spotted on top of the retainer and circulate to clean up the string. POOH & LDBHA. 17.7 MU 9-5/8” cleanout assembly (to include 8-1/2” bit). RIH with cleanout assembly to ~180’ (2- stands) above planned TOC. 17.8 Wait on cement to build 500psi compressive strength. Slowly RIH and tag cement on top of retainer. CBU 2-4x while pumping pills/sweeps to help in cleaning the 9-5/8” casing. Ensure fluid is consistent in and out before shutting down. 17.9 RU casing testing equipment and PT 9-5/8” casing to 2,000 psi for 30 min, chart test. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001. x Provide AOGCC inspector 24 hr notice for opportunity to witness pressure test 17.10 RD test equipment. RU and displace drilling mud to 9.8 ppg brine. 17.11 Once clean 9.8 ppg brine is observed in and out, shut down and flow check well. 17.12 POOH & LD cleanout assembly. 17.13 RU test equipment. Install test plug and test annular, upper rams and lower rams with 4-1/2” test joint. 18.0 Run Kill String/ Post Rig Work 18.1 RU to run used 4-1/2” 12.6#, 13Cr-80 Vam Top tubing. x Ensure wear bushing is pulled. x Ensure 4-1/2”, 12.6#, Vam Top x 5-1/2” DELTA 544 crossover is on rig floor and M/U to FOSV. x Ensure all tubing has been drifted in the pipe shed prior to running. x Be sure to count the total # of joints in the pipe shed before running. x Keep hole covered while RU casing tools. x Record OD’s, ID’s, lengths, SN’s of all components with vendor & model info. x Monitor displacement from wellbore while RIH. 18.2 PU, MU and RH with the following 4-1/2” kill string jewelry (tally to be provided by Operations Engineer): x Torque Turn All Connections x Tubing Jewelry to include (top to bottom): x 1x ‘X’ Nipple @ ~2,500’ MD x 1x WLEG x Tubing is 4-1/2”, 12.6#, 13Cr-80, Vam Top 4-1/2” 12.6/# 13Cr-80 Vam Top – Make up Torque Casing OD Minimum Optimum Maximum 4-1/2” 4,000 ft-lbs 4,440 ft-lbs 4,880 ft-lbs 18.3 Run 4-1/2” kill string to ~2,600’. 18.4 MU the tubing hanger and land same. Run in the lock-down screws and torque to spec. 18.5 Install and pressure test TWC from above. 18.6 ND BOPE. NU the tubing head adapter and tree. 18.7 PT the tubing hanger void to 500/5,000 psi. PT the tree to 250/5,000 psi. 18.8 RU lubricator and pull TWC. 18.9 Freeze protect the wellbore. x Rig up to pump heated diesel down the IA, taking returns up the tubing. Reverse 138 bbls heated diesel into the IA. x Shut in the IA. x Line up to U-tube from the IA to the tubing. x U-tube the diesel and freeze protect the tubing and IA to ~2,000’ MD. 18.10 After u-tube is complete, RU lubricator and install BPV. 18.11 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over with valve alignment as per operations personnel. 18.12 RDMO Parker 273. POST RIG WORK 1. Well Site Inspection is required within 12 months of approved 10-403. a. Provide AOGCC inspector 10 days notice before inspection for opportunity to accompany inspection tour. b. Post-inspection 10-404 required within 30 days of inspection. _____________________________________________________________________________________ Created By: FVR 3/20/2025 PROPOSED SCHEMATIC Niakuk Unit Well: NK 41B Last Completed: TBD PTD: 224-153 GENERAL WELL INFO API: 50-029-22778-02-00 Completed: TBD CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5 / X56 / Weld N/A Surface 110’ N/A 13-3/8” Surface 68 / L-80 / BTC 12.415” Surface 4,205’ 0.1497 9-5/8” Intermediate 47 / L-80 / DWC/C 8.681” Surface 14,144’ 0.0758 TUBING DETAIL 4-1/2” Tubing 12.6 / L-80 / VT 3.958” Surface ~2,600’ 0.0152 TD = 14,575’(MD) / TD =6,806’(TVD) 13-3/8” Window @ 4,205’ MD KBElev: =65.14’ /GL Elev: =19.4’ 9-5/8” 1 2 Fish: RCT BHA 14188’ – 14963’ PBTD =13,626’ (MD) / PBTD =6,553(TVD) 4-1/2” 3 PB1: 14150’–15336’ PB2: 12570’ – 15176’ 9-5/8” Window @ 14,108’ MD Tracked PB1: 14,125’ – 14,575’ OPEN HOLE / CEMENT DETAIL Driven 17-1/2” 2038 sx PF E, 54 sx PF C, 1190 sx Class G 12-1/4” Lead –467 sks / Tail –425 sks (pumped on 3/12/2025) JEWELRY DETAIL No Depth ID Item 1 ~14,050’ 9-5/8” cement retainer 2 ~2,600’ 3.813” 4-1/2” WLEG 3 ~2,500’ 3.813” X Nipple WELL INCLINATION DETAIL KOP @ 4,205’ Max Angle 75.58deg @ 5,132’ TREE & WELLHEAD Tree Wellhead 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:Lau, Jack J (OGC) To:Frank Roach Cc:Joseph Lastufka Subject:RE: NK-41B Forward Plan (PTD: 224-153) Date:Friday, March 21, 2025 10:20:47 AM Attachments:PBE NK-41B Suspension Program V0.pdf Frank – You have verbal approval to move forward with the suspension on NK-41B per the procedure sent 3/20/25. Please include the following CoA. AOGCC witnessed tag TOC AOGCC witnessed MIT post cement to 2000 psi Jack From: Frank Roach <Frank.Roach@hilcorp.com> Sent: Friday, March 21, 2025 10:03 AM To: Lau, Jack J (OGC) <jack.lau@alaska.gov> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: RE: NK-41B Forward Plan (PTD: 224-153) Jack, Thanks for the callback and discussion a little while ago. I just talked with Joe over here and the 10-403 should be over there shortly. In the meantime, we would like verbal approval to proceed with the retainer set and cement job per the plan that was sent yesterday. We’re currently in the hole with the retainer, running to set at 14,050’. Let me know if you need anything additional. Thank you, sir. Regards, Frank V Roach Drilling Engineer Hilcorp Alaska, LLC 907.854.2321 mobile 907.777.8413 office From: Frank Roach Sent: Thursday, March 20, 2025 8:08 PM To: Lau, Jack J (OGC) <jack.lau@alaska.gov> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: NK-41B Forward Plan (PTD: 224-153) Jack, Thank you for the phone discussion earlier today about our status with NK-41B. Please see the attached plan to set up the well for suspension as we work out the plan on how to return and make another attempt in the future. This is what we’ll use for the 10-403, but I wanted to get this in front of you ASAP. Let me know if you have any questions or need anything additional. Regards, Frank V Roach Drilling Engineer Hilcorp Alaska, LLC 907.854.2321 mobile 907.777.8413 office The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 17.0 Set 9-5/8” Retainer and Pump Cement Plug 17.1 MU 9-5/8” cement retainer and RIH t/~14,050’. Ensure retainer is spaced out such that it won’t be set across a connection. Set retainer and slack off string weight to confirm retainer is set. 17.2 Establish injection below the retainer. Once pressure breaks over, pump additional 5 bbls to confirm injection. 17.3 Unsting from the retainer and spot 50 bbls 15.8ppg Class G cement within 5 bbls of the end of the stinger. Estimated Total Cement Volume: Cement Slurry Design: 17.4 Once spotted, sting back into the retainer and squeeze 19 bbls below the retainer. 17.5 With 31 bbls left in the workstring/stinger, unsting and spot remaining 31 bbls on top of the retainer. 17.6 Pull up above the cement spotted on top of the retainer and circulate to clean up the string. POOH & LDBHA. 17.7 MU 9-5/8” cleanout assembly (to include 8-1/2” bit). RIH with cleanout assembly to ~180’ (2- stands) above planned TOC. 17.8 Wait on cement to build 500psi compressive strength. Slowly RIH and tag cement on top of retainer. CBU 2-4x while pumping pills/sweeps to help in cleaning the 9-5/8” casing. Ensure fluid is consistent in and out before shutting down. 17.9 RU casing testing equipment and PT 9-5/8” casing to 2,000 psi for 30 min, chart test. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001. x Provide AOGCC inspector 24 hr notice for opportunity to witness pressure test 17.10 RD test equipment. RU and displace drilling mud to 9.8 ppg brine. 17.11 Once clean 9.8 ppg brine is observed in and out, shut down and flow check well. 17.12 POOH & LD cleanout assembly. 17.13 RU test equipment. Install test plug and test annular, upper rams and lower rams with 4-1/2” test joint. 18.0 Run Kill String/ Post Rig Work 18.1 RU to run used 4-1/2” 12.6#, 13Cr-80 Vam Top tubing. x Ensure wear bushing is pulled. x Ensure 4-1/2”, 12.6#, Vam Top x 5-1/2” DELTA 544 crossover is on rig floor and M/U to FOSV. x Ensure all tubing has been drifted in the pipe shed prior to running. x Be sure to count the total # of joints in the pipe shed before running. x Keep hole covered while RU casing tools. x Record OD’s, ID’s, lengths, SN’s of all components with vendor & model info. x Monitor displacement from wellbore while RIH. 18.2 PU, MU and RH with the following 4-1/2” kill string jewelry (tally to be provided by Operations Engineer): x Torque Turn All Connections x Tubing Jewelry to include (top to bottom): x 1x ‘X’ Nipple @ ~2,500’ MD x 1x WLEG x Tubing is 4-1/2”, 12.6#, 13Cr-80, Vam Top 4-1/2” 12.6/# 13Cr-80 Vam Top – Make up Torque Casing OD Minimum Optimum Maximum 4-1/2” 4,000 ft-lbs 4,440 ft-lbs 4,880 ft-lbs 18.3 Run 4-1/2” kill string to ~2,600’. 18.4 MU the tubing hanger and land same. Run in the lock-down screws and torque to spec. 18.5 Install and pressure test TWC from above. 18.6 ND BOPE. NU the tubing head adapter and tree. 18.7 PT the tubing hanger void to 500/5,000 psi. PT the tree to 250/5,000 psi. 18.8 RU lubricator and pull TWC. 18.9 Freeze protect the wellbore. x Rig up to pump heated diesel down the IA, taking returns up the tubing. Reverse 138 bbls heated diesel into the IA. x Shut in the IA. x Line up to U-tube from the IA to the tubing. x U-tube the diesel and freeze protect the tubing and IA to ~2,000’ MD. 18.10 After u-tube is complete, RU lubricator and install BPV. 18.11 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over with valve alignment as per operations personnel. 18.12 RDMO Parker 273. POST RIG WORK 1. Well Site Inspection is required within 12 months of approved 10-403. a. Provide AOGCC inspector 10 days notice before inspection for opportunity to accompany inspection tour. b. Post-inspection 10-404 required within 30 days of inspection. _____________________________________________________________________________________ Created By: FVR 3/20/2025 PROPOSED SCHEMATIC Niakuk Unit Well: NK 41B Last Completed: TBD PTD: 224-153 GENERAL WELL INFO API: 50-029-22778-02-00 Completed: TBD CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5 / X56 / Weld N/A Surface 110’ N/A 13-3/8” Surface 68 / L-80 / BTC 12.415” Surface 4,205’ 0.1497 9-5/8” Intermediate 47 / L-80 / DWC/C 8.681” Surface 14,144’ 0.0758 TUBING DETAIL 4-1/2” Tubing 12.6 / L-80 / VT 3.958” Surface ~2,600’ 0.0152 TD = 14,575’(MD) / TD =6,806’(TVD) 13-3/8” Window @ 4,205’ MD KBElev: =65.14’ / GL Elev: =19.4’ 9-5/8” 1 2 Fish: RCT BHA 14188’ – 14963’ PBTD =13,626’ (MD) / PBTD =6,553(TVD) 4-1/2” 3 PB1: 14150’–15336’ PB2: 12570’ – 15176’ 9-5/8” Window @ 14,108’ MD Tracked PB1: 14,125’ – 14,575’ OPEN HOLE / CEMENT DETAIL Driven 17-1/2” 2038 sx PF E, 54 sx PF C, 1190 sx Class G 12-1/4” Lead –467 sks / Tail –425 sks (pumped on 3/12/2025) JEWELRY DETAIL No Depth ID Item 1 ~14,050’ 9-5/8” cement retainer 2 ~2,600’ 3.813” 4-1/2” WLEG 3 ~2,500’ 3.813” X Nipple WELL INCLINATION DETAIL KOP @ 4,205’ Max Angle 75.58deg @ 5,132’ TREE & WELLHEAD Tree Wellhead 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:Lau, Jack J (OGC) To:AOGCC Records (CED sponsored) Subject:FW: PBE NK-41B 9-5/8" Casing Test and FIT (PTD: 224-153) Date:Tuesday, March 18, 2025 10:23:44 AM Attachments:PBE NK-41B CSG TST FIT 3-14-25.pdf From: Frank Roach <Frank.Roach@hilcorp.com> Sent: Tuesday, March 18, 2025 8:47 AM To: Lau, Jack J (OGC) <jack.lau@alaska.gov> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: PBE NK-41B 9-5/8" Casing Test and FIT (PTD: 224-153) Jack, Attached is the 9-5/8” casing test and FIT results post-window milling from last night. The 9-5/8” cement job went well with no losses, good lift pressure, and plug bumped ~1bbl late. Window milling went good as well. After the FIT and pulling out to surface, the mills were in good condition and within spec, indicating a good window. Current operations are making up the kick-off BHA. Plan forward is to run in with this BHA and gain separation from PB1 and the lost-in-hole BHA. Once we have enough separation and new hole to bury the next BHA, we’ll trip out to pick up the 8-1/2” x 9-7/8” underreamer assembly to drill to intermediate 2 TD. Regards, Frank V Roach Drilling Engineer Hilcorp Alaska, LLC 907.854.2321 mobile 907.777.8413 office 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, 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 theonward 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. CASING AND LEAK-OFF FRACTURE TESTS Well Name:PBE NK 41-B Date:3/17/2025 Csg Size/Wt/Grade:9.625" 47# L-80 DWC/C Supervisor:Anderson/Amend Csg Setting Depth:14,125 TMD 6,686 TVD - Open Hole Mud Weight:10.3 ppg LOT / FIT Press =975 psi LOT / FIT =13.10 ppg Hole Depth =14145 md Fluid Pumped=5.1 Bbls Volume Back =5.1 bbls Estimated Pump Output:0.0925 Barrels/Stroke LOT / FIT DATA CASING TEST DATA Enter Strokes Enter Pressure Enter Strokes Enter Pressure Here Here Here Here ->237 ->4 132 ->686 ->8 253 ->10 176 ->20 643 ->14 269 ->32 1031 ->18 345 ->42 1286 ->22 428 ->52 1594 ->26 507 ->62 1894 ->30 588 ->72 2124 ->34 667 ->82 2444 ->38 744 ->96 2854 ->42 820 ->118 3454 ->46 888 ->130 3765 ->50 951 ->146 4207 ->52 975 ->164 4603 Enter Holding Enter Holding Time Here Pressure Here Time Here Pressure Here ->0 975 ->0 4603 ->1 920 ->1 4597 ->2 907 ->2 4596 ->3 896 ->3 4595 ->4 888 ->4 4594 ->5 881 ->5 4594 ->6 874 ->10 4591 ->7 867 ->15 4589 ->8 861 ->20 4587 ->9 856 ->25 4582 ->10 851 ->30 4584 ->12 832 -> ->14 822 -> -> -> 2 6 10 14 18 22 26 30 34 38 42 465052 4 8 20 32 42 52 62 72 82 96 118 130 146 164 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 2100 2200 2300 2400 2500 2600 2700 2800 2900 3000 3100 3200 3300 3400 3500 3600 3700 3800 3900 4000 4100 4200 4300 4400 4500 4600 4700 4800 4900 5000 0 10 20 30 40 50 60 70 80 90 100 110 120 130 140 150 160 170 180Pressure (psi)Strokes (# of) LOT / FIT DATA 975920907896888881874867861856851 832 822 460345974596459545944594 4591 4589 4587 4582 4584 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 2100 2200 2300 2400 2500 2600 2700 2800 2900 3000 3100 3200 3300 3400 3500 3600 3700 3800 3900 4000 4100 4200 4300 4400 4500 4600 4700 4800 4900 5000 0 5 10 15 20 25 30 35 40Pressure (psi)Time (Minutes) LOT / FIT DATA UNDEFINED SAG RIVER AND IVISHAK RUSH By Grace Christianson at 10:42 am, Mar 14, 2025 325-147 Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2025.03.14 10:24:37 - 08'00' Sean McLaughlin (4311) * BOPE test to 4500 psi. Annular to 3500 psi. * Casing test and FIT digital data to AOGCC upon completion of FIT. X 10-407 JJL 3/14/25*&: 03/14/25 Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.03.14 14:37:49 -08'00' RBDMS JSB 031825 Prudhoe Bay East (PBU) NK-41B Drilling Program Version 2 03/14/2025 Table of 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 ................................................................................................... 9 8.0 Mandatory Regulatory Compliance / Notifications .................................................................. 10 9.0 Pre-Rig, R/U, and Preparatory Work ........................................................................................ 13 10.0 N/U BOPE ..................................................................................................................................... 14 11.0 Decomplete, Cut & Pull 9-5/8”, Set 13-3/8” P&A Plug ............................................................ 15 12.0 Set Whipstock, Mill 12-1/4” Window ......................................................................................... 18 13.0 Drill 12-1/4” Intermediate 1 Hole Section ................................................................................. 21 14.0 Run 9-5/8” Intermediate 1 Casing .............................................................................................. 25 15.0 Cement 9-5/8” Intermediate Casing ........................................................................................... 28 16.0 Drill 8-1/2” x 9-7/8” Intermediate 2 Hole Section ..................................................................... 31 17.0 Run 7” Intermediate 2 Liner ...................................................................................................... 38 18.0 Cement 7” Intermediate 2 Liner ................................................................................................ 42 19.0 Drill 6-1/8” Production Hole Section.......................................................................................... 45 20.0 Run 4-1/2” Production Liner ...................................................................................................... 49 21.0 Cement 4-1/2” Production Liner ................................................................................................ 52 22.0 Run Upper Completion/ Post Rig Work .................................................................................... 55 23.0 Parker 273 Rig BOP Schematic .................................................................................................. 59 24.0 Wellhead Schematic ..................................................................................................................... 60 25.0 Days Vs Depth .............................................................................................................................. 61 26.0 Formation Tops & Information .................................................................................................. 62 27.0 Anticipated Drilling Hazards ...................................................................................................... 66 28.0 Parker 273 Rig Layout ................................................................................................................ 72 29.0 FIT Procedure .............................................................................................................................. 73 30.0 Parker 273 Rig Choke Manifold Schematic .............................................................................. 74 31.0 Casing Design ............................................................................................................................... 75 32.0 12-1/4” Hole Section MASP ........................................................................................................ 76 33.0 8-1/2” x 9-7/8” Hole Section MASP ............................................................................................ 77 34.0 6-1/8” Hole Section MASP .......................................................................................................... 78 35.0 Spider Plot (NAD 27) (Governmental Sections) ........................................................................ 79 36.0 Surface Plat (As Built) (NAD 27) ................................................................................................ 80 Page 2 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 1.0 Well Summary Well PBU NK-41B Pad Prudhoe Bay DS-NK Planned Completion Type 4-1/2” Production Tubing Target Reservoir(s) Sag / Ivishak Sands Planned Well TD, MD / TVD 21,886’ MD / 10,165’ TVD PBTD, MD / TVD 21,806’ MD / 10,097’ TVD Surface Location (Governmental) 1,474' FSL, 717' FEL, Sec 36, T12N, R15E, UM, AK Surface Location (NAD 27) X= 721,841.38, Y= 5,980,017.95 Top of Productive Horizon (Governmental)1,308' FNL, 1,384' FEL, Sec 28, T12N, R16E, UM, AK TPH Location (NAD 27) X= 736,341.30, Y= 5,988,242.18 BHL (Governmental) 1,196' FNL, 1,161' FEL, Sec 28, T12N, R16E, UM, AK BHL (NAD 27) X= 736,560.06, Y= 5,988,360.75 AFE Number 241-00161 AFE Drilling Days 55 AFE Completion Days 8 Maximum Anticipated Pressure (Surface) 3958 psig Maximum Anticipated Pressure (Downhole/Reservoir) 4971 psig Work String 5-1/2” 21.9# S-135 DELTA 544 4” 14# S-139 XT-39 Parker 273 KB Elevation above MSL: 19.4 ft + 46.95 ft = 66.35 ft GL Elevation above MSL: 19.4 ft BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams Page 3 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 2.0 Management of Change Information Page 4 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 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 20” 19.25 - - - X-52 Weld *16” 13-3/8” 12.415 12.259 14.375 68 L-80 BTC 5,020 2,270 1,556 12-1/4” 9-5/8” 8.681 8.525 10.625 47 L-80 DWC-C 6,870 4,760 1,086 8-1/2”x 9-7/8”7” 6.276 6.151 7.656 26 L-80 Hyd 563 7,240 5,410 604 6-1/8 4-1/2” 3.958 3.833 4.937 12.6 13Cr-80 VamTop 8,430 7,500 288 Tubing 4-1/2” 3.958 3.833 4.937 12.6 13Cr-80 VamTop 8,430 7,500 288 *Existing hole section and casing string 4.0 Drill Pipe Information: Hole Section OD (in) ID (in)TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn M/U (Min) M/U (Max) Tension (k-lbs) Surf, Int, & Prod 5-1/2”4.778” 4.000” 6.625” 21.9 S-135 Delta 544 41,900 58,700 786klb 4”3.340” 2.688” 4.875” 14.0 S-135 XT39 17,700 21,200 513klb All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 5 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 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 Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area – this will not save the data entered, and will navigate to another data entry. x Ensure time entry adds up to 24 hours total. x Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. x Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 5.2 Afternoon Updates x Submit a short operations update each work day to sean.mclaughlin@hilcorp,com, frank.roach@hilcorp.com, nathan.sperry@hilcorp.com, jengel@hilcorp.com and joseph.lastufka@hilcorp.com 5.3 Intranet Home Page Morning Update x Submit a short operations update each morning by 7am on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 5.4 EHS Incident Reporting x Health and Safety: Notify EHS field coordinator. x Environmental: Drilling Environmental Coordinator x Notify Drilling Manager & Drilling Engineer on all incidents 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, frank.roach@hilcorp.com, jengel@hilcorp.com and joseph.lastufka@hilcorp.com 5.6 Casing and Cement report x Send casing and cement report for each string of casing to sean.mclaughlin@hilcorp,com, frank.roach@hilcorp.com, jengel@hilcorp.com and joseph.lastufka@hilcorp.com 5.7 Hilcorp Contact List: Title Name Work Phone Email Drilling Manager Sean McLaughlin 907.223.6784 sean.mclaughlin@hilcorp.com Drilling Engineer Frank Roach 907.777.8413 frank.roach@hilcorp.com Drilling Engineer Joe Engel 907.777.8395 jengel@hilcorp.com Drilling Engineer Nate Sperry 907.777.8450 nathan.sperry@hilcorp.com Completion Engineer Eric Dickerman 907.564.4061 eric.dickerman@hilcorp.com Geologist Ryan Phelps 907.777.8361 ryan.phelps@hilcorp.com Reservoir Engineer Jeff Allen 907.777.8428 jallen@hilcorp.com Drilling Env. Coordinator Adrian Kersten 907.564.4820 adrian.kersten@hilcorp.com Drilling Tech Joe Lastufka 907.777.8400 Joseph.Lastufka@hilcorp.com Page 6 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 6.0 Planned Wellbore Schematic Pre-Rig Abandonment Schematic: Page 7 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure Pre-Window Schematic: Page 8 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure Proposed Schematic: Page 9 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 7.0 Drilling / Completion Summary NK-41B is a sidetrack producer planned to be drilled in the Sag and Ivishak sands. The parent wellbore, NK-41A, is a shut-in, suspended well since November, 1997. The 1997 lower abandonment was confirmed on 12/11/24, prior to the rig’s arrival on the well. Operations covered on a separate sundry. The directional plan is a 12-1/4” intermediate 1 hole will be drilled and 9-5/8” casing set in the CM3. An 8- 1/2”x9-7/8” underreamed intermediate 2 hole will be drilled and 7” liner set at TSGR. A 6-1/8” slant section will be drilled across the Sag River and Ivishak formations and TD in BSAD. A 4-1/2” production liner will be run and cemented in place. The well will be completed with 4-1/2” production tubing. Perforating will be performed post-rig. Parker 273 will be used to finish decomplete, drill, and complete the wellbore. Drilling operations are expected to commence approximately January 11, 2024, pending rig schedule. All cuttings & mud generated during drilling operations will be hauled to one of two locations: Primary: Prudhoe G&I on Pad 4 Secondary: the Milne Point “B” pad G&I facility General sequence of operations: 1. MIRU Parker 273 to well site 2. N/U & Test BOPE 3. Pull Hanger. Cut and pull 9-5/8” casing. 4. Run whipstock and mill 12-1/4” window. 5. Drill 12-1/4” to TD of intermediate 1 hole section. 6. Run and cement 9-5/8” intermediate 1 casing 7. Drill 8-1/2”x9-7/8” to TD of intermediate 2 hole section. 8. Run and cement 7” intermediate 2 liner 9. Drill 6-1/8” hole to TD 10. Run and cement 4-1/2” production liner 11. Run Upper Completion 12. N/D BOP, N/U Tree, RDMO Reservoir Evaluation Plan: 1. Intermediate 1 Hole: No mud logging. Remote Ops geologist. LWD: GR + Res 2. Intermediate 2 Hole: Mud logging. Field Ops geologist for casing pick. Triple Combo 3. Production Hole: Mud logging. Field Ops geologist. Triple-Combo For any cuttings collected, submit a set of washed and dried cuttings to AOGCC as per 20 AAC 25.071(b)(2). Page 10 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with all applicable AOGCC regulations, specific regulations are listed below. 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 (1) week intervals during the decompletion of PBU NK-41A. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. x BOPs shall be tested at (2) week intervals once the window has been milled and during the drilling and completion of PBU NK-41B. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. x The initial and subsequent tests of BOP equipment will be to 250/4,500 psi for 5/5 min (annular to 70% rated WP, 3,500 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 control fluid flow from the well bore, AOGCC is to be notified and we must 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 7-14 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”. o Ensure the diverter vent line is at least 75’ away from potential ignition sources x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. x Casing pressure test criteria in 20 AAC 25.030 (e) Casing and Cementing,“A casing pressure test must be performed if BOPE is to be installed on a casing. The casing must be tested to hold a minimum surface pressure equal to 50 percent of the casing internal yield pressure. The test pressure must show stabilizing pressure and may not decline more than 10 percent within 30 minutes. The results of this test and any subsequent tests of the casing must be recorded as required by 20 AAC 25.070(1)”. Page 11 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure AOGCC Regulation Variance Requests: x No variances are requested at this time. Summary of Parker 273 BOP Equipment & Test Requirements Hole Section Equipment Test Pressure (psi) 12-1/4” x 13-5/8” x 5M Annular BOP x 13-5/8” x Double Gate o Blind ram in btm cavity x Mud cross w/ 3-1/8” x 5M side outlets x 13-5/8” x Single ram x 3” x 5M Choke Line x 2” x 5M Kill line x 3” x 5M Choke manifold x Standpipe, floor valves, etc Initial Test: 250/4,500 Annular: 250/3,500 Subsequent Tests: 250/4,500 Annular: 250/3,500 8-1/2” x 13-5/8” x 5M Annular BOP x 13-5/8” x Double Gate o Blind ram in btm cavity x Mud cross w/ 3-1/8” x 5M side outlets x 13-5/8” x Single ram x 3” x 5M Choke Line x 2” x 5M Kill line x 3” x 5M Choke manifold x Standpipe, floor valves, etc 6-1/8” x 13-5/8” x 5M Annular BOP x 13-5/8” x Double Gate o Blind ram in btm cavity x Mud cross w/ 3-1/8” x 5M side outlets x 13-5/8” x Single ram x 3” x 5M Choke Line x 2” x 5M Kill line x 3” x 5M Choke manifold x Standpipe, floor valves, etc Primary closing unit: Sara Koomey Control Unit, 3,000 psi, 316 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is an air-driven pump and emergency pressure is provided by bottled nitrogen. The remote closing operator panels are located in the doghouse and on accumulator unit. Page 12 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 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 spud. x 24 hours notice prior to testing BOPs. x 24 hours notice prior to casing running & cement operations. x Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email:melvin.rixse@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) Page 13 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 9.0 Pre-Rig, R/U, and Preparatory Work 9.1 Prior to the rig’s arrival, the following steps should have been completed (for more detail, refer to the 10-403 for NK-41A): x MIT 9-5/8” Casing (passed to 2,174psi on 12/11/24) x MIT-OA (established open shoe @ 1,900psi on 12/11/24) x CBL and drift of 9-5/8” Csg from 8,000’ to surface x Install 9-5/8” plug and pressure test same x Punch 9-5/8” csg @ ~6,990’ and circ clean through OA x Cement down 9-5/8” and up 9-5/8” x 13-3/8” annulus with annular planned TOC at 6,000’ x After cement reaches compressive strength, tag plug and CMIT TxIA t/2,500psi 9.2 NK-41B will utilize NK-41A’s wellhead and surface casing on DS-NK. Ensure to review attached surface plat and make sure rig is over appropriate wellhead. 9.3 Ensure PTD and drilling program are posted in the rig office and on the rig floor. 9.4 Level pad and ensure enough room for layout of rig footprint and R/U. 9.5 Rig mat footprint of rig. 9.6 Ensure any necessary wellhead equipment is staged prior to MIRU. 9.7 MIRU Parker 273 Ensure rig is centered over wellhead to prevent any wear to BOPE or wellhead. 9.8 Note: 9.8 ppg NaCl brine should be left in the well from the pre-rig decomplete work. Confirm fluids in handover to ensure consistent fluids will be in the well prior to displacing to milling fluid. 9.9 Ensure 5-3/4” liners in mud pumps. x NOV 12-P-160 1,600 HP mud pumps are rated at 5,085 psi, 466 gpm @ 120 spm @ 96% volumetric efficiency. Page 14 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 10.0 N/U BOPE 10.1 Install TWC in hanger profile. Pressure test to 250/4,500 psi for 5 min. 10.2 N/D tree and adapter flange. 10.3 N/U 13-5/8 x 5M BOP as follows: x BOP configuration from top down: 13-5/8” x 5M annular / 13-5/8” x 5M double gate / 13- 5/8” x 5M mud cross / 13-5/8” x 5M single gate x Double gate ram should be dressed with 2-7/8” x 5” VBRs or 5” solid body rams in top cavity,blind ram in bottom cavity. x Single ram can be dressed with 2-7/8” x 5” VBRs or 5” solid body rams x NU bell nipple, install flowline. x Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to mud cross). x Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual valve 10.4 RU MPD RCD and related equipment 10.5 Notify AOGCC and Test BOP to 250/4,500 psi for 5/5 min. Test annular to 250/3,500 psi for 5/5 min. x Test with 5” test joint and test VBR’s with 4” and 5” test joints x Smallest and largest pipes to be ran x Confirm test pressures with PTD x Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure is trapped underneath test plug x Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech 10.6 RD BOP test equipment. 10.7 Pull TWC. Page 15 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 11.0 Decomplete, Cut & Pull 9-5/8”, Set 13-3/8” P&A Plug 11.1 Pull hanger and pup joint to rig floor and L/D. 11.2 P/U 8-1/2” cleanout assembly: 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 Utilize used roller cone bit with jets removed for maximum flow. x Drill string will be 5” 19.5# S-135. 11.3 RIH w/cleanout assy to ~5,660’ MD (Last tagged by e-line on 1/12/2025) 11.4 Slowly wash down and tag cement plug from pre-rig work. CBU 2-4x ensuring clean 9.8ppg brine in and out. 11.5 Flow check well. POOH & LD cleanout assembly MOC-1 11.6 MU mechanical casing cutter BHA per fishing representative. Make sure cutters are dressed to be able to cut 9-5/8” 47# BTC-M casing. 11.7 RIH to cut depth @ ~5,600’ MD. Locate the collars above and below proposed cut depth. Cut casing in the middle of the joint identified by the coupling locate. x After the pressure drop indicating the cut is seen spin the cutter for an additional 15 minutes. This helps to ensure that the cutter blades have completely cut through the casing. x If the cut appears to go poorly (casing grabs blades, other anomalies), plan to make the casing stub polishing run. Final decision for the polishing/scraper run may be made once the cut joint is pulled 11.8 Line up to take returns from the OA to the flowback tank(s). Close annular around drillpipe, break circulation, and CBU 2x min at max rate. After consistent brine is observed in and out, shut down and flow check well for 30 minutes to confirm well is in balance. 11.9 POOH and LD casing cutter BHA. 11.10 Back out lockdown screws. x Reporting is inconsistent on the 9-5/8” casing set. Drilling report states casing was set on slips, but the tally summary sheet notes a casing hanger. Be prepared for the potential of casing growth. If the last couple lockdown screws become tight when backing out, Stop and retighten LDS. RIH w/HWDP/collars and hang off with a RTTS (or equivalent) packer. While staying connected to the packer, attempt to back out LDS again. Once successful, release RTTS, lay down packer, and HWDP. Page 16 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 11.11 Spear and pull 9-5/8” casing to the floor. Release spear and LD same. LD 9-5/8” casing down to the cut. Note torque required to break connections, overall condition of the casing, and the cut. Depending on condition, joints may be salvaged for future shoetrack/pup joints. Inspect casing for NORM prior to removal from location. 11.12 MU 13-3/8” drift/cleanout assembly. Ensure casing scraper or smooth OD stabilizer / string mill is in the BHA to clean area where retainer is to be set. Also ensure BHA is close to mimicking whipstock assembly for drifting. RIH to 9-5/8” casing stump. 11.13 CBU at least 2x @ max rate to ensure clean casing. Wipe retainer setting area multiple times to help ensure a good set. POOH & LD cleanout BHA. 11.14 MU 13-3/8” cement retainer and RIH t/50’ above the casing stub. Ensure retainer is spaced out such that it won’t be set across a connection. Set retainer and slack off string weight to confirm retainer is set. x Provide AOGCC inspector 24 hr notice of retainer set for opportunity to witness weight testing to confirm set. 11.15 Establish injection below the retainer. Once pressure breaks over, pump additional 5 bbls to confirm injection. 11.16 Unsting from the retainer and spot 45 bbls 15.8ppg Class G cement within 5 bbls of the end of the stinger. Estimated Total Cement Volume: Cement Slurry Design: Tail Slurry System HalCem Density 15.8 lb/gal Yield 1.16 ft3/sk Mix Water 4.98 gal/sk Page 17 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 11.17 Once spotted, sting back into the retainer and squeeze 30 bbls below the retainer. This volume is 150’ worth of 13-3/8” capacity (22.5 bbls) plus 7.5 bbls excess. 11.18 With 15 bbls left in the workstring/stinger, unsting and spot remaining 15 bbls on top of the retainer. This volume equates to 50’ of 13-3/8” capacity above the retainer (7.5 bbls), plus another 7.5 bbls excess. 11.19 Pull up above the cement spotted on top of the retainer and circulate to clean up string. POOH & LDBHA 11.20 Wait on cement to reach a minimum of 500psi compressive strength before continuing. Page 18 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 12.0 Set Whipstock, Mill 12-1/4” Window 12.1 MU 13-3/8” cleanout assembly (to include 12-1/4” bit and 13-3/8” casing scraper). Space out casing scraper where it will cover planned whipstock setting depth and contingency bridge plug depth. RIH with cleanout assembly to ~100’ above the abandonment plug. 12.2 Slowly RIH and tag cement on top of retainer. CBU 2-4x while pumping pills/sweeps to help in cleaning the 13-3/8” casing. Ensure fluid is consistent both in and out before shutting down. 12.3 RU casing testing equipment and PT 13-3/8” casing to 2500 psi for 30 min, chart test. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001. x Provide AOGCC inspector 24 hr notice for opportunity to witness pressure test. 12.4 Flow check well for 10 minutes prior to tripping out. POOH & LD cleanout assembly. 12.5 Whipstock set depth information: x Planned TOW: 4,254’ x Whipstock should be set to avoid a collar while milling the window. x Drilling Foreman, Whipstock hand, and drilling engineer to agree on set depth 12.6 MU 12-1/4” mill/whipstock assembly as per WIS tally: x MU HWDP, string magnets, and float sub x Ensure ditch magnets are installed in shaker room and cleaned prior to running in with the whipstock 12.7 Install MWD and orient. Rack back mill assembly x Ensure a dedicated MWD is available for the orientation of the whipstock 12.8 Verify offset between MWD and the whipstock tray, witnessed and agreed by the Drilling Foreman, MWD/DD personnel, and WIS rep. Document and record offset in well file. 12.9 Slowly RIH with whipstock assembly per WIS rep. x RIH no faster than 1.5 to 2 minutes per stand. x Ensure workstring is stationary prior to setting in slips to avoid weakening shear bolt and prematurely tripping/setting the anchor. 12.10 Stop 30-45’ above planned set depth. Work torque out of string. Measure and record P/U and S/O weights. Obtain survey with MWD for orienting whipstock. 12.11 Orient whipstock to desired direction by turning DP in ¼ round increments. P/U and S/O on DP to work all torque out after oriented. (Being careful not to set trip anchor). Target orientation is 30q LOHS – Consult with milling hand 12.12 Whipstock orientation: Page 19 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure x Desired orientation of the whipstock face is 15R to 45R, target is 20 ROHS x Hole Angle at window interval (@ 4,254’, 55° inc, 46° azi) x Sidetrack tangent section is 74q inclination and 63q azimuth 12.13 Once whipstock is in the desired orientation, set whipstock per WIS rep. 12.14 Displace well over to 9.0 ppg milling fluid. Confirm fluid in and out has correct parameters and sufficient for moving metal shavings/cuttings uphole: x Funnel visc: 40-60s x YP: 18-20 12.15 Record P/U, S/O weights, and free rotation. Slack off to top of whipstock and with light weight and low torque. Mill window as per whipstock contractor representative. Pump high visc sweeps as necessary. 12.16 Clean catch trays and ditch magnets frequently while milling window to collect metal cuttings/shavings. Track weight of recovered metal to gauge whether window milling was complete. 12.17 Mill window until the uppermost mill has passed across the entire tray. Dress and polish window as needed. 12.18 With upper mill at the end of the tray, this will drill ~ 20’ of new hole. 12.19 After window is milled but before POOH, shut down pumps and work milling assembly through window watching for drag. Dress and polish window as needed. After reaming, shut off pumps and rotary and dry drift window. 12.20 Circulate bottoms up until even MW in/out and hole is clean of metal shavings. Reduce mud properties for drilling or displace over to 9.0 ppg LSND drilling fluid. 12.21 Pull window milling assembly into 13-3/8” casing and perform FIT to 12.5ppg EMW. Chart test. Ensure test is recorded on same chart as the casing test. Document incremental volume pumped (and subsequent pressure) and volume returned. 45R 15R Page 20 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure x 13-3/8” surface casing is fully cemented. Open hole weak point is the top of the window and ~ 4,254’ MD / ~ 3,956’ TVD. x 12.5 ppg FIT value is to cover over and above expected ECD while drilling interval. x 12.3 ppg provides >25 bbls based on 11.0 ppg MW +0.5ppg intensity, 10.0 ppg PP. x If 12.3 ppg EMW is not achieved, contact drilling engineer. 12.22 POOH and LD window milling BHA. Gauge all mills for wear. Depending on results, have backup milling assembly ready to dress window to desired dimensions. 12.23 PU stack washer and wash across BOPE. Function all rams to clear any potential milling debris. Page 21 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 13.0 Drill 12-1/4” Intermediate 1 Hole Section 13.1 P/U 12-1/4” RSS directional BHA. 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 Ensure MWD is R/U and operational. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. x Drill string will be 5-1/2” 21.9# S-135 DELTA 544. x Run a non-ported float in the production hole section. 13.2 12-1/4” hole section mud program summary: x Density: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. x Solids Concentration:Keep the shaker screen size optimized and fluid running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible. x Rheology: Keep viscosifier additions reasonably low. Utilize sweeps (weighted, high vis, tandem) to inform hole cleaning efficiency. Ensure 6 rpm is > 12 (~hole diameter) for sufficient hole cleaning x Run the centrifuge as needed while drilling the intermediate hole, this will help with solids removal. x Dump and dilute as necessary to keep drilled solids to an absolute minimum. x MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, & Toolpusher office. System Type:9.0 – 11.0 ppg LSND drilling fluid Properties: Interval Density PV YP API FL HPHT Drill Solids MBT Hardness ~4,254’ – ~9,422’ Window – UG4 9.0 – 9.6 5 – 20 15 – 30 < 8 N/A <6% <12 <200 ~9,422’ – ~17,408’ UG4 – CM3 9.6 – 10.6 5 – 20 15 – 30 < 6 N/A <6% <20 <200 ~17,408’ – TD CM3 – TD 10.5 – 11.0 5 – 20 15 – 30 < 6 <10 <6% <20 <200 Page 22 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure System Formulation: Product- intermediate Size Pkg ppb or (% liquids) Soda Ash 50 lb sx 0.17 PowerVIS 25 lb sx 1.5 – 2.0 M-I Pac UL 50 lb sx 3.0 Hydrahib/Kla-Stop 55 gal dm 1.0 – 1.5 KCl 50 lb sx 10.7 SCREENKLEEN 55 gal dm 0.25 M-I Wate 50 lb sx 56 (as needed for wt) Busan 1060 55 gal dm 2.1 13.3 Displace wellbore to 10.0 ppg LSND drilling fluid 13.4 Obtain initial ECD benchmark readings prior to drilling ahead. 13.5 Drill 12-1/4” hole section from 13-3/8” window to ~ 9,200’ MD (~200’ MD above UG4) per Geologist and Drilling Engineer Utilizing the following parameters: x Flow Rate: 700-950 GPM x RPM: Maximize RPM when rotating Take the first couple stands to understand BHA tendency. x Ensure shakers are set up to handle this flowrate. Ensure shakers are running slightly wet to maximize solids removal efficiency. Check for holes in screens on every connection. x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex: concretion deflection x Monitor Torque and Drag with pumps on every 5 stands x Monitor ECD, pump pressure & hookload trends for hole cleaning indication. Attempt to limit drilling ECD to 1.0 ppg over calculated cleanhole ECD. x Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across any sands for any extended period of time. x Limit maximum instantaneous ROP to < 200 FPH. The SV sands will drill faster than this, but good hole cleaning practices now reduces time needed to cleanup prior to running casing. x Limit WOB to 20k max to maintain bit stability when encountering hard stringers in the UG4-UG1 x 12-1/4” Hole Section A/C: x There are no wells with a CF < 1.0 13.6 Toward the end of the above interval, begin to weight up from 9.0 ppg to 9.6 ppg. Ensure mud is a consistent 9.6 ppg ~200’ before entering the UG4. x If using a spike fluid to weight up, ensure the fluid is heated to avoid shocking the formation Page 23 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure MOC-2 13.7 Drill 12-1/4” hole section from ~9,200’ MD to section TD in the UG1, utilizing the following parameters: x Flow Rate: 700-950 GPM x RPM: Maximize RPM when rotating x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex: concretion deflection x Monitor Torque and Drag with pumps on every 5 stands x Monitor ECD, pump pressure & hookload trends for hole cleaning indication x Limit maximum instantaneous ROP to < 200 FPH. Good hole cleaning practices now reduces time needed to cleanup prior to running casing. x Limit WOB to 20k max to maintain bit stability when encountering hard stringers in the UG4-UG1 x Once CM3 is penetrated, limit ECD to 0.5 ppg over calculated clean-hole ECD. Pay close attention to pump pressure to reduce Colville breathing risk. x 12-1/4” Hole Section A/C: x There are no wells with a CF < 1.0 13.8 At TD, CBU (minimum 5-7X, more if needed) at max rate and rotation (120+ rpm). Pump tandem sweeps x Obtain BHCT from MWD tools and provide to Halliburton cementers. x Rack back a stand at each bottoms up and reciprocate a full stand in between (while circulating the BU). Keep the pipe moving while pumping. x Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent stream, circulate more if necessary 13.9 BROOH to just below 12-1/4” window x Circulate at full drill rate unless losses are seen. x Rotate at maximum rpm that can be sustained. x Target pulling speed of 5 – 10 min/std (slip to slip time, not including connections), but adjust as hole conditions dictate. Slow pulling speed when backreaming through coal depths seen when drilling. x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling from the lower SVs. x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. x Monitor returns during the backream for increase in cuttings. With this high sail angle, cuttings in laterals will come back in waves and not a consistent stream so circulate more if necessary. Page 24 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 13.10 Slowly pull into the window and stop ~1-2 stands above the window, inside the 13-3/8” casing. CBU minimum 2x to clean the casing. Utilize sweeps as needed. Flow-check well prior to tripping out. 13.11 POOH and LD BHA. 13.12 Change out upper rams to 9-5/8” fixed-bore rams and test with 9-5/8” test joint. Page 25 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 14.0 Run 9-5/8” Intermediate 1 Casing 14.1 Well control preparedness: In the event of an influx of formation fluids while running the intermediate casing, the following well control response procedure will be followed: x P/U & M/U the 5-1/2” safety joint (with 9-5/8” crossover installed on bottom, TIW valve in open position on top, 5-1/2” handling joint above TIW). This joint shall be fully M/U and available prior to running the first joint of 9-5/8” casing. x Slack off and with 5-1/2” DP across the BOP, shut in ram or annular on 5-1/2” DP. Close TIW. x Proceed with well kill operations. 14.2 R/U 9-5/8” casing running equipment. x Ensure 9-5/8” 47# BTC x DELTA 544 crossover is on rig floor and M/U to FOSV. x Use BOL 2000 (or equivalent) thread compound. Dope pin end only w/ paint brush. x R/U CRT equipment. x Ensure all casing has been drifted to 8-1/2” on location prior to running. x Note that 47# drift is 8.525” x Be sure to count the total # of joints on the deck 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. 14.3 P/U shoe joint, visually verify no debris inside joint. 14.4 Continue M/U & thread locking 120’ shoe track assembly consisting of: 9-5/8” Float Shoe 1 joint – 9-5/8”, 2 Centralizers 10’ from each end w/ stop rings 1 joint – 9-5/8”, 1 Centralizer mid joint w/ stop ring 1 joint – 9-5/8”, 1 Centralizer mid joint w/ stop ring 9-5/8” Float Collar w/ Stage Cementer Bypass Baffle ‘Top Hat’ 1 joint – 9-5/8”, 1 Centralizer mid joint w/ stop ring x Ensure proper operation of float equipment while picking up. x Ensure to record S/N’s of all float equipment and stage tool components. 14.5 Continue running 9-5/8” intermediate casing x Fill casing while running using fill up line on rig floor. x Use BOL 2000 or equivalent thread compound. Dope pin end only w/ paint brush. x Centralization: x 1 centralizer every joint to within 120’ of the window x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Obtain up and down weights of the casing before entering open hole. Record rotating torque at 10 and 20 rpm x Likely to lose rotation capability around 11,600’ MD x See data sheets on the next page for MU torque for the 9-5/8” casing connection. Page 26 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 9-5/8” 47/# L-80 DWC/C Make-up Torque Casing OD Minimum Optimum Maximum 9-5/8” 40,000 ft-lbs 45,000 ft-lbs 59,400 ft-lbs Page 27 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 14.6 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 14.7 Slow in and out of slips. 14.8 RIH with 9-5/8” intermediate casing to 13-3/8” shoe at ~4,205’ MD. CBU and establish PU and SO weights prior to exiting shoe. 14.9 Continue to RIH with 9-5/8” intermediate casing using the following circulation strategy (Note: Take special care when staging pumps up and down to avoid packing off and breaking down formation): x 13-3/8” shoe to TD: Every 5th joint, staging up to planned cementing rate. Circulate for 5 minutes. 14.10 P/U hanger and landing joint and M/U to casing string. Casing shoe +/- 10’ from TD. 14.11 Break circulation at 1 bpm to avoid breaking down formation. Slowly stage up to full circulating rate (planned cementing rates). Allow circulating pressures to stabilize before increasing circulating rate to the next stage. Circulate 4 BU or more if needed to condition hole for cementing. Reduce YP to < 18 to help ensure success of cement job. Do not start the YP drop until casing is on bottom and cementers are ready. Page 28 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 15.0 Cement 9-5/8” Intermediate Casing 15.1 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 fluids can be delivered to the cementing unit at acceptable rates. x How to handle cement returns at surface. While not expected, ensure vac trucks are on standby and ready to assist. x Which pumps will be utilized for displacement, and how fluid will be fed to displacement pump. x Ensure adequate amounts 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. 15.2 Document efficiency of all possible displacement pumps prior to cement job. 15.3 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. 15.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and bottom plugs to ensure done in correct order. 15.5 Fill surface cement lines with water and pressure test. 15.6 Drop first bottom plug – HEC rep to witness. Pump spacer. 15.7 Drop second bottom plug – HEC rep to witness. Mix and pump lead cement per below calculations, confirm actual cement volumes with cementer after TD is reached. 15.8 Drop third bottom plug – HEC rep to witness. Mix and pump tail cement per below calculations, confirm actual cement volumes with cementer after TD is reached. x Cement volume based on annular volume + 40% open hole excess. Job will consist of lead & tail, TOC brought to ~11,669’ MD. Estimated Total Cement Volume: Page 29 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure Cement Slurry Design: 15.9 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 and continue with the cement job. 15.10 After pumping cement, drop top plug and displace with the rig pumps and LSND mud out of mud pits. x Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. x Ensure rig pump is used to displace cement. 15.11 Displacement calculation is in the Table in step 15.8. 15.12 Monitor returns closely while displacing cement. Adjust pump rate if losses or packing off are seen at any point during the job. 15.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling Engineer. 15.14 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. 15.15 While a low likelihood, be prepared for cement returns to surface. Open the shaker bypass line to the cuttings tank to dump any cement returns. Have black water available and vac trucks ready to assist. Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact with the cement. 15.16 Freeze protect 13-3/8” x 9-5/8” casing annulus to ~2,200’ MD with dead crude or diesel after cement tests indicate cement has reached 500 psi compressive strength. x Freeze protect with 131 bbls of dead crude/diesel Lead Slurry Tail Slurry System EconoCem HalCem Density 12.0 lb/gal 15.8 lb/gal Yield 2.35 ft3/sk 1.16 ft3/sk Mix Water 13.92 gal/sk 4.98 gal/sk Page 30 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure x Ensure total injection volume injected down the annulus (including any mud used to keep annulus open) doesn’t exceed 110% of the 13-3/8” x 9-5/8” annular volume. 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 jengel@hilcorp.com and joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 31 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure MOC-3 16.0 Drill 8-1/2” x 9-7/8” Intermediate 2 Hole Section 16.1 MU 8-1/2” Cleanout BHA (Milltooth Bit & 1.22° PDM) 16.2 TIH w/ 8-1/2” cleanout BHA to above 12-1/4” sidetrack point at ~12,570’. 16.3 Perform checkshots around sidetrack point to confirm which hole the 9-5/8” casing ran into. 16.4 Continue to TIH w/8-1/2” cleanout BHA to float equipment. Note depth TOC tagged on AM report. 16.5 R/U and test casing to 4500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and plot on FIT graph. Document incremental volume pumped (and subsequent pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001 16.6 Drill out shoe track to within 1-5’ of the float shoe. CBU 2x. 16.7 POOH & LD cleanout BHA. 16.8 Whipstock set depth information: x Planned TOW: 14,100’ or as close to the shoe as possible. x Whipstock should be set to avoid a collar while milling the window. x Drilling Foreman, Whipstock hand, and drilling engineer to agree on set depth 16.9 MU 8-1/2” mill/hydraulic whipstock assembly as per WIS tally: x MU HWDP, string magnets, and float sub x Ensure ditch magnets are installed in shaker room and cleaned prior to running in with the whipstock 16.10 Install MWD and orient. Rack back mill assembly x Ensure a dedicated MWD is available for the orientation of the whipstock 16.11 Verify offset between MWD and the whipstock tray, witnessed and agreed by the Drilling Foreman, MWD/DD personnel, and WIS rep. Document and record offset in well file. 16.12 Slowly RIH with whipstock assembly per WIS rep x RIH no faster than 1.5 to 2 minutes per stand. x Ensure workstring is stationary prior to setting in slips to avoid weakening shear bolt and prematurely tripping/setting the anchor. 16.13 Stop 30-45’ above planned set depth. Work torque out of string. Measure and record P/U and S/O weights. Obtain survey with MWD for orienting whipstock. 16.14 Orient whipstock to desired direction by turning DP in ¼ round increments. P/U and S/O on DP to work all torque out after oriented. (Being careful not to set trip anchor). Target orientation is 45q LOHS – Consult with milling hand Page 32 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 16.15 Initial Whipstock Orientation (may change upon results from cleanout run checkshots): x Desired orientation of the whipstock face is 45L to 60L, target is 45 LOHS x Hole Angle at window interval (@ 14,100’, 75° inc, 62° azi) x Sidetrack tangent section is 74q inclination and 63q azimuth 16.16 Once whipstock is in the desired orientation, set whipstock per WIS rep. 16.17 Displace well over to 10.3 ppg milling fluid. Confirm fluid in and out has correct parameters and sufficient for moving metal shavings/cuttings uphole: x Funnel visc: 40-60s x YP: 18-20 16.18 Record P/U, S/O weights, and free rotation. Slack off to top of whipstock and with light weight and low torque. Mill window as per whipstock contractor representative. Pump high visc sweeps as necessary. 16.19 Clean catch trays and ditch magnets frequently while milling window to collect metal cuttings/shavings. Track weight of recovered metal to gauge whether window milling was complete. 16.20 Mill window until the uppermost mill has passed across the entire tray. Dress and polish window as needed. 16.21 With upper mill at the end of the tray, this will drill ~ 20’ of new hole. 16.22 After window is milled but before POOH, shut down pumps and work milling assembly through window watching for drag. Dress and polish window as needed. After reaming, shut off pumps and rotary and dry drift window. 16.23 Circulate bottoms up until even MW in/out and hole is clean of metal shavings. Reduce mud properties for drilling or displace over to 10.3 ppg LSND drilling fluid. 16.24 Conduct FIT to 12.9 ppg EMW. Chart Test. Ensure test is recorded on same chart as casing test. Document incremental volume pumped (and subsequent pressure) and volume returned. Submit casing test and FIT digital data to AOGCC. x 12.9 ppg FIT provides >>25bbls based on 11.5 ppg MW +0.5ppg kick intensity, 9.40 ppg EMW PP @ TD 45L 60L * Casing test and FIT digital data to AOGCC upon completion of FIT - JJL Page 33 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 16.25 POOH and LD window milling BHA. Gauge all mills for wear. Depending on results, have backup milling assembly ready to dress window to desired dimensions. 16.26 PU stack washer and wash across BOPE. Function all rams to clear any potential milling debris. 16.27 MU 8-1/2” separation BHA x Motor assy with 8-1/2” bit x GWD x Agitator to ensure weight transfer x Drift and caliper all components before MU. Visually verify no debris inside components that cannot be drifted. x Ensure MWD is RU and operational. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. 16.28 RIH and orient above window. 16.29 RIH to bottom and begin drilling to gain separation from NK-41B PB1 and the LIH BHA between 14,188’ and 14,963’ MD (PB1 depths). 16.30 Once sufficient standoff from the LIH BHA and PB1 to clear magnetic interference, CBU and condition mud for trip. BROOH from TD to below window. Pull into the window and note any drag. 16.31 Flow check well once inside 9-5/8” casing. POOH and LD motor assembly. 16.32 NOV underreamer will be utilized above the MWD to allow for 9-7/8” hole 16.33 MU 8-1/2” x 9-7/8” directional BHA x RSS and Triple Combo x Ensure BHA components have been inspected previously. x Drift and caliper all components before MU. Visually verify no debris inside components that cannot be drifted. x Ensure MWD is RU and operational. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. x NOV underreamer will be utilized above the MWD to allow for 9-7/8” hole x NOV bit to match underreamer will be run. x Drill string will be 5-1/2” 21.9# S-135 DELTA 544. x Run a solid float in the intermediate 2 hole section. 16.34 TIH w/ 8-1/2” x 9-7/8” BHA to 9-5/8” shoe. 16.35 Intermediate 2 hole section will use the same mud used to TD Intermediate 1 hole section. 16.36 8-1/2” x 9-7/8” hole section mud program summary: Page 34 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure x Density: 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. x Solids Concentration: It is imperative that the solids concentration be kept low while drilling the production hole section. Keep the shaker screen size optimized and fluid running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible. x Rheology: Keep viscosifier additions to an absolute minimum (DUO-VIS / XCD). Data suggests excessive viscosifier concentrations can decrease return permeability. Do not pump high vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 10 (hole diameter) for sufficient hole cleaning x Run the centrifuge as needed while drilling the production hole, this will help with solids removal. x Dump and dilute as necessary to keep drilled solids to an absolute minimum. x MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, & Toolpusher office. System Type:10.3 – 11.5 ppg LSND drilling fluid Properties: Interval Density PV YP API FL HPHT Drill Solids MBT Hardness ~14,144’ – ~20,634’ Shoe – TCM1 10.3-11.0 5 – 20 15 – 30 <6 <10 <6% <20 <100 ~20,634’ – ~21,393’ CM1 – TD 11.0-11.5 5 – 20 15 – 30 <6 <10 <6% <20 <100 System Formulation: Product- intermediate Size Pkg ppb or (% liquids) Soda Ash 50 lb sx 0.17 PowerVIS 25 lb sx 1.5 – 2.0 M-I Pac UL 50 lb sx 3.0 Hydrahib/Kla-Stop 55 gal dm 2.0 – 1.5 KCl 50 lb sx 10.7 SCREENKLEEN 55 gal dm 0.25 M-I Wate 50 lb sx 56 (as needed for wt) Busan 1060 55 gal dm 2.1 16.37 Install MPD RCD Page 35 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 16.38 Begin drilling 8-1/2” hole section, on-bottom staging technique: x Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8K. x Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations x If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to PU off bottom and restart on bottom staging technique. If stick slip continues, consider adding 0.5% lubes 16.39 Once ~300’ outside of the 9-5/8” shoe, pick up off bottom and activate underreamer per NOV procedure. Verify reamer blades are unlocked 16.40 Drill 8-1/2” x 9-7/8” hole section to ~20,400’ MD (~200’ above CM1) per geologist and Drilling Engineer utilizing the following parameters: x Flow Rate: 500-550 GPM, target min. AV’s in the 9-7/8” openhole: 180 ft/min, 530 GPM x Flow Rate: 500-550 GPM, AV’s in the 9-5/8” casing: 257 ft/min, 530 GPM x RPM: 120+ x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex: concretion deflection x Monitor Torque and Drag with pumps on every 5 stands x Monitor ECD, pump pressure & hookload trends for hole cleaning indication x Monitor downhole WOB/TOB and compare to surface parameters to ensure the bit or the underreamer isn’t being overworked x Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across any sands for an extended period of time. x Limit maximum instantaneous ROP to < 200 FPH. This is to minimize cutter damage if encountering concretions or the Tuffs section in the Colville. x Do not initiate backreaming while the underreamer is unlocked. Backreaming can damage the reamer cutting blocks or possibly back off the pilot BHA. x Prior to picking up off bottom for a connection, ensure WOB has drilled off (hookload and torque returning to free rotating values) and RPM gradually slowed to zero. This is to mitigate the risk of backing off the pilot BHA below the underreamer. x Target ROP is as fast as we can clean the hole without having to backream connections x MPD will be utilized to hold ECD and monitor any pressure build up on connections. x 8-1/2” x 9-7/8” Hole Section A/C: x There are no wells with a CF < 1.0 16.41 Toward the end of the above interval, begin to weight up from 10.5 ppg to 11.0 ppg. Ensure mud is a consistent 11.0 ppg ~200’ before entering the CM1 (projected top at 20,640’ MD). x Use a spike fluid to weight up and add black product for HRZ/Kingak stability. Ensure the fluid is heated to facilitate better mixing of the black product into the mud system and to avoid shocking the formation and inducing losses/breathing 16.42 Drill 8-1/2” hole section from ~20,400’ to section TD per Geologist and Drilling Engineer. Page 36 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure x Flow Rate: 500-550 GPM, target min. AV’s 180 ft/min, 530 GPM in 9-7/8” openhole x Flow Rate: 500-550 GPM, target min. AV’s 257 ft/min, 530 GPM in 9-5/8” casing x RPM: 120+ x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex: concretion deflection x Monitor Torque and Drag with pumps on every 5 stands x Monitor ECD, pump pressure & hookload trends for hole cleaning indication x Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across the sand for any extended period of time. x Limit maximum instantaneous ROP to < 200 FPH while drilling through the Colville. This is to minimize cutter damage if encountering concretions or the Tuffs section in the Colville. x Once in the HRZ, limit maximum instantaneous ROP to < 100 FPH to TD. This is to minimize ECD spikes to cause instability in the shales. x Do not initiate backreaming while the underreamer is unlocked. Backreaming can damage the reamer cutting blocks or possibly back off the pilot BHA. x Prior to picking up off bottom for a connection, ensure WOB has drilled off (hookload and torque returning to free rotating values) and RPM gradually slowed to zero. This is to mitigate the risk of backing off the pilot BHA. x Target ROP is as fast as we can clean the hole without having to backream connections x MPD will be utilized to hold ECD and monitor any pressure build up on connections. x 8-1/2” x 9-7/8” Hole Section A/C: x There are no wells with a CF < 1.0 16.43 TD will be in the SGR formation and confirmed via samples. Do not lock the underreamer blades until SGR samples are verified. Follow NOV/Halliburton parameters for rotating while circulating up samples with the blades unlocked. 16.44 Once samples are verified and the underreamer blades are locked closed, CBU at drilling rate and max rotation. Pump sweeps if needed x Monitor BU for increase in cuttings 16.45 Perform wiper trip to the 9-5/8” casing shoe x Pump out of the hole until above HRZ to maintain ECDs over shale stability minimums. x Pulling speed 5 – 10 min/stand (slip to slip time, not including connections), adjust as dictated by hole conditions x If pulling tight, trip back to TD and begin backreaming operations. x If backreaming operations are commenced, continue backreaming to the shoe 16.46 CBU minimum 5 times at 9-5/8” shoe at maximum flow rate and clean casing with high vis sweeps. 16.47 If trip to 9-5/8” shoe is clean, continue to POOH and LD BHA for upcoming liner run. Page 37 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 16.48 If trip to the shoe is troublesome, run back to TD and CBU 2x or until well cleans up, whichever comes later. 16.49 When at the 9-5/8” shoe, monitor well for flow. Increase mud weight if necessary. x Wellbore breathing has been seen on historical Niakuk wells. Perform extended flow checks to determine if well is breathing, treat all flow as an influx until proven otherwise x If necessary, increase MW at shoe for any higher than expected pressure seen 16.50 Pull RCD Bearing and install trip nipple. 16.51 POOH and LD BHA. Rabbit DP that will be used to run liner. Only LWD open hole logs are planned for the hole section (Triple Combo). There will not be any additional logging runs conducted. Page 38 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 17.0 Run 7” Intermediate 2 Liner 17.1 Well control preparedness: In the event of an influx of formation fluids while running the injection liner, the following well control response procedure will be followed: x P/U & M/U the 5-1/2” safety joint (with 7” crossover installed on bottom, TIW valve in open position on top, 5-1/2” handling joint above TIW). This joint shall be fully M/U and available prior to running the first joint of 7” liner. x Slack off and with 5-1/2” DP across the BOP, shut in ram or annular on 5-1/2” DP. Close TIW. x Proceed with well kill operations. 17.2 Change upper VBRs to 7” casing rams and test to 250 psi low, 4,500 psi high for 5/5 minutes using 7” test joint. 17.3 R/U 7” liner running equipment. x Ensure 7” 26# H-563 x DELTA544 crossover is on rig floor and M/U to FOSV. x Ensure all casing has been drifted on the deck prior to running. x Be sure to count the total # of joints on the deck 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. 17.4 Run 7” injection liner x Use Hydril approved thread compound. Dope pin end only w/ paint brush. Wipe off excess. x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Use lift nubbins and stabbing guides for the liner run. x If liner length exceeds surface casing length, ensure centralizers are placed 1/jt for each joint outside of the surface shoe. x Obtain up and down weights of the liner before entering open hole. x See data sheet on the next page for MU torque for the 7” liner connections. x Centralization: x 1 centralizer every joint on all 7” liner 17.5 Run 7” liner as follows: 7” Float Shoe 1 solid joint – 7”, 2 Centralizers 10’ from each end w/ stop rings 7” Float Collar 1 solid joint – 7”, 1 Centralizer mid joint w/ stop rings 7” Landing collar 1 solid joint – 7”, 1 Centralizer mid joint w/ stop rings 7” 26/# L-80 Hydril 563 – Make up Torque Casing OD Minimum Optimum Maximum 7” 7,800 ft-lbs 9,400 ft-lbs 13,700 ft-lbs Page 39 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure Page 40 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 17.6 Ensure hanger/pkr will not be set in a 9-5/8” connection. x AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as per 20 AAC 25.030(d)(6). Plan is to place liner hanger with ~150’ overlap. Do not place liner hanger/packer across 9-5/8” connection. 17.7 Before picking up Baker SLZXP liner hanger / packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 17.8 M/U Baker SLZXP liner top packer to 7” liner. Circulate 2 liner volumes to clear string and allow for PAL mix to set 17.9 Note: PU, SO, ROT and torque of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 17.10 RIH with liner no faster than 30 ft/min – Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. x Ensure 5-1/2” DP has been drifted x Fill drill pipe on the fly. Monitor FL and if filling is required due to losses/surging. 17.11 Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to bottom. 17.12 Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, & 20 RPM. If torque approaches make-up torque of liner, discontinue rotation. 17.13 Continue to RIH with 7” intermediate 2 liner using the following circulation strategy (Note: Take special care when staging pumps up and down to avoid packing off and breaking down formation): x 9-5/8” shoe to top CM3: Every 5th joint, staging up to planned cementing rate. Circulate for 5 minutes. x Top CM3 to top HRZ: Every 10th joint, staging up to planned cementing rate. Circulate for 5 minutes. x Circulate down consecutive joints to achieve a full bottoms-up by THRZ x Top HRZ to TD: Fill pipe only. Break circulation only if drag appears to be increasing or if there’s indications of getting stuck. Once circulation starts, circulate every stand down to TD. 17.14 Tag bottom and PU to position float shoe ~2’ off bottom. Last motion of the liner should be “up” to ensure it is set in tension. 17.15 Break circulation. Begin circulating at ~0.5 – 1 BPM and monitor pump pressures. Slowly stage up to full circulating rate (planned cementing rates). Allow circulating pressures to stabilize before increasing circulating rate to the next stage. Circulate 4 BU or more if needed to condition hole for cementing. Reduce YP to < 18 to help ensure success of cement job. Do not start the YP Page 41 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure drop until liner is on bottom and cementers are ready. Do not exceed 1,600 psi while circulating for risk of prematurely setting liner hanger. Note all losses. Confirm all pressures with Baker. Page 42 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 18.0 Cement 7” Intermediate 2 Liner 18.1 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 How to handle cement returns at surface. Ensure vac trucks are on standby and ready to assist. x Which pumps will be utilized for displacement, and how fluid will be fed to displacement pump. x Ensure adequate amounts 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. 18.2 Document efficiency of all possible displacement pumps prior to cement job. 18.3 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. 18.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and bottom drillpipe darts into rotating cement head to ensure done in correct order. 18.5 Fill surface cement lines with water and pressure test. 18.6 Pump remaining spacer. 18.7 Drop lower drillpipe dart and pump cement per schedule below. Cement volume based on annular volume + 40% open hole excess. Job will consist of lead and tail slurries, TOC brought to 250’ TVD above TCM3 (TOC and volume to change, depending on as-drilled log data). Estimated Total Cement Volume: Page 43 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure Cement Slurry Design: 18.8 Drop upper 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. 18.9 Displace cement at max rate of 7 bbl/min. Reduce pump rate to 2-3 bpm prior to latching each DP dart into liner wiper plug and park the string with liner on depth. Note plug departure from liner hanger running tool and resume pumping at full displacement rate. Displacement volume can be re-zeroed when the upper drillpipe dart latches into top liner wiper plug. 18.10 If elevated displacement pressures are encountered, position liner at setting depth and cease reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman immediately of any changes. 18.11 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. 18.12 Slack off 20K lbs on the SLZXP liner hanger/packer to ensure the HRDE setting tool is in compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4,500 psi to release the HRDE running tool Slack off total liner weight plus 30k to confirm hanger is set. 18.13 Bleed DP pressure to 0 psi and check floats. Pick up to expose rotating dog sub and set down 50K without pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating at 10-20 RPM and set down 50K again. 18.14 Pickup to verify that the HRD setting tool has released. If running tool cannot be hydraulically released, apply LH torque to mechanically release the setting tool. 18.15 Pressure up drill pipe to 500 psi and pick up to remove the RS packoff bushing from the RS nipple. Bump up pressure as required 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) Lead Slurry Tail Slurry System EconoCem HalCem Density 12.0 lb/gal 15.8 lb/gal Yield 2.35 ft3/sk 1.16 ft3/sk Mix Water 13.92 gal/sk 4.98 gal/sk Page 44 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 18.16 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. 18.17 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. While cement returns will be challenging to observe, watch for them and record the estimated volume. Rotate & circulate to clear cmt from DP. 18.18 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. 18.19 Change upper rams from 7” fixed to 3-1/2” x 5-1/2” VBRs and test with 4” and 5-1/2” test joints to 250 psi low / 4,500 psi high for 5/5 minutes. 18.20 Pressure test casing and liner to 250 psi low / 4,000 psi high for 30 minutes. Do not test until cement has reached minimum 500 psi compressive strength. 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 frank.roach@hilcorp.com and joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 45 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 19.0 Drill 6-1/8” Production Hole Section 19.1 MU 6-1/8” directional BHA x RSS and Triple Combo x Ensure BHA components have been inspected previously. x Drift and caliper all components before MU. Visually verify no debris inside components that cannot be drifted. x Ensure MWD is RU and operational. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. x Drill string will be a tapered string 5-1/2” 21.9# S-135 DELTA 544 and 4” 14.0# S-135 XT39. x Run a solid float in the production hole section. 19.2 TIH w/ 6-1/8” BHA to top of 7” liner. Slowly enter liner top and continue t/TIH to landing collar. Note depth landing collar tagged on AM report. 19.3 RU and test casing/liner envelope to 4,000 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and plot on FIT graph. Document incremental volume pumped (and subsequent pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001. 19.4 Drill out shoe track to 10’ above float shoe. Displace well to 9.7 ppg solids-free drilling fluid. 19.5 Drill out remaining shoe track and 20’ of new formation. 19.6 CBU and condition mud for FIT. x Conduct FIT to 11.5 ppg EMW. Chart Test. Ensure test is recorded on same chart as casing test. Document incremental volume pumped (and subsequent pressure) and volume returned. Submit casing test and FIT digital data to AOGCC. x 11.5 ppg FIT provides >>25bbls based on 10.4 ppg MW +0.5ppg kick intensity, 9.40 ppg EMW PP @TD 19.7 6-1/8” hole section mud program summary: x Density: Primary weighting material to be used for the hole section will be sodium chloride. Additional NaCl will be on location to weight up the active system (1) ppg above highest anticipated MW. x Solids Concentration: It is imperative that the solids concentration be kept low while drilling the production hole section. Keep the shaker screen size optimized and fluid running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible. * Casing test and FIT digital data to AOGCC upon completion of FIT - JJL Page 46 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure x Rheology: Keep viscosifier additions to a minimum (FLO-VIS). Utilize high vis sweeps and tandem sweeps as necessary for hole cleaning. Ensure 6 rpm is > 6 (hole diameter) for sufficient hole cleaning x Run the centrifuge as needed while drilling the production hole, this will help with solids removal. x Dump and dilute as necessary to keep drilled solids to an absolute minimum. x MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, & Toolpusher office. System Type:9.7 – 10.4 ppg PowerPro drilling fluid Properties: Interval Density PV YP API FL HPHT Drill Solids MBT Hardness Production 9.7-10.4 5 – 20 15 – 25 <10 NA <8 <10.0 <200 Product- production Size Pkg ppb or (% liquids) Busan 1060 55 gal dm 0.095 FLOTROL 55 lb sx 6 CONQOR 404 WH (8.5 gal/100 bbls)55 gal dm 0.2 FLO-VIS PLUS 25 lb sx 0.7 KCl 50 lb sx 10.7 SMB 50 lb sx 0.45 LOTORQ 55 gal dm 1.0 SAFE-CARB 10 (verify)50 lb sx 10 SAFE-CARB 20 (verify)50 lb sx 10 Soda Ash 50 lb sx 0.5 19.8 Install MPD RCD 19.9 Begin drilling 6-1/8” hole section, on-bottom staging technique: x Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8K. x Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations x If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to PU off bottom and restart on bottom staging technique. If stick slip continues, consider adding 0.5% lubes 19.10 Drill 6-1/8” hole section to section TD per Geologist and Drilling Engineer. Page 47 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure x Flow Rate: 250-350 GPM, target min. AV’s in the open hole section: 200 ft/min, 175 GPM x Flow Rate: 250-350 GPM, AV’s in the 7” section w/4” DP: 200 ft/min, 191 GPM x Flow Rate: 250-350 GPM, AV’s in the 9-5/8” section w/5-1/2” DP: 190 ft/min, 350 GPM x RPM: 120+ x Pay close attention to circulating pressures. At this depth and with a 5-1/2” x 4” tapered drillstring, circulating pressures may approach maximum of Parker 273’s circulating system. Adjust circulating rates and ROP accordingly. x Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly wet to maximize solids removal efficiency. Check for holes in screens on every connection. x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex: concretion deflection x Monitor Torque and Drag with pumps on every 5 stands x Monitor ECD, pump pressure & hookload trends for hole cleaning indication x Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across the sand for any extended period of time. x Reservoir plan is to drill down into the Ivishak sands before turning up and landing back in the Sag River sands for the horizontal. x There are no projected fault crossings in the production interval. x After making a connection, it may be necessary to start rotation prior to bringing on the pumps. This is to help break the static gels in the mud and minimize the ECD. x Limit maximum instantaneous ROP to < 100 FPH. The sands will drill faster than this, but this is a very short interval to TD. x Be aware of Zone 3 conglomerates and Zone 2 chert. While these intervals are short due to the hole angle, these formations can damage the bit and necessitate a bit trip. x MPD will be utilized to hold ECD and monitor pressure build up on connections. x 6-1/8” Hole Section A/C: x There are no wells with a CF < 1.0 19.11 TD Will be called by the geologist when all tools have reached TD, CBU at drilling rate and max rotation. Pump sweeps if needed x Monitor BU for increase in cuttings 19.12 BROOH to the 7” shoe. x Circulate at full drilling rate x Pulling speed 5 – 10 min/stand (slip to slip time, not including connections), adjust as dictated by hole conditions x If pulling tight, trip back to TD and begin backreaming operations. 19.13 CBU minimum 5 times at the 7” shoe at maximum rate and clean casing with high vis sweeps. 19.14 When at the 9-5/8” shoe, monitor well for flow. Increase mud weight if necessary. Page 48 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure x Perform extended flow checks to determine if well is overbalanced. Treat all flow as an influx until proven otherwise x If necessary, increase MW at shoe for any higher than expected pressure observed 19.15 Pull RCD Bearing and install trip nipple. 19.16 POOH and LD BHA. Rabbit DP that will be used to run liner. Only LWD open hole logs are planned for the hole section (Triple Combo). There will not be any additional logging runs conducted. Page 49 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 20.0 Run 4-1/2” Production Liner 20.1 Well control preparedness: In the event of an influx of formation fluids while running the injection liner, the following well control response procedure will be followed: When M/U & running 4-1/2” liner: x P/U & M/U the 5-1/2” safety joint (with 4-1/2” crossover installed on bottom, TIW valve in open position on top, 5-1/2” handling joint above TIW). This joint shall be fully M/U and available prior to running the first joint of 4-1/2” liner. x Slack off and with 5-1/2” DP across the BOP, shut in ram or annular on 5-1/2” DP. Close TIW. x Proceed with well kill operations. When 4-1/2” liner is fully picked up and RIH on 4” DP: x P/U & M/U the 5-1/2” safety joint (with 4” crossover installed on bottom, TIW valve in open position on top, 5-1/2” handling joint above TIW). This joint shall be fully M/U and available prior to running the first stand of 4” drillpipe. x Slack off and with 5-1/2” DP across the BOP, shut in ram or annular on 5-1/2” DP. Close TIW. x Proceed with well kill operations. 20.2 Upper VBRs to cover the 4-1/2” liner, 5-1/2” x 4” drillpipe used in this operation. 20.3 R/U 4-1/2” liner running equipment. x Ensure 4-1/2” 12.6# VT x DELTA544 crossover is on rig floor and M/U to FOSV. x Ensure 4 XT39 x DELTA 544 crossover is on rig floor and M/U to FOSV. x Ensure all casing has been drifted on the deck prior to running. x Be sure to count the total # of joints on the deck 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. 20.4 Run 4-1/2” production liner x Use Vam approved thread compound. Dope pin end only w/ paint brush. Wipe off excess. x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Use lift nubbins and stabbing guides for the liner run. x Obtain up and down weights of the liner before entering open hole. x See data sheet on the next page for MU torque for the 4-1/2” liner connections. x Run 2 centralizers per joint. One centralizer free floating with stop rings at 4’ and 10’ above pin. Second centralizer locked down 10’ below box. Centralize no higher than 50’ below 7” shoe. x 4-1/2” 12.6/# 13Cr-80 VT – Make up Torque Casing OD Minimum Optimum Maximum 4-1/2” 4,000 ft-lbs 4,440 ft-lbs 4,880 ft-lbs Page 50 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure Page 51 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 20.5 Ensure hanger/pkr will not be set in a 7” connection. x AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as per 20 AAC 25.030(d)(6). Plan is to place liner hanger with ~150’ overlap. Do not place liner hanger/packer across 7” connection. 20.6 Before picking up Baker Flexlock III/ZXP liner hanger / packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 20.7 M/U Baker Flexlock III/ZXP liner hanger / packer assy to 4-1/2” liner. Circulate 2 liner volumes to clear string and allow for PAL mix to set 20.8 Note: PU, SO, ROT and torque of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 20.9 RIH with liner no faster than 30 ft/min – Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. x Ensure all 4” and 5-1/2” DP for the liner run has been drifted x Run enough 4” DP such that the 5-1/2” x 4” DP XO is ~100’ above the 7” liner top with liner on bottom. x Fill drill pipe on the fly. Monitor FL and if filling is required due to losses/surging. 20.10 Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to bottom. 20.11 Before switching elevators and handling equipment from 4” DP to 5-1/2” DP, flow check well for 10 minutes. 20.12 Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, & 20 RPM. If torque approaches make-up torque of liner, discontinue rotation. 20.13 Tag bottom and PU to position float shoe ~2’ off bottom. 20.14 Break circulation. Begin circulating at ~0.5 – 1 BPM and monitor pump pressures. Slowly stage up to full circulating rate (planned cementing rates). Allow circulating pressures to stabilize before increasing circulating rate to the next stage. Circulate 4 BU or more if needed to condition hole for cementing. Reduce YP to < 18 to help ensure success of cement job. Do not start the YP drop until liner is on bottom and cementers are ready. Do not exceed 1,600 psi while circulating for risk of prematurely setting liner hanger. Note all losses. Confirm all pressures with Baker. Page 52 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 21.0 Cement 4-1/2” Production Liner 21.1 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 How to handle cement returns at surface. Ensure vac trucks are on standby and ready to assist. x Which pumps will be utilized for displacement, and how fluid will be fed to displacement pump. x Ensure adequate amounts 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. 21.2 Document efficiency of all possible displacement pumps prior to cement job. 21.3 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. 21.4 R/U cement line (if not already done so). Company Rep to witness loading of the drillpipe dart into rotating cement head. 21.5 Prior to starting cement job, drop ball and set Flexlock liner hanger per Baker representative. 21.6 Slack off 20K lbs on the Flexlock/ZXP liner hanger/packer assembly to ensure the HRDE setting tool is in compression for release from the Flexlock/ZXP liner hanger/packer assembly. Continue pressuring up 4,500 psi to release ball from setting sleeve and the HRDE running tool. Slack off total liner weight plus 30k to confirm hanger is set. 21.7 Fill surface cement lines with water and pressure test. 21.8 Pump remaining spacer. 21.9 Cement volume based on annular volume + 40% open hole excess. Job will consist of tail slurry, TOC brought to top of liner. Page 53 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure Estimated Total Cement Volume: Cement Slurry Design: 21.10 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. 21.11 Displace cement at max rate of 7 bbl/min. Reduce pump rate to 2-3 bpm and park liner on depth 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. 21.12 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. 21.13 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. 21.14 Bleed DP pressure to 0 psi and check floats. Pick up to expose rotating dog sub and set down 50K Pick back up and begin rotating at 10-20 RPM and set down 50K again. 21.15 Pickup to verify that the HRD setting tool has released. If running tool cannot be hydraulically released, apply LH torque to mechanically release the setting tool. Tail Slurry System HalCem Density 15.8 lb/gal Yield 1.16 ft3/sk Mix Water 4.98 gal/sk Page 54 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 21.16 Pressure up drill pipe to 500 psi and pick up to remove the RS packoff bushing from the RS nipple. Bump up pressure as required 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) 21.17 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. 21.18 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. While cement returns will be challenging to observe, watch for them and record the estimated volume. Rotate & circulate to clear cmt from DP. 21.19 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. 21.20 Pressure test casing and liner to 250 psi low / 4,000 psi high for 30 minutes. Do not test until cement has reached minimum 1,000 psi compressive strength. Note: Once running tool is LD, swap to the completion AFE. 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 frank.roach@hilcorp.com and joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 55 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 22.0 Run Upper Completion/ Post Rig Work 22.1 RU to run 4-1/2” 12.6#, 13Cr-80 Vam Top tubing. x Ensure wear bushing is pulled. x Ensure 4-1/2”, 12.6#, Vam Top x 5-1/2” DELTA 544 crossover is on rig floor and M/U to FOSV. x Ensure all tubing has been drifted in the pipe shed prior to running. x Be sure to count the total # of joints in the pipe shed before running. x Keep hole covered while RU casing tools. x Record OD’s, ID’s, lengths, SN’s of all components with vendor & model info. x Monitor displacement from wellbore while RIH. 22.2 PU, MU and RH with the following 4-1/2” completion jewelry (tally to be provided by Operations Engineer): x Torque Turn All Connections x Tubing Jewelry to include (top to bottom): x 1x SSSV nipple profile x 6x GLMs (size and final number to be determined by OE) x 1x ‘X’ Nipple x 1x Production Packer x 1x ‘X’ Nipple x 1x ‘XN’ Nipple with RHC profile installed x 1x WLEG x Tubing is 4-1/2”, 12.6#, 13Cr-80, Vam Top 4-1/2” 12.6/# 13Cr-80 Vam Top – Make up Torque Casing OD Minimum Optimum Maximum 4-1/2” 4,000 ft-lbs 4,440 ft-lbs 4,880 ft-lbs Page 56 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure Page 57 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 22.3 Space out the completion to land such that the 4-1/2” WLEG is inserted half-way into the PBR on the 4-1/2” production liner. Record PU and SO weights prior to picking up tubing hanger. 22.4 MU the tubing hanger and land same. Run in the lock-down screws and torque to spec. 22.5 Reverse circulate heated kill-weight brine. Circulate surface-to-surface at a maximum of 4 BPM with brine and inhibited brine as follows: x Clean brine within the tubing from WLEG to surface x Inhibited brine on the annular side from the shear valve depth to the WLEG x Clean brine on the annular side from surface down to the shear valve. 22.6 Install and pressure test TWC from above. 22.7 ND BOPE. NU the tubing head adapter and tree. 22.8 PT the tubing hanger void to 500/5,000 psi. PT the tree to 250/5,000 psi. 22.9 RU lubricator and pull TWC. 22.10 Freeze protect the wellbore. x Rig up to pump heated diesel down the IA, taking returns up the tubing up the tubing. Reverse 188 bbls heated diesel into the IA. Do not exceed 3bpm while circulating. x Shut in the IA. x Line up to U-tube from the IA to the tubing. x U-tube the diesel and freeze protect the tubing and IA to ~2,200’ MD. 22.11 After u-tube is complete, RU lubricator and install BPV. 22.12 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over with valve alignment as per operations personnel. Page 58 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 22.13 RDMO Parker 273 i. POST RIG WELL WORK (sundry to follow) 1. Slickline/Fullbore a. Pull BPV. b. Set production packer c. Test Tbg and IA to 250 psi low, 4,000 psi high for 5/30 minutes i. Chart test d. Perforate production interval e. Change out GLV per GL ENGR if not done already 2. Well Tie-In Page 59 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 23.0 Parker 273 Rig BOP Schematic Page 60 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 24.0 Wellhead Schematic Page 61 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 25.0 Days Vs Depth Page 62 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 26.0 Formation Tops & Information Page 63 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure Page 64 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure Page 65 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure Page 66 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 27.0 Anticipated Drilling Hazards 12-1/4” Hole Section: Hole Cleaning: Maintain rheology of mud system. Utilize sweeps to evaluate and maintain good hole cleaning (weighted, high-vis, and low-vis/high-vis tandem sweeps all have seen success, depending on hole angle). Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge as needed to control drilled solids. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 800 gpm Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: Crossing faults, known or unknown, can result in drilling into unstable formations that may impact future drilling and liner runs. Talk with Geologist to ensure all known faults are identified and prepared for accordingly. H2S: DS-NK is an H2S location. Below are the most recent H2S values of monitored wells in the Ivishak Pool. Well Name H2S Level Date of Reading #1 Closest SHL Well H2S Level NK-25 20 ppm 4/20/2012 #2 Closest SHL Well H2S Level NK-26A 8 ppm 8/17/2024 #1 Closest BHL Well H2S Level NK-42 76 ppm 2/26/2023 #2 Closest BHL Well H2S Level NK-22A 180 ppm 1/22/2023 Max. Recorded H2S on nearest Pad/Facility NK-21 1,580 ppm 6/25/2022 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. Page 67 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Abnormal Pressures and Temperatures: P Reservoir pressures are expected to be normal. Utilize MPD to mitigate any abnormal pressure seen. Ugnu/West Sak Hardstreaks: Hard formations (which are not necessarily predictable) can be encountered resulting in damage to PDC cutters. Damage occurs due to high impact loading of the bit cutting structure when hard streaks are hit at high ROP. Follow the appropriate mitigation strategy of reducing rotary speed while maintaining WOB. Colville Breathing: This is associated with higher mud weights and higher ECD’s in the Colville mudstones. Monitor ECDs and mud properties. Fingerprint connections to confirm breathing and not a well control event. Anti-Collision Take directional surveys every stand, take additional surveys if necessary. Continuously monitor drilling parameters for signs of magnetic interference with another well. Reference A/C report in directional plan. 12-1/4” Hole Section Specific AC: x There are no wells with a CF < 1.0 Page 68 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 8-1/2” x 9-7/8” Hole Section: Hole Cleaning: Maintain rheology of mud system. Utilize sweeps to evaluate and maintain good hole cleaning (weighted, high-vis, and low-vis/high-vis tandem sweeps all have seen success, depending on hole angle). Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge as needed to control drilled solids. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Reduce ROP (as opposed to flow rate) to control ECD. Maintain circulation rate of > 500 gpm Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: No faults are forecasted to be crossed in this interval. Crossing faults, known or unknown, can result in drilling into unstable formations that may impact future drilling and liner runs. Talk with Geologist to ensure all known faults are identified and prepared for accordingly. H2S: DS-NK is an H2S location. Below are the most recent H2S values of monitored wells in the Ivishak Pool. Well Name H2S Level Date of Reading #1 Closest SHL Well H2S Level NK-25 20 ppm 4/20/2012 #2 Closest SHL Well H2S Level NK-26A 8 ppm 8/17/2024 #1 Closest BHL Well H2S Level NK-42 76 ppm 2/26/2023 #2 Closest BHL Well H2S Level NK-22A 180 ppm 1/22/2023 Max. Recorded H2S on nearest Pad/Facility NK-21 1,580 ppm 6/25/2022 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 69 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure Abnormal Pressures and Temperatures: Reservoir pressures are expected to be normal. Utilize MPD to mitigate any abnormal pressure seen. Colville Breathing: This is associated with higher mud weights and higher ECD’s in the Colville mudstones. Monitor ECDs and mud properties. Fingerprint connections to confirm breathing and not a well control event. Tuffs or “Shale Wall” (CM1): The top of the CM1 is lithologically similar to the shallower CM intervals, but contains some interbedded volcanic tuff beds. Tuffs are hard and abrasive, especially at the top of the interval. Reduce WOB and ROP to maximize bit and reamer life when drilling through the CM1. Formation Breakout (HRZ/Kingak instability): This is related to the fissile (finely laminated) nature of the formation in conjunction with higher pore pressure, which requires higher mud weight to maintain wellbore stability. If splintering cuttings are observed at surface, additional circulations and mud weight may be required. Anti-Collision Take directional surveys every stand, take additional surveys if necessary. Continuously monitor drilling parameters for signs of magnetic interference with another well. Reference A/C report in directional plan. 8.5” x 9-7/8” Hole Section Specific AC: x There are no wells with a CF < 1.0. Page 70 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 6-1/8” Hole Section: Hole Cleaning: Maintain rheology of mud system. Utilize sweeps to evaluate and maintain good hole cleaning (weighted, high-vis, and low-vis/high-vis tandem sweeps all have seen success, depending on hole angle). Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge as needed to control drilled solids. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Reduce ROP (as opposed to flow rate) to control ECD. Maintain circulation rate of > 250 gpm Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: There are 3 possible fault crossings in this interval (2 high probability and 1 low probability). All 3 faults have throws < 100’ and have a low lost circulation risk. Crossing faults, known or unknown, can result in drilling into unstable formations that may impact future drilling and liner runs. Talk with Geologist to ensure all known faults are identified and prepared for accordingly. H2S: DS-NK is an H2S location. Below are the most recent H2S values of monitored wells in the Ivishak Pool. Well Name H2S Level Date of Reading #1 Closest SHL Well H2S Level NK-25 20 ppm 4/20/2012 #2 Closest SHL Well H2S Level NK-26A 8 ppm 8/17/2024 #1 Closest BHL Well H2S Level NK-42 76 ppm 2/26/2023 #2 Closest BHL Well H2S Level NK-22A 180 ppm 1/22/2023 Max. Recorded H2S on nearest Pad/Facility NK-21 1,580 ppm 6/25/2022 4. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 5. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. Page 71 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 6. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Abnormal Pressures and Temperatures: Reservoir pressures are expected to be normal. Utilize MPD to mitigate any abnormal pressure seen. Shublik Breathing: This is associated with higher mud weights and higher ECD’s in the Shublik carbonates. This is different in comparison to the breathing potential in the Colville Mudstones in that the formation will take fluid, but release gas. If treated like a traditional influx, the subsequent weight-up will start the process over with more fluid being lost and then more gas being released. Circulating out the gas via driller’s method and monitor pressures to determine if this is a breathing event or if it is an influx. Zone 4 and Zone 3 Conglomerates; Zone 2 Hard Streaks: Zone 3 conglomerates and Zone 2 chert/hard streaks can hinder ROP. Bit selection is key to avoid a bit trip. Maintain WOB to work through and maintain directional control through the zones. Anti-Collision Take directional surveys every stand, take additional surveys if necessary. Continuously monitor drilling parameters for signs of magnetic interference with another well. Reference A/C report in directional plan. 6-1/8” Hole Section Specific AC: x There are no wells with a CF < 1.0. Page 72 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 28.0 Parker 273 Rig Layout Page 73 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 29.0 FIT 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. Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental volume pumped and returned during test. Page 74 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 30.0 Parker 273 Rig Choke Manifold Schematic Page 75 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 31.0 Casing Design Page 76 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 32.0 12-1/4” Hole Section MASP Page 77 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 33.0 8-1/2” x 9-7/8” Hole Section MASP Page 78 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 34.0 6-1/8” Hole Section MASP Page 79 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 35.0 Spider Plot (NAD 27) (Governmental Sections) Page 80 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 36.0 Surface Plat (As Built) (NAD 27) CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From:Frank Roach To:Lau, Jack J (OGC) Cc:Joseph Lastufka Subject:RE: [EXTERNAL] RE: NK-41B Changes (PTD: 224-153) Date:Friday, March 14, 2025 9:27:23 AM Attachments:image002.png Jack, As of now, we are not expecting hydrocarbons or fresh water above the newly planned TOC in the 7” section. However, we will confirm this with the as-drilled logs and adjust if needed. I just received the updated directional plan and buttoning up the edits to the drilling program. I should have this out around the end of lunch for submittal. Regards, Frank V Roach Drilling Engineer Hilcorp Alaska, LLC 907.854.2321 mobile 907.777.8413 office From: Lau, Jack J (OGC) <jack.lau@alaska.gov> Sent: Friday, March 14, 2025 9:22 AM To: Frank Roach <Frank.Roach@hilcorp.com> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: [EXTERNAL] RE: NK-41B Changes (PTD: 224-153) Thanks for the detailed update Frank. As for not fully cementing the 7”, please verify there are no hydrocarbons or fresh water in the uncemented section above the CM3. When can we expect the 10-403? Jack From: Frank Roach <Frank.Roach@hilcorp.com> Sent: Thursday, March 13, 2025 3:48 PM To: Lau, Jack J (OGC) <jack.lau@alaska.gov> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: NK-41B Changes (PTD: 224-153) Jack, Following up from our conversation on Tuesday. As we discussed, we stacked out hard with our 9-5/8” casing at 14,148’ – 14,150’ MD. This depth correlates with ending up in the original hole and stacking out at the cleanout assembly depth (~30’-40’ above the LIH BHA) so we think we’re in the original hole and missed the sidetrack. Looking at the risks, the safe bet was to cement the 9-5/8” casing in place. That was completed yesterday (no losses during the job, top plug bumped on strokes). We are currently running in with a cleanout assembly with survey tools. We will be using the survey tools to confirm which hole we’re in (determined by taking checkshots around the sidetrack point). Once we determine which hole we’re in, PB1 and PB2 depths will be documented accordingly. Including the BHA currently in the hole, there will be a couple extra runs needed in order to get back on to plan: *Current*: Cleanout BHA to perform checkshots confirm which hole the 9-5/8” found, tag plugs, and drill out shoetrack to ~2’ of the float shoe (bury the whipstock as deep as possible). Whipstock runs and milling the window Kickoff motor assembly to ensure we’re clear of the plugback hole (and LIH BHA if we’re indeed in PB1) Kick tolerance modeling shows the 12.9ppg EMW provides >25 bbls kick tolerance as the loss in MD didn’t change the TVD much at 75degrees. Two changes made to Intermediate 2 will be the tubular connection and the cement job volume. The extended 7” length exceeded the footage of 7” 26# L-80 VamTop we have available. This will be replaced with 7” 26# L-80 Hydril 563 and maintain our premium thread in this interval. With the shallower 9-5/8” shoe, there’s concern about fully cementing the 7” liner and the ECDs causing us to lose circulation. Cement will be brought to ~16,473’ MD. This is ~250’ TVD above the top CM3. Also attached is another updated schematic, showing the updated depths, and the most likely position of casing and the two plugbacks. ***NOTE*** this could change with the results of the checkshots. As before, we’ll be submitting a 10-403 with these changes, but wanted to get this in front of you as soon as possible as the picture became clearer. Let me know if you need anything additional. Regards, Frank V Roach Drilling Engineer Hilcorp Alaska, LLC 907.854.2321 mobile 907.777.8413 office 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 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. UNDEFINED SAG RIVER AND IVISHAK Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2025.03.07 12:39:51 - 09'00' Sean McLaughlin (4311) 325-133 RUSH By Gavin Gluyas at 2:36 pm, Mar 07, 2025 A.Dewhurst 07MAR25 10-407 * BOPE test to 4500 psi. Annular to 3500 psi. * Casing test and FIT digital data to AOGCC upon completion of FIT. DSR-3/10/25JJL 3/7/25 *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.03.11 13:37:47 -08'00'03/11/25 RBDMS JSB 031325 Prudhoe Bay East (PBU) NK-41B Drilling Program Version 2 03/07/2025 Table of 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 ................................................................................................... 9 8.0 Mandatory Regulatory Compliance / Notifications .................................................................. 10 9.0 Pre-Rig, R/U, and Preparatory Work ........................................................................................ 13 10.0 N/U BOPE ..................................................................................................................................... 14 11.0 Decomplete, Cut & Pull 9-5/8”, Set 13-3/8” P&A Plug ............................................................ 15 12.0 Set Whipstock, Mill 12-1/4” Window ......................................................................................... 18 13.0 Drill 12-1/4” Intermediate 1 Hole Section ................................................................................. 21 14.0 Run 9-5/8” Intermediate 1 Casing .............................................................................................. 25 15.0 Cement 9-5/8” Intermediate Casing ........................................................................................... 28 16.0 Drill 8-1/2” x 9-7/8” Intermediate 2 Hole Section ..................................................................... 31 17.0 Run 7” Intermediate 2 Liner ...................................................................................................... 36 18.0 Cement 7” Intermediate 2 Liner ................................................................................................ 39 19.0 Drill 6-1/8” Production Hole Section.......................................................................................... 42 20.0 Run 4-1/2” Production Liner ...................................................................................................... 46 21.0 Cement 4-1/2” Production Liner ................................................................................................ 50 22.0 Run Upper Completion/ Post Rig Work .................................................................................... 53 23.0 Parker 273 Rig BOP Schematic .................................................................................................. 57 24.0 Wellhead Schematic ..................................................................................................................... 58 25.0 Days Vs Depth .............................................................................................................................. 59 26.0 Formation Tops & Information .................................................................................................. 60 27.0 Anticipated Drilling Hazards ...................................................................................................... 64 28.0 Parker 273 Rig Layout ................................................................................................................ 70 29.0 FIT Procedure .............................................................................................................................. 71 30.0 Parker 273 Rig Choke Manifold Schematic .............................................................................. 72 31.0 Casing Design ............................................................................................................................... 73 32.0 12-1/4” Hole Section MASP ........................................................................................................ 74 33.0 8-1/2” x 9-7/8” Hole Section MASP ............................................................................................ 75 34.0 6-1/8” Hole Section MASP .......................................................................................................... 76 35.0 Spider Plot (NAD 27) (Governmental Sections) ........................................................................ 77 36.0 Surface Plat (As Built) (NAD 27) ................................................................................................ 78 Page 2 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 1.0 Well Summary Well PBU NK-41B Pad Prudhoe Bay DS-NK Planned Completion Type 4-1/2” Production Tubing Target Reservoir(s) Sag / Ivishak Sands Planned Well TD, MD / TVD 21,888’ MD / 10,166’ TVD PBTD, MD / TVD 21,800’ MD / 10,097’ TVD Surface Location (Governmental) 1,474' FSL, 717' FEL, Sec 36, T12N, R15E, UM, AK Surface Location (NAD 27) X= 721,841.38, Y= 5,980,017.95 Top of Productive Horizon (Governmental)1,308' FNL, 1,384' FEL, Sec 28, T12N, R16E, UM, AK TPH Location (NAD 27) X= 736,341.30, Y= 5,988,242.18 BHL (Governmental) 1,196' FNL, 1,161' FEL, Sec 28, T12N, R16E, UM, AK BHL (NAD 27) X= 736,560.06, Y= 5,988,360.75 AFE Number 241-00161 AFE Drilling Days 55 AFE Completion Days 8 Maximum Anticipated Pressure (Surface) 3958 psig Maximum Anticipated Pressure (Downhole/Reservoir) 4971 psig Work String 5-1/2” 21.9# S-135 DELTA 544 4” 14# S-139 XT-39 Parker 273 KB Elevation above MSL: 19.4 ft + 46.95 ft = 66.35 ft GL Elevation above MSL: 19.4 ft BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams Page 3 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 2.0 Management of Change Information Page 4 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 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 20” 19.25 - - - X-52 Weld *16” 13-3/8” 12.415 12.259 14.375 68 L-80 BTC 5,020 2,270 1,556 12-1/4” 9-5/8” 8.681 8.525 10.625 47 L-80 DWC-C 6,870 4,760 1,086 8-1/2”x 9-7/8”7” 6.276 6.151 7.656 26 L-80 VamTop 7,240 5,410 604 6-1/8 4-1/2” 3.958 3.833 4.937 12.6 13Cr-80 VamTop 8,430 7,500 288 Tubing 4-1/2” 3.958 3.833 4.937 12.6 13Cr-80 VamTop 8,430 7,500 288 *Existing hole section and casing string 4.0 Drill Pipe Information: Hole Section OD (in) ID (in)TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn M/U (Min) M/U (Max) Tension (k-lbs) Surf, Int, & Prod 5-1/2”4.778” 4.000” 6.625” 21.9 S-135 Delta 544 41,900 58,700 786klb 4”3.340” 2.688” 4.875” 14.0 S-135 XT39 17,700 21,200 513klb All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 5 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 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 Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area – this will not save the data entered, and will navigate to another data entry. x Ensure time entry adds up to 24 hours total. x Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. x Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 5.2 Afternoon Updates x Submit a short operations update each work day to sean.mclaughlin@hilcorp,com, frank.roach@hilcorp.com, nathan.sperry@hilcorp.com, jengel@hilcorp.com and joseph.lastufka@hilcorp.com 5.3 Intranet Home Page Morning Update x Submit a short operations update each morning by 7am on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 5.4 EHS Incident Reporting x Health and Safety: Notify EHS field coordinator. x Environmental: Drilling Environmental Coordinator x Notify Drilling Manager & Drilling Engineer on all incidents 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, frank.roach@hilcorp.com, jengel@hilcorp.com and joseph.lastufka@hilcorp.com 5.6 Casing and Cement report x Send casing and cement report for each string of casing to sean.mclaughlin@hilcorp,com, frank.roach@hilcorp.com, jengel@hilcorp.com and joseph.lastufka@hilcorp.com 5.7 Hilcorp Contact List: Title Name Work Phone Email Drilling Manager Sean McLaughlin 907.223.6784 sean.mclaughlin@hilcorp.com Drilling Engineer Frank Roach 907.777.8413 frank.roach@hilcorp.com Drilling Engineer Joe Engel 907.777.8395 jengel@hilcorp.com Drilling Engineer Nate Sperry 907.777.8450 nathan.sperry@hilcorp.com Completion Engineer Eric Dickerman 907.564.4061 eric.dickerman@hilcorp.com Geologist Ryan Phelps 907.777.8361 ryan.phelps@hilcorp.com Reservoir Engineer Jeff Allen 907.777.8428 jallen@hilcorp.com Drilling Env. Coordinator Adrian Kersten 907.564.4820 adrian.kersten@hilcorp.com Drilling Tech Joe Lastufka 907.777.8400 Joseph.Lastufka@hilcorp.com _____________________________________________________________________________________ Created By: JNL 3/7/2025 CURRENT SCHEMATIC Niakuk Unit Well: NK 41B Last Completed: TBD PTD: 224-153 GENERAL WELL INFO API: 50-029-22778-02-00 Completed: TBD CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5 / X56 / Weld N/A Surface 110’ N/A 13-3/8” Surface 68 / L-80 / BTC 12.415” Surface 4,205’ 0.1497 9-5/8” Intermediate 47 / L-80 / DWC/C 8.835” Surface 15,176’ 0.0758 7” Liner 26 / L-80 / TXP 6.276” 15,026’ 21,399’ 0.0383 4-1/2” Liner 12.6 / L-80 / VT 3.958” 21,149’ 21,888’ 0.0152 TUBING DETAIL 4-1/2” Tubing 12.6 / L-80 / VT 3.958” Surface 21,311’ 0.0152 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status TD =15,176’(MD) / TD =7,000’(TVD) 13-3/8” Window @ 4,205’ MD KB Elev: = 65.14’ / GL Elev: = 19.4’ Fish: RCT BHA 14188’ – 14963’ PBTD=15,176’ (MD) / PBTD =7,000’(TVD) PB1: 12570’ – 15336’ OPEN HOLE / CEMENT DETAIL Driven 17-1/2” 2038 sx PF E, 54 sx PF C, 1190 sx Class G 12-1/4” TBD 8-1/2” x 9-7/8” TBD 6-1/8” TBD JEWELRY DETAIL No Depth ID Item 1 ~17,357’ 6.190” 9-5/8” x 7” Liner Hanger/LTP 2 ~21,311’ 3.910” 7” x 4-1/2” Liner Hanger/LTP 3 ~21,315’ 3.813” WLEG 4 ~21,300’ 3.725” XN Nipple 5 ~21,270’ 3.813” X Nipple 6 ~21,240’ 3.873” Production Packer 7 ~21,210’ 3.813” X Nipple 8 TBD TBD GLM (number, sizes and depths TBD) 9 ~2,200’ 3.813” Nipple profile for SSSV WELL INCLINATION DETAIL KOP @ 4,205’ Max Angle 74.58 deg @ 4,952’ TREE & WELLHEAD Tree Wellhead Page 8 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure Proposed Schematic: Page 9 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 7.0 Drilling / Completion Summary NK-41B is a sidetrack producer planned to be drilled in the Sag and Ivishak sands. The parent wellbore, NK-41A, is a shut-in, suspended well since November, 1997. The 1997 lower abandonment was confirmed on 12/11/24, prior to the rig’s arrival on the well. Operations covered on a separate sundry. The directional plan is a 12-1/4” intermediate 1 hole will be drilled and 9-5/8” casing set in the CM3. An 8- 1/2”x9-7/8” underreamed intermediate 2 hole will be drilled and 7” liner set at TSGR. A 6-1/8” slant section will be drilled across the Sag River and Ivishak formations and TD in BSAD. A 4-1/2” production liner will be run and cemented in place. The well will be completed with 4-1/2” production tubing. Perforating will be performed post-rig. Parker 273 will be used to finish decomplete, drill, and complete the wellbore. Drilling operations are expected to commence approximately January 11, 2024, pending rig schedule. All cuttings & mud generated during drilling operations will be hauled to one of two locations: Primary: Prudhoe G&I on Pad 4 Secondary: the Milne Point “B” pad G&I facility General sequence of operations: 1. MIRU Parker 273 to well site 2. N/U & Test BOPE 3. Pull Hanger. Cut and pull 9-5/8” casing. 4. Run whipstock and mill 12-1/4” window. 5. Drill 12-1/4” to TD of intermediate 1 hole section. 6. Run and cement 9-5/8” intermediate 1 casing 7. Drill 8-1/2”x9-7/8” to TD of intermediate 2 hole section. 8. Run and cement 7” intermediate 2 liner 9. Drill 6-1/8” hole to TD 10. Run and cement 4-1/2” production liner 11. Run Upper Completion 12. N/D BOP, N/U Tree, RDMO Reservoir Evaluation Plan: 1. Intermediate 1 Hole: No mud logging. Remote Ops geologist. LWD: GR + Res 2. Intermediate 2 Hole: Mud logging. Field Ops geologist for casing pick. Triple Combo 3. Production Hole: Mud logging. Field Ops geologist. Triple-Combo For any cuttings collected, submit a set of washed and dried cuttings to AOGCC as per 20 AAC 25.071(b)(2). -A.Dewhurst 07MAR25 Page 10 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with all applicable AOGCC regulations, specific regulations are listed below. 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 (1) week intervals during the decompletion of PBU NK-41A. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. x BOPs shall be tested at (2) week intervals once the window has been milled and during the drilling and completion of PBU NK-41B. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. x The initial and subsequent tests of BOP equipment will be to 250/4,500 psi for 5/5 min (annular to 70% rated WP, 3,500 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 control fluid flow from the well bore, AOGCC is to be notified and we must 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 7-14 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”. o Ensure the diverter vent line is at least 75’ away from potential ignition sources x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. x Casing pressure test criteria in 20 AAC 25.030 (e) Casing and Cementing,“A casing pressure test must be performed if BOPE is to be installed on a casing. The casing must be tested to hold a minimum surface pressure equal to 50 percent of the casing internal yield pressure. The test pressure must show stabilizing pressure and may not decline more than 10 percent within 30 minutes. The results of this test and any subsequent tests of the casing must be recorded as required by 20 AAC 25.070(1)”. Page 11 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure AOGCC Regulation Variance Requests: x No variances are requested at this time. Summary of Parker 273 BOP Equipment & Test Requirements Hole Section Equipment Test Pressure (psi) 12-1/4” x 13-5/8” x 5M Annular BOP x 13-5/8” x Double Gate o Blind ram in btm cavity x Mud cross w/ 3-1/8” x 5M side outlets x 13-5/8” x Single ram x 3” x 5M Choke Line x 2” x 5M Kill line x 3” x 5M Choke manifold x Standpipe, floor valves, etc Initial Test: 250/4,500 Annular: 250/3,500 Subsequent Tests: 250/4,500 Annular: 250/3,500 8-1/2” x 13-5/8” x 5M Annular BOP x 13-5/8” x Double Gate o Blind ram in btm cavity x Mud cross w/ 3-1/8” x 5M side outlets x 13-5/8” x Single ram x 3” x 5M Choke Line x 2” x 5M Kill line x 3” x 5M Choke manifold x Standpipe, floor valves, etc 6-1/8” x 13-5/8” x 5M Annular BOP x 13-5/8” x Double Gate o Blind ram in btm cavity x Mud cross w/ 3-1/8” x 5M side outlets x 13-5/8” x Single ram x 3” x 5M Choke Line x 2” x 5M Kill line x 3” x 5M Choke manifold x Standpipe, floor valves, etc Primary closing unit: Sara Koomey Control Unit, 3,000 psi, 316 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is an air-driven pump and emergency pressure is provided by bottled nitrogen. The remote closing operator panels are located in the doghouse and on accumulator unit. Page 12 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 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 spud. x 24 hours notice prior to testing BOPs. x 24 hours notice prior to casing running & cement operations. x Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email:melvin.rixse@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) Page 13 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 9.0 Pre-Rig, R/U, and Preparatory Work 9.1 Prior to the rig’s arrival, the following steps should have been completed (for more detail, refer to the 10-403 for NK-41A): x MIT 9-5/8” Casing (passed to 2,174psi on 12/11/24) x MIT-OA (established open shoe @ 1,900psi on 12/11/24) x CBL and drift of 9-5/8” Csg from 8,000’ to surface x Install 9-5/8” plug and pressure test same x Punch 9-5/8” csg @ ~6,990’ and circ clean through OA x Cement down 9-5/8” and up 9-5/8” x 13-3/8” annulus with annular planned TOC at 6,000’ x After cement reaches compressive strength, tag plug and CMIT TxIA t/2,500psi 9.2 NK-41B will utilize NK-41A’s wellhead and surface casing on DS-NK. Ensure to review attached surface plat and make sure rig is over appropriate wellhead. 9.3 Ensure PTD and drilling program are posted in the rig office and on the rig floor. 9.4 Level pad and ensure enough room for layout of rig footprint and R/U. 9.5 Rig mat footprint of rig. 9.6 Ensure any necessary wellhead equipment is staged prior to MIRU. 9.7 MIRU Parker 273 Ensure rig is centered over wellhead to prevent any wear to BOPE or wellhead. 9.8 Note: 9.8 ppg NaCl brine should be left in the well from the pre-rig decomplete work. Confirm fluids in handover to ensure consistent fluids will be in the well prior to displacing to milling fluid. 9.9 Ensure 5-3/4” liners in mud pumps. x NOV 12-P-160 1,600 HP mud pumps are rated at 5,085 psi, 466 gpm @ 120 spm @ 96% volumetric efficiency. Page 14 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 10.0 N/U BOPE 10.1 Install TWC in hanger profile. Pressure test to 250/4,500 psi for 5 min. 10.2 N/D tree and adapter flange. 10.3 N/U 13-5/8 x 5M BOP as follows: x BOP configuration from top down: 13-5/8” x 5M annular / 13-5/8” x 5M double gate / 13- 5/8” x 5M mud cross / 13-5/8” x 5M single gate x Double gate ram should be dressed with 2-7/8” x 5” VBRs or 5” solid body rams in top cavity,blind ram in bottom cavity. x Single ram can be dressed with 2-7/8” x 5” VBRs or 5” solid body rams x NU bell nipple, install flowline. x Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to mud cross). x Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual valve 10.4 RU MPD RCD and related equipment 10.5 Notify AOGCC and Test BOP to 250/4,500 psi for 5/5 min. Test annular to 250/3,500 psi for 5/5 min. x Test with 5” test joint and test VBR’s with 4” and 5” test joints x Smallest and largest pipes to be ran x Confirm test pressures with PTD x Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure is trapped underneath test plug x Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech 10.6 RD BOP test equipment. 10.7 Pull TWC. Page 15 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 11.0 Decomplete, Cut & Pull 9-5/8”, Set 13-3/8” P&A Plug 11.1 Pull hanger and pup joint to rig floor and L/D. 11.2 P/U 8-1/2” cleanout assembly: 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 Utilize used roller cone bit with jets removed for maximum flow. x Drill string will be 5” 19.5# S-135. 11.3 RIH w/cleanout assy to ~5,660’ MD (Last tagged by e-line on 1/12/2025) 11.4 Slowly wash down and tag cement plug from pre-rig work. CBU 2-4x ensuring clean 9.8ppg brine in and out. 11.5 Flow check well. POOH & LD cleanout assembly MOC-1 11.6 MU mechanical casing cutter BHA per fishing representative. Make sure cutters are dressed to be able to cut 9-5/8” 47# BTC-M casing. 11.7 RIH to cut depth @ ~5,600’ MD. Locate the collars above and below proposed cut depth. Cut casing in the middle of the joint identified by the coupling locate. x After the pressure drop indicating the cut is seen spin the cutter for an additional 15 minutes. This helps to ensure that the cutter blades have completely cut through the casing. x If the cut appears to go poorly (casing grabs blades, other anomalies), plan to make the casing stub polishing run. Final decision for the polishing/scraper run may be made once the cut joint is pulled 11.8 Line up to take returns from the OA to the flowback tank(s). Close annular around drillpipe, break circulation, and CBU 2x min at max rate. After consistent brine is observed in and out, shut down and flow check well for 30 minutes to confirm well is in balance. 11.9 POOH and LD casing cutter BHA. 11.10 Back out lockdown screws. x Reporting is inconsistent on the 9-5/8” casing set. Drilling report states casing was set on slips, but the tally summary sheet notes a casing hanger. Be prepared for the potential of casing growth. If the last couple lockdown screws become tight when backing out, Stop and retighten LDS. RIH w/HWDP/collars and hang off with a RTTS (or equivalent) packer. While staying connected to the packer, attempt to back out LDS again. Once successful, release RTTS, lay down packer, and HWDP. Page 16 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 11.11 Spear and pull 9-5/8” casing to the floor. Release spear and LD same. LD 9-5/8” casing down to the cut. Note torque required to break connections, overall condition of the casing, and the cut. Depending on condition, joints may be salvaged for future shoetrack/pup joints. Inspect casing for NORM prior to removal from location. 11.12 MU 13-3/8” drift/cleanout assembly. Ensure casing scraper or smooth OD stabilizer / string mill is in the BHA to clean area where retainer is to be set. Also ensure BHA is close to mimicking whipstock assembly for drifting. RIH to 9-5/8” casing stump. 11.13 CBU at least 2x @ max rate to ensure clean casing. Wipe retainer setting area multiple times to help ensure a good set. POOH & LD cleanout BHA. 11.14 MU 13-3/8” cement retainer and RIH t/50’ above the casing stub. Ensure retainer is spaced out such that it won’t be set across a connection. Set retainer and slack off string weight to confirm retainer is set. x Provide AOGCC inspector 24 hr notice of retainer set for opportunity to witness weight testing to confirm set. 11.15 Establish injection below the retainer. Once pressure breaks over, pump additional 5 bbls to confirm injection. 11.16 Unsting from the retainer and spot 45 bbls 15.8ppg Class G cement within 5 bbls of the end of the stinger. Estimated Total Cement Volume: Cement Slurry Design: Tail Slurry System HalCem Density 15.8 lb/gal Yield 1.16 ft3/sk Mix Water 4.98 gal/sk Page 17 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 11.17 Once spotted, sting back into the retainer and squeeze 30 bbls below the retainer. This volume is 150’ worth of 13-3/8” capacity (22.5 bbls) plus 7.5 bbls excess. 11.18 With 15 bbls left in the workstring/stinger, unsting and spot remaining 15 bbls on top of the retainer. This volume equates to 50’ of 13-3/8” capacity above the retainer (7.5 bbls), plus another 7.5 bbls excess. 11.19 Pull up above the cement spotted on top of the retainer and circulate to clean up string. POOH & LDBHA 11.20 Wait on cement to reach a minimum of 500psi compressive strength before continuing. Page 18 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 12.0 Set Whipstock, Mill 12-1/4” Window 12.1 MU 13-3/8” cleanout assembly (to include 12-1/4” bit and 13-3/8” casing scraper). Space out casing scraper where it will cover planned whipstock setting depth and contingency bridge plug depth. RIH with cleanout assembly to ~100’ above the abandonment plug. 12.2 Slowly RIH and tag cement on top of retainer. CBU 2-4x while pumping pills/sweeps to help in cleaning the 13-3/8” casing. Ensure fluid is consistent both in and out before shutting down. 12.3 RU casing testing equipment and PT 13-3/8” casing to 2500 psi for 30 min, chart test. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001. x Provide AOGCC inspector 24 hr notice for opportunity to witness pressure test. 12.4 Flow check well for 10 minutes prior to tripping out. POOH & LD cleanout assembly. 12.5 Whipstock set depth information: x Planned TOW: 4,254’ x Whipstock should be set to avoid a collar while milling the window. x Drilling Foreman, Whipstock hand, and drilling engineer to agree on set depth 12.6 MU 12-1/4” mill/whipstock assembly as per WIS tally: x MU HWDP, string magnets, and float sub x Ensure ditch magnets are installed in shaker room and cleaned prior to running in with the whipstock 12.7 Install MWD and orient. Rack back mill assembly x Ensure a dedicated MWD is available for the orientation of the whipstock 12.8 Verify offset between MWD and the whipstock tray, witnessed and agreed by the Drilling Foreman, MWD/DD personnel, and WIS rep. Document and record offset in well file. 12.9 Slowly RIH with whipstock assembly per WIS rep. x RIH no faster than 1.5 to 2 minutes per stand. x Ensure workstring is stationary prior to setting in slips to avoid weakening shear bolt and prematurely tripping/setting the anchor. 12.10 Stop 30-45’ above planned set depth. Work torque out of string. Measure and record P/U and S/O weights. Obtain survey with MWD for orienting whipstock. 12.11 Orient whipstock to desired direction by turning DP in ¼ round increments. P/U and S/O on DP to work all torque out after oriented. (Being careful not to set trip anchor). Target orientation is 30q LOHS – Consult with milling hand 12.12 Whipstock orientation: Page 19 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure x Desired orientation of the whipstock face is 15R to 45R, target is 20 ROHS x Hole Angle at window interval (@ 4,254’, 55° inc, 46° azi) x Sidetrack tangent section is 74q inclination and 63q azimuth 12.13 Once whipstock is in the desired orientation, set whipstock per WIS rep. 12.14 Displace well over to 9.0 ppg milling fluid. Confirm fluid in and out has correct parameters and sufficient for moving metal shavings/cuttings uphole: x Funnel visc: 40-60s x YP: 18-20 12.15 Record P/U, S/O weights, and free rotation. Slack off to top of whipstock and with light weight and low torque. Mill window as per whipstock contractor representative. Pump high visc sweeps as necessary. 12.16 Clean catch trays and ditch magnets frequently while milling window to collect metal cuttings/shavings. Track weight of recovered metal to gauge whether window milling was complete. 12.17 Mill window until the uppermost mill has passed across the entire tray. Dress and polish window as needed. 12.18 With upper mill at the end of the tray, this will drill ~ 20’ of new hole. 12.19 After window is milled but before POOH, shut down pumps and work milling assembly through window watching for drag. Dress and polish window as needed. After reaming, shut off pumps and rotary and dry drift window. 12.20 Circulate bottoms up until even MW in/out and hole is clean of metal shavings. Reduce mud properties for drilling or displace over to 9.0 ppg LSND drilling fluid. 12.21 Pull window milling assembly into 13-3/8” casing and perform FIT to 12.5ppg EMW. Chart test. Ensure test is recorded on same chart as the casing test. Document incremental volume pumped (and subsequent pressure) and volume returned. 45R 15R Page 20 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure x 13-3/8” surface casing is fully cemented. Open hole weak point is the top of the window and ~ 4,254’ MD / ~ 3,956’ TVD. x 12.5 ppg FIT value is to cover over and above expected ECD while drilling interval. x 12.3 ppg provides >25 bbls based on 11.0 ppg MW +0.5ppg intensity, 10.0 ppg PP. x If 12.3 ppg EMW is not achieved, contact drilling engineer. 12.22 POOH and LD window milling BHA. Gauge all mills for wear. Depending on results, have backup milling assembly ready to dress window to desired dimensions. 12.23 PU stack washer and wash across BOPE. Function all rams to clear any potential milling debris. Page 21 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 13.0 Drill 12-1/4” Intermediate 1 Hole Section 13.1 P/U 12-1/4” RSS directional BHA. 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 Ensure MWD is R/U and operational. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. x Drill string will be 5-1/2” 21.9# S-135 DELTA 544. x Run a non-ported float in the production hole section. 13.2 12-1/4” hole section mud program summary: x Density: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. x Solids Concentration:Keep the shaker screen size optimized and fluid running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible. x Rheology: Keep viscosifier additions reasonably low. Utilize sweeps (weighted, high vis, tandem) to inform hole cleaning efficiency. Ensure 6 rpm is > 12 (~hole diameter) for sufficient hole cleaning x Run the centrifuge as needed while drilling the intermediate hole, this will help with solids removal. x Dump and dilute as necessary to keep drilled solids to an absolute minimum. x MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, & Toolpusher office. System Type:9.0 – 11.0 ppg LSND drilling fluid Properties: Interval Density PV YP API FL HPHT Drill Solids MBT Hardness ~4,254’ – ~9,422’ Window – UG4 9.0 – 9.6 5 – 20 15 – 30 < 8 N/A <6% <12 <200 ~9,422’ – ~17,408’ UG4 – CM3 9.6 – 10.6 5 – 20 15 – 30 < 6 N/A <6% <20 <200 ~17,408’ – TD CM3 – TD 10.5 – 11.0 5 – 20 15 – 30 < 6 <10 <6% <20 <200 Page 22 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure System Formulation: Product- intermediate Size Pkg ppb or (% liquids) Soda Ash 50 lb sx 0.17 PowerVIS 25 lb sx 1.5 – 2.0 M-I Pac UL 50 lb sx 3.0 Hydrahib/Kla-Stop 55 gal dm 1.0 – 1.5 KCl 50 lb sx 10.7 SCREENKLEEN 55 gal dm 0.25 M-I Wate 50 lb sx 56 (as needed for wt) Busan 1060 55 gal dm 2.1 13.3 Displace wellbore to 10.0 ppg LSND drilling fluid 13.4 Obtain initial ECD benchmark readings prior to drilling ahead. 13.5 Drill 12-1/4” hole section from 13-3/8” window to ~ 9,200’ MD (~200’ MD above UG4) per Geologist and Drilling Engineer Utilizing the following parameters: x Flow Rate: 700-950 GPM x RPM: Maximize RPM when rotating Take the first couple stands to understand BHA tendency. x Ensure shakers are set up to handle this flowrate. Ensure shakers are running slightly wet to maximize solids removal efficiency. Check for holes in screens on every connection. x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex: concretion deflection x Monitor Torque and Drag with pumps on every 5 stands x Monitor ECD, pump pressure & hookload trends for hole cleaning indication. Attempt to limit drilling ECD to 1.0 ppg over calculated cleanhole ECD. x Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across any sands for any extended period of time. x Limit maximum instantaneous ROP to < 200 FPH. The SV sands will drill faster than this, but good hole cleaning practices now reduces time needed to cleanup prior to running casing. x Limit WOB to 20k max to maintain bit stability when encountering hard stringers in the UG4-UG1 x 12-1/4” Hole Section A/C: x There are no wells with a CF < 1.0 13.6 Toward the end of the above interval, begin to weight up from 9.0 ppg to 9.6 ppg. Ensure mud is a consistent 9.6 ppg ~200’ before entering the UG4. x If using a spike fluid to weight up, ensure the fluid is heated to avoid shocking the formation Page 23 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure MOC-2 13.7 Drill 12-1/4” hole section from ~9,200’ MD to section TD in the UG1, utilizing the following parameters: x Flow Rate: 700-950 GPM x RPM: Maximize RPM when rotating x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex: concretion deflection x Monitor Torque and Drag with pumps on every 5 stands x Monitor ECD, pump pressure & hookload trends for hole cleaning indication x Limit maximum instantaneous ROP to < 200 FPH. Good hole cleaning practices now reduces time needed to cleanup prior to running casing. x Limit WOB to 20k max to maintain bit stability when encountering hard stringers in the UG4-UG1 x Once CM3 is penetrated, limit ECD to 0.5 ppg over calculated clean-hole ECD. Pay close attention to pump pressure to reduce Colville breathing risk. x 12-1/4” Hole Section A/C: x There are no wells with a CF < 1.0 13.8 At TD, CBU (minimum 5-7X, more if needed) at max rate and rotation (120+ rpm). Pump tandem sweeps x Obtain BHCT from MWD tools and provide to Halliburton cementers. x Rack back a stand at each bottoms up and reciprocate a full stand in between (while circulating the BU). Keep the pipe moving while pumping. x Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent stream, circulate more if necessary 13.9 BROOH to just below 12-1/4” window x Circulate at full drill rate unless losses are seen. x Rotate at maximum rpm that can be sustained. x Target pulling speed of 5 – 10 min/std (slip to slip time, not including connections), but adjust as hole conditions dictate. Slow pulling speed when backreaming through coal depths seen when drilling. x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling from the lower SVs. x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. x Monitor returns during the backream for increase in cuttings. With this high sail angle, cuttings in laterals will come back in waves and not a consistent stream so circulate more if necessary. Page 24 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 13.10 Slowly pull into the window and stop ~1-2 stands above the window, inside the 13-3/8” casing. CBU minimum 2x to clean the casing. Utilize sweeps as needed. Flow-check well prior to tripping out. 13.11 POOH and LD BHA. 13.12 Change out upper rams to 9-5/8” fixed-bore rams and test with 9-5/8” test joint. Page 25 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 14.0 Run 9-5/8” Intermediate 1 Casing 14.1 Well control preparedness: In the event of an influx of formation fluids while running the intermediate casing, the following well control response procedure will be followed: x P/U & M/U the 5-1/2” safety joint (with 9-5/8” crossover installed on bottom, TIW valve in open position on top, 5-1/2” handling joint above TIW). This joint shall be fully M/U and available prior to running the first joint of 9-5/8” casing. x Slack off and with 5-1/2” DP across the BOP, shut in ram or annular on 5-1/2” DP. Close TIW. x Proceed with well kill operations. 14.2 R/U 9-5/8” casing running equipment. x Ensure 9-5/8” 47# BTC x DELTA 544 crossover is on rig floor and M/U to FOSV. x Use BOL 2000 (or equivalent) thread compound. Dope pin end only w/ paint brush. x R/U CRT equipment. x Ensure all casing has been drifted to 8-1/2” on location prior to running. x Note that 47# drift is 8.525” x Be sure to count the total # of joints on the deck 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. 14.3 P/U shoe joint, visually verify no debris inside joint. 14.4 Continue M/U & thread locking 120’ shoe track assembly consisting of: 9-5/8” Float Shoe 1 joint – 9-5/8”, 2 Centralizers 10’ from each end w/ stop rings 1 joint – 9-5/8”, 1 Centralizer mid joint w/ stop ring 1 joint – 9-5/8”, 1 Centralizer mid joint w/ stop ring 9-5/8” Float Collar w/ Stage Cementer Bypass Baffle ‘Top Hat’ 1 joint – 9-5/8”, 1 Centralizer mid joint w/ stop ring x Ensure proper operation of float equipment while picking up. x Ensure to record S/N’s of all float equipment and stage tool components. 14.5 Continue running 9-5/8” intermediate casing x Fill casing while running using fill up line on rig floor. x Use BOL 2000 or equivalent thread compound. Dope pin end only w/ paint brush. x Centralization: x 1 centralizer every joint to within 120’ of the window x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Obtain up and down weights of the casing before entering open hole. Record rotating torque at 10 and 20 rpm x Likely to lose rotation capability around 11,600’ MD x See data sheets on the next page for MU torque for the 9-5/8” casing connection. Page 26 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 9-5/8” 47/# L-80 DWC/C Make-up Torque Casing OD Minimum Optimum Maximum 9-5/8” 40,000 ft-lbs 45,000 ft-lbs 59,400 ft-lbs Page 27 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 14.6 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 14.7 Slow in and out of slips. 14.8 RIH with 9-5/8” intermediate casing to 13-3/8” shoe at ~4,205’ MD. CBU and establish PU and SO weights prior to exiting shoe. 14.9 Continue to RIH with 9-5/8” intermediate casing using the following circulation strategy (Note: Take special care when staging pumps up and down to avoid packing off and breaking down formation): x 13-3/8” shoe to TD: Every 5th joint, staging up to planned cementing rate. Circulate for 5 minutes. 14.10 P/U hanger and landing joint and M/U to casing string. Casing shoe +/- 10’ from TD. 14.11 Break circulation at 1 bpm to avoid breaking down formation. Slowly stage up to full circulating rate (planned cementing rates). Allow circulating pressures to stabilize before increasing circulating rate to the next stage. Circulate 4 BU or more if needed to condition hole for cementing. Reduce YP to < 18 to help ensure success of cement job. Do not start the YP drop until casing is on bottom and cementers are ready. Page 28 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 15.0 Cement 9-5/8” Intermediate Casing 15.1 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 fluids can be delivered to the cementing unit at acceptable rates. x How to handle cement returns at surface. While not expected, ensure vac trucks are on standby and ready to assist. x Which pumps will be utilized for displacement, and how fluid will be fed to displacement pump. x Ensure adequate amounts 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. 15.2 Document efficiency of all possible displacement pumps prior to cement job. 15.3 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. 15.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and bottom plugs to ensure done in correct order. 15.5 Fill surface cement lines with water and pressure test. 15.6 Drop first bottom plug – HEC rep to witness. Pump spacer. 15.7 Drop second bottom plug – HEC rep to witness. Mix and pump lead cement per below calculations, confirm actual cement volumes with cementer after TD is reached. 15.8 Drop third bottom plug – HEC rep to witness. Mix and pump tail cement per below calculations, confirm actual cement volumes with cementer after TD is reached. x Cement volume based on annular volume + 40% open hole excess. Job will consist of lead & tail, TOC brought to ~11,669’ MD. Estimated Total Cement Volume: Page 29 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure Cement Slurry Design: 15.9 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 and continue with the cement job. 15.10 After pumping cement, drop top plug and displace with the rig pumps and LSND mud out of mud pits. x Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. x Ensure rig pump is used to displace cement. 15.11 Displacement calculation is in the Table in step 15.8. 15.12 Monitor returns closely while displacing cement. Adjust pump rate if losses or packing off are seen at any point during the job. 15.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling Engineer. 15.14 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. 15.15 While a low likelihood, be prepared for cement returns to surface. Open the shaker bypass line to the cuttings tank to dump any cement returns. Have black water available and vac trucks ready to assist. Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact with the cement. 15.16 Freeze protect 13-3/8” x 9-5/8” casing annulus to ~2,200’ MD with dead crude or diesel after cement tests indicate cement has reached 500 psi compressive strength. x Freeze protect with 131 bbls of dead crude/diesel Lead Slurry Tail Slurry System EconoCem HalCem Density 12.0 lb/gal 15.8 lb/gal Yield 2.35 ft3/sk 1.16 ft3/sk Mix Water 13.92 gal/sk 4.98 gal/sk Page 30 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure x Ensure total injection volume injected down the annulus (including any mud used to keep annulus open) doesn’t exceed 110% of the 13-3/8” x 9-5/8” annular volume. 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 jengel@hilcorp.com and joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 31 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 16.0 Drill 8-1/2” x 9-7/8” Intermediate 2 Hole Section 16.1 MU 8-1/2” Cleanout BHA (Milltooth Bit & 1.22° PDM) 16.2 TIH w/ 8-1/2” cleanout BHA to float equipment. Note depth TOC tagged on AM report. 16.3 R/U and test casing to 4500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and plot on FIT graph. Document incremental volume pumped (and subsequent pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001 16.4 Drill out shoe track and 20’ of new formation. 16.5 CBU and condition mud for FIT. 16.6 Conduct FIT to 12.9 ppg EMW. Chart Test. Ensure test is recorded on same chart as casing test. Document incremental volume pumped (and subsequent pressure) and volume returned. Submit casing test and FIT digital data to AOGCC. x 12.9 ppg FIT provides >>25bbls based on 11.5 ppg MW +0.5ppg kick intensity, 9.40 ppg EMW PP @ TD 16.7 POOH & LD Cleanout BHA 16.8 MU 8-1/2” x 9-7/8” directional BHA x RSS and Triple Combo x Ensure BHA components have been inspected previously. x Drift and caliper all components before MU. Visually verify no debris inside components that cannot be drifted. x Ensure MWD is RU and operational. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. x NOV underreamer will be utilized above the MWD to allow for 9-7/8” hole x NOV bit to match underreamer will be run. x Drill string will be 5-1/2” 21.9# S-135 DELTA 544. x Run a solid float in the intermediate 2 hole section. 16.9 TIH w/ 8-1/2” x 9-7/8” BHA to 9-5/8” shoe. 16.10 Intermediate 2 hole section will use the same mud used to TD Intermediate 1 hole section. 16.11 8-1/2” x 9-7/8” hole section mud program summary: x Density: 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. * Casing test and FIT digital data to AOGCC upon completion of FIT - JJL Page 32 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure x Solids Concentration: It is imperative that the solids concentration be kept low while drilling the production hole section. Keep the shaker screen size optimized and fluid running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible. x Rheology: Keep viscosifier additions to an absolute minimum (DUO-VIS / XCD). Data suggests excessive viscosifier concentrations can decrease return permeability. Do not pump high vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 10 (hole diameter) for sufficient hole cleaning x Run the centrifuge as needed while drilling the production hole, this will help with solids removal. x Dump and dilute as necessary to keep drilled solids to an absolute minimum. x MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, & Toolpusher office. System Type:10.3 – 11.5 ppg LSND drilling fluid Properties: Interval Density PV YP API FL HPHT Drill Solids MBT Hardness ~15,176’ – ~20,640’ Shoe – TCM1 10.3-11.0 5 – 20 15 – 30 <6 <10 <6% <20 <100 ~20,640’ – ~21,399’ CM1 – TD 11.0-11.5 5 – 20 15 – 30 <6 <10 <6% <20 <100 System Formulation: Product- intermediate Size Pkg ppb or (% liquids) Soda Ash 50 lb sx 0.17 PowerVIS 25 lb sx 1.5 – 2.0 M-I Pac UL 50 lb sx 3.0 Hydrahib/Kla-Stop 55 gal dm 2.0 – 1.5 KCl 50 lb sx 10.7 SCREENKLEEN 55 gal dm 0.25 M-I Wate 50 lb sx 56 (as needed for wt) Busan 1060 55 gal dm 2.1 16.12 Install MPD RCD 16.13 Begin drilling 8-1/2” hole section, on-bottom staging technique: x Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8K. x Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations Page 33 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure x If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to PU off bottom and restart on bottom staging technique. If stick slip continues, consider adding 0.5% lubes 16.14 Once ~300’ outside of the 9-5/8” shoe, pick up off bottom and activate underreamer per NOV procedure. Verify reamer blades are unlocked 16.15 Drill 8-1/2” x 9-7/8” hole section to ~20,400’ MD (~200’ above CM1) per geologist and Drilling Engineer utilizing the following parameters: x Flow Rate: 500-550 GPM, target min. AV’s in the 9-7/8” openhole: 180 ft/min, 530 GPM x Flow Rate: 500-550 GPM, AV’s in the 9-5/8” casing: 257 ft/min, 530 GPM x RPM: 120+ x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex: concretion deflection x Monitor Torque and Drag with pumps on every 5 stands x Monitor ECD, pump pressure & hookload trends for hole cleaning indication x Monitor downhole WOB/TOB and compare to surface parameters to ensure the bit or the underreamer isn’t being overworked x Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across any sands for an extended period of time. x Limit maximum instantaneous ROP to < 200 FPH. This is to minimize cutter damage if encountering concretions or the Tuffs section in the Colville. x Do not initiate backreaming while the underreamer is unlocked. Backreaming can damage the reamer cutting blocks or possibly back off the pilot BHA. x Prior to picking up off bottom for a connection, ensure WOB has drilled off (hookload and torque returning to free rotating values) and RPM gradually slowed to zero. This is to mitigate the risk of backing off the pilot BHA below the underreamer. x Target ROP is as fast as we can clean the hole without having to backream connections x MPD will be utilized to hold ECD and monitor any pressure build up on connections. x 8-1/2” x 9-7/8” Hole Section A/C: x There are no wells with a CF < 1.0 16.16 Toward the end of the above interval, begin to weight up from 10.5 ppg to 11.0 ppg. Ensure mud is a consistent 11.0 ppg ~200’ before entering the CM1 (projected top at 20,640’ MD). x Use a spike fluid to weight up and add black product for HRZ/Kingak stability. Ensure the fluid is heated to facilitate better mixing of the black product into the mud system and to avoid shocking the formation and inducing losses/breathing 16.17 Drill 8-1/2” hole section from ~20,400’ to section TD per Geologist and Drilling Engineer. x Flow Rate: 500-550 GPM, target min. AV’s 180 ft/min, 530 GPM in 9-7/8” openhole x Flow Rate: 500-550 GPM, target min. AV’s 257 ft/min, 530 GPM in 9-5/8” casing x RPM: 120+ Page 34 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex: concretion deflection x Monitor Torque and Drag with pumps on every 5 stands x Monitor ECD, pump pressure & hookload trends for hole cleaning indication x Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across the sand for any extended period of time. x Limit maximum instantaneous ROP to < 200 FPH while drilling through the Colville. This is to minimize cutter damage if encountering concretions or the Tuffs section in the Colville. x Once in the HRZ, limit maximum instantaneous ROP to < 100 FPH to TD. This is to minimize ECD spikes to cause instability in the shales. x Do not initiate backreaming while the underreamer is unlocked. Backreaming can damage the reamer cutting blocks or possibly back off the pilot BHA. x Prior to picking up off bottom for a connection, ensure WOB has drilled off (hookload and torque returning to free rotating values) and RPM gradutally slowed to zero. This is to mitigate the risk of backing off the pilot BHA. x Target ROP is as fast as we can clean the hole without having to backream connections x MPD will be utilized to hold ECD and monitor any pressure build up on connections. x 8-1/2” x 9-7/8” Hole Section A/C: x There are no wells with a CF < 1.0 16.18 TD will be in the SGR formation and confirmed via samples. Do not lock the underreamer blades until SGR samples are verified. Follow NOV/Halliburton parameters for rotating while circulating up samples with the blades unlocked. 16.19 Once samples are verified and the underreamer blades are locked closed, CBU at drilling rate and max rotation. Pump sweeps if needed x Monitor BU for increase in cuttings 16.20 Perform wiper trip to the 9-5/8” casing shoe x Pump out of the hole until above HRZ to maintain ECDs over shale stability minimums. x Pulling speed 5 – 10 min/stand (slip to slip time, not including connections), adjust as dictated by hole conditions x If pulling tight, trip back to TD and begin backreaming operations. x If backreaming operations are commenced, continue backreaming to the shoe 16.21 CBU minimum 5 times at 9-5/8” shoe at maximum flow rate and clean casing with high vis sweeps. 16.22 If trip to 9-5/8” shoe is clean, continue to POOH and LD BHA for upcoming liner run. 16.23 If trip to the shoe is troublesome, run back to TD and CBU 2x or until well cleans up, whichever comes later. Page 35 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 16.24 When at the 9-5/8” shoe, monitor well for flow. Increase mud weight if necessary. x Wellbore breathing has been seen on historical Niakuk wells. Perform extended flow checks to determine if well is breathing, treat all flow as an influx until proven otherwise x If necessary, increase MW at shoe for any higher than expected pressure seen 16.25 Pull RCD Bearing and install trip nipple. 16.26 POOH and LD BHA. Rabbit DP that will be used to run liner. Only LWD open hole logs are planned for the hole section (Triple Combo). There will not be any additional logging runs conducted. Page 36 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 17.0 Run 7” Intermediate 2 Liner 17.1 Well control preparedness: In the event of an influx of formation fluids while running the injection liner, the following well control response procedure will be followed: x P/U & M/U the 5-1/2” safety joint (with 7” crossover installed on bottom, TIW valve in open position on top, 5-1/2” handling joint above TIW). This joint shall be fully M/U and available prior to running the first joint of 7” liner. x Slack off and with 5-1/2” DP across the BOP, shut in ram or annular on 5-1/2” DP. Close TIW. x Proceed with well kill operations. 17.2 Change upper VBRs to 7” casing rams and test to 250 psi low, 4,500 psi high for 5/5 minutes using 7” test joint. 17.3 R/U 7” liner running equipment. x Ensure 7” 26# VT x DELTA544 crossover is on rig floor and M/U to FOSV. x Ensure all casing has been drifted on the deck prior to running. x Be sure to count the total # of joints on the deck 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. 17.4 Run 7” injection liner x Use Vam approved thread compound. Dope pin end only w/ paint brush. Wipe off excess. x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Use lift nubbins and stabbing guides for the liner run. x If liner length exceeds surface casing length, ensure centralizers are placed 1/jt for each joint outside of the surface shoe. x Obtain up and down weights of the liner before entering open hole. x See data sheet on the next page for MU torque for the 7” liner connections. x Centralization: x 1 centralizer every joint on all 7” liner 17.5 Run 7” liner as follows: 7” Float Shoe 1 solid joint – 7”, 2 Centralizers 10’ from each end w/ stop rings 7” Float Collar 1 solid joint – 7”, 1 Centralizer mid joint w/ stop rings 7” Landing collar 1 solid joint – 7”, 1 Centralizer mid joint w/ stop rings 7” 26/# L-80 VT – Make up Torque Casing OD Minimum Optimum Maximum 7” 7,470 ft-lbs 8,300 ft-lbs 9,130 ft-lbs Page 37 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure Page 38 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 17.6 Ensure hanger/pkr will not be set in a 9-5/8” connection. x AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as per 20 AAC 25.030(d)(6). Plan is to place liner hanger with ~150’ overlap. Do not place liner hanger/packer across 9-5/8” connection. 17.7 Before picking up Baker SLZXP liner hanger / packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 17.8 M/U Baker SLZXP liner top packer to 7” liner. Circulate 2 liner volumes to clear string and allow for PAL mix to set 17.9 Note: PU, SO, ROT and torque of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 17.10 RIH with liner no faster than 30 ft/min – Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. x Ensure 5-1/2” DP has been drifted x Fill drill pipe on the fly. Monitor FL and if filling is required due to losses/surging. 17.11 Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to bottom. 17.12 Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, & 20 RPM. If torque approaches make-up torque of liner, discontinue rotation. 17.13 Continue to RIH with 7” intermediate 2 liner using the following circulation strategy (Note: Take special care when staging pumps up and down to avoid packing off and breaking down formation): x 9-5/8” shoe to top HRZ: Every 5th joint, staging up to planned cementing rate. Circulate for 5 minutes. x Circulate down consecutive joints to achieve a full bottoms-up by THRZ x Top HRZ to TD: Fill pipe only. Break circulation only if drag appears to be increasing or if there’s indications of getting stuck. Once circulation starts, circulate every stand down to TD. 17.14 Tag bottom and PU to position float shoe ~2’ off bottom. Last motion of the liner should be “up” to ensure it is set in tension. 17.15 Break circulation. Begin circulating at ~0.5 – 1 BPM and monitor pump pressures. Slowly stage up to full circulating rate (planned cementing rates). Allow circulating pressures to stabilize before increasing circulating rate to the next stage. Circulate 4 BU or more if needed to condition hole for cementing. Reduce YP to < 18 to help ensure success of cement job. Do not start the YP drop until liner is on bottom and cementers are ready. Do not exceed 1,600 psi while circulating for risk of prematurely setting liner hanger. Note all losses. Confirm all pressures with Baker. Page 39 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 18.0 Cement 7” Intermediate 2 Liner 18.1 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 How to handle cement returns at surface. Ensure vac trucks are on standby and ready to assist. x Which pumps will be utilized for displacement, and how fluid will be fed to displacement pump. x Ensure adequate amounts 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. 18.2 Document efficiency of all possible displacement pumps prior to cement job. 18.3 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. 18.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and bottom drillpipe darts into rotating cement head to ensure done in correct order. 18.5 Fill surface cement lines with water and pressure test. 18.6 Pump remaining spacer. 18.7 Drop lower drillpipe dart and pump cement per schedule below. Cement volume based on annular volume + 40% open hole excess. Job will consist of lead and tail slurries, TOC brought to top of liner. Estimated Total Cement Volume: Page 40 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure Cement Slurry Design: 18.8 Drop upper 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. 18.9 Displace cement at max rate of 7 bbl/min. Reduce pump rate to 2-3 bpm prior to latching each DP dart into liner wiper plug and park the string with liner on depth. Note plug departure from liner hanger running tool and resume pumping at full displacement rate. Displacement volume can be re-zeroed when the upper drillpipe dart latches into top liner wiper plug. 18.10 If elevated displacement pressures are encountered, position liner at setting depth and cease reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman immediately of any changes. 18.11 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. 18.12 Slack off 20K lbs on the SLZXP liner hanger/packer to ensure the HRDE setting tool is in compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4,500 psi to release the HRDE running tool Slack off total liner weight plus 30k to confirm hanger is set. 18.13 Bleed DP pressure to 0 psi and check floats. Pick up to expose rotating dog sub and set down 50K without pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating at 10-20 RPM and set down 50K again. 18.14 Pickup to verify that the HRD setting tool has released. If running tool cannot be hydraulically released, apply LH torque to mechanically release the setting tool. 18.15 Pressure up drill pipe to 500 psi and pick up to remove the RS packoff bushing from the RS nipple. Bump up pressure as required 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) Lead Slurry Tail Slurry System EconoCem HalCem Density 12.0 lb/gal 15.8 lb/gal Yield 2.35 ft3/sk 1.16 ft3/sk Mix Water 13.92 gal/sk 4.98 gal/sk Page 41 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 18.16 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. 18.17 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. While cement returns will be challenging to observe, watch for them and record the estimated volume. Rotate & circulate to clear cmt from DP. 18.18 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. 18.19 Change upper rams from 7” fixed to 3-1/2” x 5-1/2” VBRs and test with 4” and 5-1/2” test joints to 250 psi low / 4,500 psi high for 5/5 minutes. 18.20 Pressure test casing and liner to 250 psi low / 4,000 psi high for 30 minutes. Do not test until cement has reached minimum 500 psi compressive strength. 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 frank.roach@hilcorp.com and joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 42 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 19.0 Drill 6-1/8” Production Hole Section 19.1 MU 6-1/8” directional BHA x RSS and Triple Combo x Ensure BHA components have been inspected previously. x Drift and caliper all components before MU. Visually verify no debris inside components that cannot be drifted. x Ensure MWD is RU and operational. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. x Drill string will be a tapered string 5-1/2” 21.9# S-135 DELTA 544 and 4” 14.0# S-135 XT39. x Run a solid float in the production hole section. 19.2 TIH w/ 6-1/8” BHA to top of 7” liner. Slowly enter liner top and continue t/TIH to landing collar. Note depth landing collar tagged on AM report. 19.3 RU and test casing/liner envelope to 4,000 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and plot on FIT graph. Document incremental volume pumped (and subsequent pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001. 19.4 Drill out shoe track to 10’ above float shoe. Displace well to 9.7 ppg solids-free drilling fluid. 19.5 Drill out remaining shoe track and 20’ of new formation. 19.6 CBU and condition mud for FIT. x Conduct FIT to 11.5 ppg EMW. Chart Test. Ensure test is recorded on same chart as casing test. Document incremental volume pumped (and subsequent pressure) and volume returned. Submit casing test and FIT digital data to AOGCC. x 11.5 ppg FIT provides >>25bbls based on 10.4 ppg MW +0.5ppg kick intensity, 9.40 ppg EMW PP @TD 19.7 6-1/8” hole section mud program summary: x Density: Primary weighting material to be used for the hole section will be sodium chloride. Additional NaCl will be on location to weight up the active system (1) ppg above highest anticipated MW. x Solids Concentration: It is imperative that the solids concentration be kept low while drilling the production hole section. Keep the shaker screen size optimized and fluid running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible. * Casing test and FIT digital data to AOGCC upon completion of FIT - JJL Page 43 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure x Rheology: Keep viscosifier additions to a minimum (FLO-VIS). Utilize high vis sweeps and tandem sweeps as necessary for hole cleaning. Ensure 6 rpm is > 6 (hole diameter) for sufficient hole cleaning x Run the centrifuge as needed while drilling the production hole, this will help with solids removal. x Dump and dilute as necessary to keep drilled solids to an absolute minimum. x MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, & Toolpusher office. System Type:9.7 – 10.4 ppg PowerPro drilling fluid Properties: Interval Density PV YP API FL HPHT Drill Solids MBT Hardness Production 9.7-10.4 5 – 20 15 – 25 <10 NA <8 <10.0 <200 Product- production Size Pkg ppb or (% liquids) Busan 1060 55 gal dm 0.095 FLOTROL 55 lb sx 6 CONQOR 404 WH (8.5 gal/100 bbls)55 gal dm 0.2 FLO-VIS PLUS 25 lb sx 0.7 KCl 50 lb sx 10.7 SMB 50 lb sx 0.45 LOTORQ 55 gal dm 1.0 SAFE-CARB 10 (verify)50 lb sx 10 SAFE-CARB 20 (verify)50 lb sx 10 Soda Ash 50 lb sx 0.5 19.8 Install MPD RCD 19.9 Begin drilling 6-1/8” hole section, on-bottom staging technique: x Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8K. x Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations x If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to PU off bottom and restart on bottom staging technique. If stick slip continues, consider adding 0.5% lubes 19.10 Drill 6-1/8” hole section to section TD per Geologist and Drilling Engineer. Page 44 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure x Flow Rate: 250-350 GPM, target min. AV’s in the open hole section: 200 ft/min, 175 GPM x Flow Rate: 250-350 GPM, AV’s in the 7” section w/4” DP: 200 ft/min, 191 GPM x Flow Rate: 250-350 GPM, AV’s in the 9-5/8” section w/5-1/2” DP: 190 ft/min, 350 GPM x RPM: 120+ x Pay close attention to circulating pressures. At this depth and with a 5-1/2” x 4” tapered drillstring, circulating pressures may approach maximum of Parker 273’s circulating system. Adjust circulating rates and ROP accordingly. x Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly wet to maximize solids removal efficiency. Check for holes in screens on every connection. x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex: concretion deflection x Monitor Torque and Drag with pumps on every 5 stands x Monitor ECD, pump pressure & hookload trends for hole cleaning indication x Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across the sand for any extended period of time. x Reservoir plan is to drill down into the Ivishak sands before turning up and landing back in the Sag River sands for the horizontal. x There are no projected fault crossings in the production interval. x After making a connection, it may be necessary to start rotation prior to bringing on the pumps. This is to help break the static gels in the mud and minimize the ECD. x Limit maximum instantaneous ROP to < 100 FPH. The sands will drill faster than this, but this is a very short interval to TD. x Be aware of Zone 3 conglomerates and Zone 2 chert. While these intervals are short due to the hole angle, these formations can damage the bit and necessitate a bit trip. x MPD will be utilized to hold ECD and monitor pressure build up on connections. x 6-1/8” Hole Section A/C: x There are no wells with a CF < 1.0 19.11 TD Will be called by the geologist when all tools have reached TD, CBU at drilling rate and max rotation. Pump sweeps if needed x Monitor BU for increase in cuttings 19.12 BROOH to the 7” shoe. x Circulate at full drilling rate x Pulling speed 5 – 10 min/stand (slip to slip time, not including connections), adjust as dictated by hole conditions x If pulling tight, trip back to TD and begin backreaming operations. 19.13 CBU minimum 5 times at the 7” shoe at maximum rate and clean casing with high vis sweeps. 19.14 When at the 9-5/8” shoe, monitor well for flow. Increase mud weight if necessary. Page 45 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure x Perform extended flow checks to determine if well is overbalanced. Treat all flow as an influx until proven otherwise x If necessary, increase MW at shoe for any higher than expected pressure observed 19.15 Pull RCD Bearing and install trip nipple. 19.16 POOH and LD BHA. Rabbit DP that will be used to run liner. Only LWD open hole logs are planned for the hole section (Triple Combo). There will not be any additional logging runs conducted. Page 46 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 20.0 Run 4-1/2” Production Liner 20.1 Well control preparedness: In the event of an influx of formation fluids while running the injection liner, the following well control response procedure will be followed: When M/U & running 4-1/2” liner: x P/U & M/U the 5-1/2” safety joint (with 4-1/2” crossover installed on bottom, TIW valve in open position on top, 5-1/2” handling joint above TIW). This joint shall be fully M/U and available prior to running the first joint of 4-1/2” liner. x Slack off and with 5-1/2” DP across the BOP, shut in ram or annular on 5-1/2” DP. Close TIW. x Proceed with well kill operations. When 4-1/2” liner is fully picked up and RIH on 4” DP: x P/U & M/U the 5-1/2” safety joint (with 4” crossover installed on bottom, TIW valve in open position on top, 5-1/2” handling joint above TIW). This joint shall be fully M/U and available prior to running the first stand of 4” drillpipe. x Slack off and with 5-1/2” DP across the BOP, shut in ram or annular on 5-1/2” DP. Close TIW. x Proceed with well kill operations. 20.2 Upper VBRs to cover the 4-1/2” liner, 5-1/2” x 4” drillpipe used in this operation. 20.3 R/U 4-1/2” liner running equipment. x Ensure 4-1/2” 12.6# VT x DELTA544 crossover is on rig floor and M/U to FOSV. x Ensure 4 XT39 x DELTA 544 crossover is on rig floor and M/U to FOSV. x Ensure all casing has been drifted on the deck prior to running. x Be sure to count the total # of joints on the deck 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. 20.4 Run 4-1/2” production liner x Use Vam approved thread compound. Dope pin end only w/ paint brush. Wipe off excess. x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Use lift nubbins and stabbing guides for the liner run. x Obtain up and down weights of the liner before entering open hole. x See data sheet on the next page for MU torque for the 4-1/2” liner connections. x Run 2 centralizers per joint. One centralizer free floating with stop rings at 4’ and 10’ above pin. Second centralizer locked down 10’ below box. Centralize no higher than 50’ below 7” shoe. 4-1/2” 12.6/# 13Cr-80 VT – Make up Torque Casing OD Minimum Optimum Maximum 4-1/2” 4,000 ft-lbs 4,440 ft-lbs 4,880 ft-lbs Page 47 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure Page 48 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure Page 49 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 20.5 Ensure hanger/pkr will not be set in a 7” connection. x AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as per 20 AAC 25.030(d)(6). Plan is to place liner hanger with ~150’ overlap. Do not place liner hanger/packer across 7” connection. 20.6 Before picking up Baker Flexlock III/ZXP liner hanger / packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 20.7 M/U Baker Flexlock III/ZXP liner hanger / packer assy to 4-1/2” liner. Circulate 2 liner volumes to clear string and allow for PAL mix to set 20.8 Note: PU, SO, ROT and torque of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 20.9 RIH with liner no faster than 30 ft/min – Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. x Ensure all 4” and 5-1/2” DP for the liner run has been drifted x Run enough 4” DP such that the 5-1/2” x 4” DP XO is ~100’ above the 7” liner top with liner on bottom. x Fill drill pipe on the fly. Monitor FL and if filling is required due to losses/surging. 20.10 Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to bottom. 20.11 Before switching elevators and handling equipment from 4” DP to 5-1/2” DP, flow check well for 10 minutes. 20.12 Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, & 20 RPM. If torque approaches make-up torque of liner, discontinue rotation. 20.13 Tag bottom and PU to position float shoe ~2’ off bottom. 20.14 Break circulation. Begin circulating at ~0.5 – 1 BPM and monitor pump pressures. Slowly stage up to full circulating rate (planned cementing rates). Allow circulating pressures to stabilize before increasing circulating rate to the next stage. Circulate 4 BU or more if needed to condition hole for cementing. Reduce YP to < 18 to help ensure success of cement job. Do not start the YP drop until liner is on bottom and cementers are ready. Do not exceed 1,600 psi while circulating for risk of prematurely setting liner hanger. Note all losses. Confirm all pressures with Baker. Page 50 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 21.0 Cement 4-1/2” Production Liner 21.1 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 How to handle cement returns at surface. Ensure vac trucks are on standby and ready to assist. x Which pumps will be utilized for displacement, and how fluid will be fed to displacement pump. x Ensure adequate amounts 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. 21.2 Document efficiency of all possible displacement pumps prior to cement job. 21.3 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. 21.4 R/U cement line (if not already done so). Company Rep to witness loading of the drillpipe dart into rotating cement head. 21.5 Prior to starting cement job, drop ball and set Flexlock liner hanger per Baker representative. 21.6 Slack off 20K lbs on the Flexlock/ZXP liner hanger/packer assembly to ensure the HRDE setting tool is in compression for release from the Flexlock/ZXP liner hanger/packer assembly. Continue pressuring up 4,500 psi to release ball from setting sleeve and the HRDE running tool. Slack off total liner weight plus 30k to confirm hanger is set. 21.7 Fill surface cement lines with water and pressure test. 21.8 Pump remaining spacer. 21.9 Cement volume based on annular volume + 40% open hole excess. Job will consist of tail slurry, TOC brought to top of liner. Page 51 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure Estimated Total Cement Volume: Cement Slurry Design: 21.10 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. 21.11 Displace cement at max rate of 7 bbl/min. Reduce pump rate to 2-3 bpm and park liner on depth 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. 21.12 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. 21.13 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. 21.14 Bleed DP pressure to 0 psi and check floats. Pick up to expose rotating dog sub and set down 50K Pick back up and begin rotating at 10-20 RPM and set down 50K again. 21.15 Pickup to verify that the HRD setting tool has released. If running tool cannot be hydraulically released, apply LH torque to mechanically release the setting tool. Tail Slurry System HalCem Density 15.8 lb/gal Yield 1.16 ft3/sk Mix Water 4.98 gal/sk Page 52 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 21.16 Pressure up drill pipe to 500 psi and pick up to remove the RS packoff bushing from the RS nipple. Bump up pressure as required 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) 21.17 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. 21.18 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. While cement returns will be challenging to observe, watch for them and record the estimated volume. Rotate & circulate to clear cmt from DP. 21.19 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. 21.20 Pressure test casing and liner to 250 psi low / 4,000 psi high for 30 minutes. Do not test until cement has reached minimum 1,000 psi compressive strength. Note: Once running tool is LD, swap to the completion AFE. 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 frank.roach@hilcorp.com and joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 53 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 22.0 Run Upper Completion/ Post Rig Work 22.1 RU to run 4-1/2” 12.6#, 13Cr-80 Vam Top tubing. x Ensure wear bushing is pulled. x Ensure 4-1/2”, 12.6#, Vam Top x 5-1/2” DELTA 544 crossover is on rig floor and M/U to FOSV. x Ensure all tubing has been drifted in the pipe shed prior to running. x Be sure to count the total # of joints in the pipe shed before running. x Keep hole covered while RU casing tools. x Record OD’s, ID’s, lengths, SN’s of all components with vendor & model info. x Monitor displacement from wellbore while RIH. 22.2 PU, MU and RH with the following 4-1/2” completion jewelry (tally to be provided by Operations Engineer): x Torque Turn All Connections x Tubing Jewelry to include (top to bottom): x 1x SSSV nipple profile x 6x GLMs (size and final number to be determined by OE) x 1x ‘X’ Nipple x 1x Production Packer x 1x ‘X’ Nipple x 1x ‘XN’ Nipple with RHC profile installed x 1x WLEG x Tubing is 4-1/2”, 12.6#, 13Cr-80, Vam Top 4-1/2” 12.6/# 13Cr-80 Vam Top – Make up Torque Casing OD Minimum Optimum Maximum 4-1/2” 4,000 ft-lbs 4,440 ft-lbs 4,880 ft-lbs Page 54 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure Page 55 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 22.3 Space out the completion to land such that the 4-1/2” WLEG is inserted half-way into the PBR on the 4-1/2” production liner. Record PU and SO weights prior to picking up tubing hanger. 22.4 MU the tubing hanger and land same. Run in the lock-down screws and torque to spec. 22.5 Reverse circulate heated kill-weight brine. Circulate surface-to-surface at a maximum of 4 BPM with brine and inhibited brine as follows: x Clean brine within the tubing from WLEG to surface x Inhibited brine on the annular side from the shear valve depth to the WLEG x Clean brine on the annular side from surface down to the shear valve. 22.6 Install and pressure test TWC from above. 22.7 ND BOPE. NU the tubing head adapter and tree. 22.8 PT the tubing hanger void to 500/5,000 psi. PT the tree to 250/5,000 psi. 22.9 RU lubricator and pull TWC. 22.10 Freeze protect the wellbore. x Rig up to pump heated diesel down the IA, taking returns up the tubing up the tubing. Reverse 188 bbls heated diesel into the IA. Do not exceed 3bpm while circulating. x Shut in the IA. x Line up to U-tube from the IA to the tubing. x U-tube the diesel and freeze protect the tubing and IA to ~2,200’ MD. 22.11 After u-tube is complete, RU lubricator and install BPV. 22.12 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over with valve alignment as per operations personnel. Page 56 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 22.13 RDMO Parker 273 i. POST RIG WELL WORK (sundry to follow) 1. Slickline/Fullbore a. Pull BPV. b. Set production packer c. Test Tbg and IA to 250 psi low, 4,000 psi high for 5/30 minutes i. Chart test d. Perforate production interval e. Change out GLV per GL ENGR if not done already 2. Well Tie-In Page 57 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 23.0 Parker 273 Rig BOP Schematic Page 58 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 24.0 Wellhead Schematic Page 59 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 25.0 Days Vs Depth Page 60 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 26.0 Formation Tops & Information Page 61 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure Page 62 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure Page 63 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure Page 64 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 27.0 Anticipated Drilling Hazards 12-1/4” Hole Section: Hole Cleaning: Maintain rheology of mud system. Utilize sweeps to evaluate and maintain good hole cleaning (weighted, high-vis, and low-vis/high-vis tandem sweeps all have seen success, depending on hole angle). Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge as needed to control drilled solids. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 800 gpm Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: Crossing faults, known or unknown, can result in drilling into unstable formations that may impact future drilling and liner runs. Talk with Geologist to ensure all known faults are identified and prepared for accordingly. H2S: DS-NK is an H2S location. Below are the most recent H2S values of monitored wells in the Ivishak Pool. Well Name H2S Level Date of Reading #1 Closest SHL Well H2S Level NK-25 20 ppm 4/20/2012 #2 Closest SHL Well H2S Level NK-26A 8 ppm 8/17/2024 #1 Closest BHL Well H2S Level NK-42 76 ppm 2/26/2023 #2 Closest BHL Well H2S Level NK-22A 180 ppm 1/22/2023 Max. Recorded H2S on nearest Pad/Facility NK-21 1,580 ppm 6/25/2022 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. Page 65 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Abnormal Pressures and Temperatures: P Reservoir pressures are expected to be normal. Utilize MPD to mitigate any abnormal pressure seen. Ugnu/West Sak Hardstreaks: Hard formations (which are not necessarily predictable) can be encountered resulting in damage to PDC cutters. Damage occurs due to high impact loading of the bit cutting structure when hard streaks are hit at high ROP. Follow the appropriate mitigation strategy of reducing rotary speed while maintaining WOB. Colville Breathing: This is associated with higher mud weights and higher ECD’s in the Colville mudstones. Monitor ECDs and mud properties. Fingerprint connections to confirm breathing and not a well control event. Anti-Collision Take directional surveys every stand, take additional surveys if necessary. Continuously monitor drilling parameters for signs of magnetic interference with another well. Reference A/C report in directional plan. 12-1/4” Hole Section Specific AC: x There are no wells with a CF < 1.0 Note: abnormal pressures expected in shales/mudstones from CM3 through Kingak, however no permeable formations anticipated to be abnormally pressured. Kuparuk anticipated to be at 0.494 psi/ft gradient. See emails attached to PTD. -A.Dewhurst 07MAR25 Page 66 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 8-1/2” x 9-7/8” Hole Section: Hole Cleaning: Maintain rheology of mud system. Utilize sweeps to evaluate and maintain good hole cleaning (weighted, high-vis, and low-vis/high-vis tandem sweeps all have seen success, depending on hole angle). Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge as needed to control drilled solids. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Reduce ROP (as opposed to flow rate) to control ECD. Maintain circulation rate of > 500 gpm Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: No faults are forecasted to be crossed in this interval. Crossing faults, known or unknown, can result in drilling into unstable formations that may impact future drilling and liner runs. Talk with Geologist to ensure all known faults are identified and prepared for accordingly. H2S: DS-NK is an H2S location. Below are the most recent H2S values of monitored wells in the Ivishak Pool. Well Name H2S Level Date of Reading #1 Closest SHL Well H2S Level NK-25 20 ppm 4/20/2012 #2 Closest SHL Well H2S Level NK-26A 8 ppm 8/17/2024 #1 Closest BHL Well H2S Level NK-42 76 ppm 2/26/2023 #2 Closest BHL Well H2S Level NK-22A 180 ppm 1/22/2023 Max. Recorded H2S on nearest Pad/Facility NK-21 1,580 ppm 6/25/2022 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 67 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure Abnormal Pressures and Temperatures: Reservoir pressures are expected to be normal. Utilize MPD to mitigate any abnormal pressure seen. Colville Breathing: This is associated with higher mud weights and higher ECD’s in the Colville mudstones. Monitor ECDs and mud properties. Fingerprint connections to confirm breathing and not a well control event. Tuffs or “Shale Wall” (CM1): The top of the CM1 is lithologically similar to the shallower CM intervals, but contains some interbedded volcanic tuff beds. Tuffs are hard and abrasive, especially at the top of the interval. Reduce WOB and ROP to maximize bit and reamer life when drilling through the CM1. Formation Breakout (HRZ/Kingak instability): This is related to the fissile (finely laminated) nature of the formation in conjunction with higher pore pressure, which requires higher mud weight to maintain wellbore stability. If splintering cuttings are observed at surface, additional circulations and mud weight may be required. Anti-Collision Take directional surveys every stand, take additional surveys if necessary. Continuously monitor drilling parameters for signs of magnetic interference with another well. Reference A/C report in directional plan. 8.5” x 9-7/8” Hole Section Specific AC: x There are no wells with a CF < 1.0. Page 68 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 6-1/8” Hole Section: Hole Cleaning: Maintain rheology of mud system. Utilize sweeps to evaluate and maintain good hole cleaning (weighted, high-vis, and low-vis/high-vis tandem sweeps all have seen success, depending on hole angle). Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge as needed to control drilled solids. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Reduce ROP (as opposed to flow rate) to control ECD. Maintain circulation rate of > 250 gpm Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: There are 3 possible fault crossings in this interval (2 high probability and 1 low probability). All 3 faults have throws < 100’ and have a low lost circulation risk. Crossing faults, known or unknown, can result in drilling into unstable formations that may impact future drilling and liner runs. Talk with Geologist to ensure all known faults are identified and prepared for accordingly. H2S: DS-NK is an H2S location. Below are the most recent H2S values of monitored wells in the Ivishak Pool. Well Name H2S Level Date of Reading #1 Closest SHL Well H2S Level NK-25 20 ppm 4/20/2012 #2 Closest SHL Well H2S Level NK-26A 8 ppm 8/17/2024 #1 Closest BHL Well H2S Level NK-42 76 ppm 2/26/2023 #2 Closest BHL Well H2S Level NK-22A 180 ppm 1/22/2023 Max. Recorded H2S on nearest Pad/Facility NK-21 1,580 ppm 6/25/2022 4. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 5. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. Page 69 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 6. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Abnormal Pressures and Temperatures: Reservoir pressures are expected to be normal. Utilize MPD to mitigate any abnormal pressure seen. Shublik Breathing: This is associated with higher mud weights and higher ECD’s in the Shublik carbonates. This is different in comparison to the breathing potential in the Colville Mudstones in that the formation will take fluid, but release gas. If treated like a traditional influx, the subsequent weight-up will start the process over with more fluid being lost and then more gas being released. Circulating out the gas via driller’s method and monitor pressures to determine if this is a breathing event or if it is an influx. Zone 4 and Zone 3 Conglomerates; Zone 2 Hard Streaks: Zone 3 conglomerates and Zone 2 chert/hard streaks can hinder ROP. Bit selection is key to avoid a bit trip. Maintain WOB to work through and maintain directional control through the zones. Anti-Collision Take directional surveys every stand, take additional surveys if necessary. Continuously monitor drilling parameters for signs of magnetic interference with another well. Reference A/C report in directional plan. 6-1/8” Hole Section Specific AC: x There are no wells with a CF < 1.0. Page 70 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 28.0 Parker 273 Rig Layout Page 71 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 29.0 FIT 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. Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental volume pumped and returned during test. Page 72 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 30.0 Parker 273 Rig Choke Manifold Schematic Page 73 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 31.0 Casing Design Page 74 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 32.0 12-1/4” Hole Section MASP Page 75 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 33.0 8-1/2” x 9-7/8” Hole Section MASP Page 76 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 34.0 6-1/8” Hole Section MASP Page 77 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 35.0 Spider Plot (NAD 27) (Governmental Sections) Page 78 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 36.0 Surface Plat (As Built) (NAD 27) 1 Gluyas, Gavin R (OGC) From:Lau, Jack J (OGC) Sent:Wednesday, February 12, 2025 4:32 PM To:AOGCC Records (CED sponsored) Subject:FW: [EXTERNAL] RE: Parker 273 Drillpipe Change NK-41B (PTD: 224-153) From: Lau, Jack J (OGC) Sent: Wednesday, February 12, 2025 4:31 PM To: 'Frank Roach' <Frank.Roach@hilcorp.com>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: RE: [EXTERNAL] RE: Parker 273 Drillpipe Change NK-41B (PTD: 224-153) Thanks Frank. You are approved to swap to 5.5” drill pipe contingent on the following: 1) Updated kick tolerance calculations for all impacted hole sections result in > 25 bbl kick tolerance 2) Pipe rams are suitable for closing on 5.5” drill pipe when utilized (program has 2-7/9” x 5” VBRs or 5” solid body) 3) The correct sized safety joint is available on the floor (program references 5” safety joint) 4) Ensure that all calculations impacted by the swap, such as cement displacement, are updated. Let me know if there are any concerns with the above. Jack From: Frank Roach <Frank.Roach@hilcorp.com> Sent: Wednesday, February 12, 2025 3:51 PM To: Lau, Jack J (OGC) <jack.lau@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: RE: [EXTERNAL] RE: Parker 273 Drillpipe Change NK-41B (PTD: 224-153) Jack, We’re still above 25bbls. The original modeling had a ~32bbl kick tolerance with a 12.3ppg EMW FIT. Upsizing from 5” to 5-1/2” drillpipe dropped that kick tolerance volume to ~30.0bbls with a 12.3ppg EMW FIT. On 2/2, we achieved a 12.5ppg EMW FIT after milling the window. Regards, Frank V Roach Drilling Engineer Hilcorp Alaska, LLC 907.854.2321 mobile 2 907.777.8413 office From: Lau, Jack J (OGC) <jack.lau@alaska.gov> Sent: Wednesday, February 12, 2025 3:41 PM To: Frank Roach <Frank.Roach@hilcorp.com>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: [EXTERNAL] RE: Parker 273 Drillpipe Change NK-41B (PTD: 224-153) Thanks for the update Frank. I’ll give you a call this afternoon. How does swapping DP impact your kick tolerance calcs? I will double check this afternoon. Jack From: Frank Roach <Frank.Roach@hilcorp.com> Sent: Wednesday, February 12, 2025 3:30 PM To: Lau, Jack J (OGC) <jack.lau@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: Parker 273 Drillpipe Change NK-41B (PTD: 224-153) Jack/Mel, Jack, I left a voicemail a little while ago and wanted to follow up with an email. I wanted to give you both a heads-up now that we’re making some progress on the rig. We will be switching our drillstring over to a new-to-us 5-1/2” Delta 544 drillpipe and HWDP. This will help out on these longer wells we are drilling in Prudhoe and Milne Point. This was planned to be done on the rig move to Milne, but with the recent events on NK-41B, we’ll need to make the switch earlier. The spec sheets for the drillpipe and HWDP are attached. On Sunday, February 9, we stuck our drillstring at 15,336’ MD, while drilling ahead (bit and BHA in the UG1. ~1,400’MD before TWS). Managed to work the BHA up to ~14,963’, but unable to work any further. An attempt to cut drillpipe yesterday wasn’t conclusive so we continued to work the string in an attempt to gain circulation and free the pipe. We established circulation early this morning and ramped up to 5.5bpm while working the string until we popped free around 09:00 this morning. Indications are we likely parted at the cut attempt as we did not see detection on our MWD tools. Currently, we are pulling out of the hole with the freed drillstring and should be at surface sometime tomorrow morning. Once at surface, we will be swapping out the drillpipe and performing a BOPE test with the new string. Following steps will be a cleanout run, followed by a fishing run to attempt to recover the BHA. Let me know if you need anything additional. 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. 3 Regards, Frank V Roach Drilling Engineer Hilcorp Alaska, LLC 907.854.2321 mobile 907.777.8413 office 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 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. 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:Lau, Jack J (OGC) To:AOGCC Records (CED sponsored) Subject:FW: PBE NK-41B 13-3/8" Post-Plug Csg Test and FIT (PTD: 2244-153) Date:Monday, February 3, 2025 9:42:36 AM Attachments:PBE NK-41B CSG FIT 2-2-25.pdf From: Frank Roach <Frank.Roach@hilcorp.com> Sent: Sunday, February 2, 2025 10:08 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Lau, Jack J (OGC) <jack.lau@alaska.gov>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: PBE NK-41B 13-3/8" Post-Plug Csg Test and FIT (PTD: 2244-153) Mel, Attached is the casing test and FIT results post-window milling this afternoon. The abandonment of NK-41A went about as good as could be expected. It was a clean cut and pull of the 9-5/8”. The 13-3/8” retainer set and subsequent abandonment cement job went well with planned volumes pumped through the retainer and cement spotted on top of the plug. After waiting on compressive strength, the weight tag of the cement on top of the retainer and pressure test of the 13-3/8” surface casing were both State-witnessed. We are currently pulling out of the hole with the milling assembly. Once to surface, the mills will be inspected and if wear is within limits, we’ll be picking up our motor assembly to kick off and start our 12-1/4” intermediate 1 hole section. Regards, Frank V Roach Drilling Engineer Hilcorp Alaska, LLC 907.854.2321 mobile 907.777.8413 office The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CASING AND LEAK-OFF FRACTURE TESTS Well Name:PBE NK 41-B Date:2/2/2025 Csg Size/Wt/Grade:13.375" 68# L-80 BTC Supervisor:Barber/ Serafine Csg Setting Depth:4,227 TMD 3,951 TVD - Open Hole Mud Weight:9 ppg LOT / FIT Press =720 psi LOT / FIT =12.50 ppg Hole Depth =4247 md Fluid Pumped=2.5 Bbls Volume Back =2.5 bbls Estimated Pump Output:0.0925 Barrels/Stroke LOT / FIT DATA CASING TEST DATA Enter Strokes Enter Pressure Enter Strokes Enter Pressure Here Here Here Here ->250 ->5 160 ->492 ->10 342 ->6 141 ->15 545 ->8 202 ->20 777 ->10 261 ->25 965 ->12 330 ->30 1159 ->14 398 ->35 1340 ->16 457 ->40 1524 ->18 526 ->45 1697 ->20 570 ->50 1895 ->22 639 ->55 2113 ->24 689 ->60 2287 ->26 736 ->65 2495 -> ->70 2696 Enter Holding Enter Holding Time Here Pressure Here Time Here Pressure Here ->0 736 ->0 2650 ->1 674 ->1 2645 ->2 654 ->2 2640 ->3 640 ->3 2635 ->4 628 ->4 2628 ->5 620 ->5 2622 ->6 614 ->10 2615 ->7 607 ->15 2610 ->8 600 ->20 2606 ->9 596 ->25 2603 ->10 594 ->30 2600 -> -> -> -> -> -> 2 4 6 8 10 12 14 16 18 20 22 24 26 5 10 15 20 25 30 35 40 45 50 55 60 65 70 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 2100 2200 2300 2400 2500 2600 2700 2800 2900 3000 3100 3200 3300 3400 3500 3600 3700 3800 0 1020304050607080Pressure (psi)Strokes (# of) LOT / FIT DATA 736 674654640628620614607600596594 265026452640263526282622 2615 2610 2606 2603 2600 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 2100 2200 2300 2400 2500 2600 2700 2800 2900 3000 3100 3200 3300 3400 3500 3600 3700 3800 0 5 10 15 20 25 30Pressure (psi)Time (Minutes) LOT / FIT DATA 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 Sean McLaughlin Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK, 99503 Re: Prudhoe Bay Field, Undefined Sag River and Ivishak Oil Pool, PBU NK-41B Hilcorp Alaska, LLC Permit to Drill Number: 224-153 Surface Location: 1474’ FSL, 717’ FEL, Sec 36, T12N, R15E, UM, AK Bottomhole Location: 1196' FSL, 1161' FEL, Sec 28, T12N, R16E, UM, AK Dear Mr. McLaughlin: 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, Greg C. Wilson Commissioner DATED this 23rd day of December 2024. Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2024.12.23 13:19:42 -09'00' 8-1/2"x9-7/8" By Grace Christianson at 10:18 am, Dec 13, 2024 Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2024.12.13 09:48:44 - 09'00' Sean McLaughlin (4311) DSR-12/16/24 Undefined Sag River and Ivishak 50-029-22778-02-00 A.Dewhurst 19DEC24 * BOPE test to 4500 psi. Annular to 3500 psi. MGR20DEC2024 224-153 MEUIRUMOF Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2024.12.23 13:23:25 -09'00'12/23/24 12/23/24 RBDMS JSB 122424 Prudhoe Bay East (PBU) NK-41B Drilling Program Version 0 12/03/2024 Table of 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 ............................................................................................... 9 8.0 Mandatory Regulatory Compliance / Notifications ............................................................... 10 9.0 Pre-Rig, R/U, and Preparatory Work .................................................................................... 13 10.0 N/U BOPE ............................................................................................................................... 14 11.0 Decomplete, Cut & Pull 9-5/8” ............................................................................................... 15 12.0 Set Whipstock, Mill 12-1/4” Window ..................................................................................... 17 13.0 Drill 12-1/4” Intermediate 1 Hole Section .............................................................................. 20 14.0 Run 9-5/8” Intermediate 1 Casing .......................................................................................... 24 15.0 Cement 9-5/8” Intermediate Casing ....................................................................................... 27 16.0 Drill 8-1/2” x 9-7/8” Intermediate 2 Hole Section .................................................................. 30 17.0 Run 7” Intermediate 2 Liner .................................................................................................. 35 18.0 Cement 7” Intermediate 2 Liner ............................................................................................ 38 19.0 Drill 6-1/8” Production Hole Section ...................................................................................... 41 20.0 Run 4-1/2” Production Liner .................................................................................................. 45 21.0 Cement 4-1/2” Production Liner ............................................................................................ 48 22.0 Run Upper Completion/ Post Rig Work ................................................................................ 51 23.0 Parker 273 Rig BOP Schematic .............................................................................................. 55 24.0 Wellhead Schematic ................................................................................................................ 56 25.0 Days Vs Depth ......................................................................................................................... 57 26.0 Formation Tops & Information.............................................................................................. 58 27.0 Anticipated Drilling Hazards ................................................................................................. 62 28.0 Parker 273 Rig Layout............................................................................................................ 68 29.0 FIT Procedure ......................................................................................................................... 69 30.0 Parker 273 Rig Choke Manifold Schematic ........................................................................... 70 31.0 Casing Design .......................................................................................................................... 71 32.0 12-1/4” Hole Section MASP .................................................................................................... 72 33.0 8-1/2” x 9-7/8” Hole Section MASP ........................................................................................ 73 34.0 6-1/8” Hole Section MASP ...................................................................................................... 74 35.0 Spider Plot (NAD 27) (Governmental Sections) ..................................................................... 75 36.0 Surface Plat (As Built) (NAD 27) ............................................................................................ 76 Page 2 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 1.0 Well Summary Well PBU NK-41B Pad Prudhoe Bay DS-NK Planned Completion Type 4-1/2” Production Tubing Target Reservoir(s) Sag / Ivishak Sands Planned Well TD, MD / TVD 21,951’ MD / 10,166’ TVD PBTD, MD / TVD 21,871’ MD / 10,097’ TVD Surface Location (Governmental) 1,474' FSL, 717' FEL, Sec 36, T12N, R15E, UM, AK Surface Location (NAD 27) X= 721,841.38, Y= 5,980,017.95 Top of Productive Horizon (Governmental)1,308' FNL, 1,384' FEL, Sec 28, T12N, R16E, UM, AK TPH Location (NAD 27) X= 736,341.30, Y= 5,988,242.18 BHL (Governmental) 1,196' FNL, 1,161' FE L, Sec 28, T12N, R16E, UM, AK BHL (NAD 27) X= 736,560.06, Y= 5,988,360.75 AFE Number 241-00162 AFE Drilling Days 55 AFE Completion Days 8 Maximum Anticipated Pressure (Surface) 3958 psig Maximum Anticipated Pressure (Downhole/Reservoir) 4971 psig Work String 5” 19.5# S-135 XT-50 4” 14# S-139 XT-39 Parker 273 KB Elevation above MSL: 19.4 ft + 46.95 ft = 66.35 ft GL Elevation above MSL: 19.4 ft BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams 4971 psig 3958 psig Page 3 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 2.0 Management of Change Information Page 4 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 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 20” 19.25 - - - X-52 Weld *16” 13-3/8” 12.415 12.259 14.375 68 L-80 BTC 5,020 2,270 1,556 12-1/4” 9-5/8” 8.681 8.525 10.625 47 L-80 DWC-C 6,870 4,760 1,086 8-1/2”x 9-7/8”7” 6.276 6.151 7.656 26 L-80 VamTop 7,240 5,410 604 6-1/8 4-1/2” 3.958 3.833 4.937 12.6 13Cr-80 VamTop 8,430 7,500 288 Tubing 4-1/2” 3.958 3.833 4.937 12.6 13Cr-80 VamTop 8,430 7,500 288 *Existing hole section and casing string 4.0 Drill Pipe Information: Hole Section OD (in) ID (in)TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn M/U (Min) M/U (Max) Tension (k-lbs) Surf, Int, & Prod 5”4.276” 3.500”6.500”19.5 S-135 XT50 44,000 52,800 712klb 4”3.340”2.688”4.875”14.0 S-135 XT39 17,700 21,200 513klb All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 5 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 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 Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area – this will not save the data entered, and will navigate to another data entry. x Ensure time entry adds up to 24 hours total. x Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. x Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 5.2 Afternoon Updates x Submit a short operations update each work day to sean.mclaughlin@hilcorp,com, frank.roach@hilcorp.com, nathan.sperry@hilcorp.com, jengel@hilcorp.com and joseph.lastufka@hilcorp.com 5.3 Intranet Home Page Morning Update x Submit a short operations update each morning by 7am on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 5.4 EHS Incident Reporting x Health and Safety: Notify EHS field coordinator. x Environmental: Drilling Environmental Coordinator x Notify Drilling Manager & Drilling Engineer on all incidents 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, frank.roach@hilcorp.com, jengel@hilcorp.com and joseph.lastufka@hilcorp.com 5.6 Casing and Cement report x Send casing and cement report for each string of casing to sean.mclaughlin@hilcorp,com, frank.roach@hilcorp.com, jengel@hilcorp.com and joseph.lastufka@hilcorp.com 5.7 Hilcorp Contact List: Title Name Work Phone Email Drilling Manager Sean McLaughlin 907.223.6784 sean.mclaughlin@hilcorp.com Drilling Engineer Frank Roach 907.777.8413 frank.roach@hilcorp.com Drilling Engineer Joe Engel 907.777.8395 jengel@hilcorp.com Drilling Engineer Nate Sperry 907.777.8450 nathan.sperry@hilcorp.com Completion Engineer Eric Dickerman 907.564.4061 eric.dickerman@hilcorp.com Geologist Ryan Phelps 907.777.8361 ryan.phelps@hilcorp.com Reservoir Engineer Jeff Allen 907.777.8428 jallen@hilcorp.com Drilling Env. Coordinator Adrian Kersten 907.564.4820 adrian.kersten@hilcorp.com Drilling Tech Joe Lastufka 907.777.8400 Joseph.Lastufka@hilcorp.com Page 6 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 6.0 Planned Wellbore Schematic Pre-Rig Abandonment Schematic: Page 7 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure Pre-Window Schematic: Page 8 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure Proposed Schematic: Page 9 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 7.0 Drilling / Completion Summary NK-41B is a sidetrack producer planned to be drilled in the Sag and Ivishak sands. The parent wellbore, NK-41A, is a shut-in, suspended well since November, 1997. The 1997 lower abandonment was confirmed on 12/11/24, prior to the rig’s arrival on the well. Operations covered on a separate sundry. The directional plan is a 12-1/4” intermediate 1 hole will be drilled and 9-5/8” casing set in the CM3. An 8- 1/2”x9-7/8” underreamed intermediate 2 hole will be drilled and 7” liner set at TSGR. A 6-1/8” slant section will be drilled across the Sag River and Ivishak formations and TD in BSAD. A 4-1/2” production liner will be run and cemented in place. The well will be completed with 4-1/2” production tubing. Perforating will be performed post-rig. Parker 273 will be used to finish decomplete, drill, and complete the wellbore. Drilling operations are expected to commence approximately January 11, 2024, pending rig schedule. All cuttings & mud generated during drilling operations will be hauled to one of two locations: Primary: Prudhoe G&I on Pad 4 Secondary: the Milne Point “B” pad G&I facility General sequence of operations: 1. MIRU Parker 273 to well site 2. N/U & Test BOPE 3. Pull Hanger. Cut and pull 9-5/8” casing. 4. Run whipstock and mill 12-1/4” window. 5. Drill 12-1/4” to TD of intermediate 1 hole section. 6. Run and cement 9-5/8” intermediate 1 casing 7. Drill 8-1/2”x9-7/8” to TD of intermediate 2 hole section. 8. Run and cement 7” intermediate 2 liner 9. Drill 6-1/8” hole to TD 10. Run and cement 4-1/2” production liner 11. Run Upper Completion 12. N/D BOP, N/U Tree, RDMO Reservoir Evaluation Plan: 1. Intermediate 1 Hole: No mud logging. Remote Ops geologist. LWD: GR + Res 2. Intermediate 2 Hole: Mud logging. Field Ops geologist for casing pick. Triple Combo 3. Production Hole: Mud logging. Field Ops geologist. Triple-Combo For any cuttings collected, submit a set of washed and dried cuttings to AOGCC as per 20 AAC 25.071(b)(2). -A.Dewhurst 17DEC24 Page 10 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with all applicable AOGCC regulations, specific regulations are listed below. 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 (1) week intervals during the decompletion of PBU NK-41A. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. x BOPs shall be tested at (2) week intervals once the window has been milled and during the drilling and completion of PBU NK-41B. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. x The initial and subsequent tests of BOP equipment will be to 250/4,500 psi for 5/5 min (annular to 70% rated WP, 3,500 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 control fluid flow from the well bore, AOGCC is to be notified and we must 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 7-14 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”. o Ensure the diverter vent line is at least 75’ away from potential ignition sources x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. x Casing pressure test criteria in 20 AAC 25.030 (e) Casing and Cementing,“A casing pressure test must be performed if BOPE is to be installed on a casing. The casing must be tested to hold a minimum surface pressure equal to 50 percent of the casing internal yield pressure. The test pressure must show stabilizing pressure and may not decline more than 10 percent within 30 minutes. The results of this test and any subsequent tests of the casing must be recorded as required by 20 AAC 25.070(1)”. - No diverter planned. - mgr Page 11 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure AOGCC Regulation Variance Requests: x No variances are requested at this time. Summary of Parker 273 BOP Equipment & Test Requirements Hole Section Equipment Test Pressure (psi) 12-1/4” x 13-5/8” x 5M Annular BOP x 13-5/8” x Double Gate o Blind ram in btm cavity x Mud cross w/ 3-1/8” x 5M side outlets x 13-5/8” x Single ram x 3” x 5M Choke Line x 2” x 5M Kill line x 3” x 5M Choke manifold x Standpipe, floor valves, etc Initial Test: 250/4,500 Annular: 250/3,500 Subsequent Tests: 250/4,500 Annular: 250/3,500 8-1/2” x 13-5/8” x 5M Annular BOP x 13-5/8” x Double Gate o Blind ram in btm cavity x Mud cross w/ 3-1/8” x 5M side outlets x 13-5/8” x Single ram x 3” x 5M Choke Line x 2” x 5M Kill line x 3” x 5M Choke manifold x Standpipe, floor valves, etc 6-1/8” x 13-5/8” x 5M Annular BOP x 13-5/8” x Double Gate o Blind ram in btm cavity x Mud cross w/ 3-1/8” x 5M side outlets x 13-5/8” x Single ram x 3” x 5M Choke Line x 2” x 5M Kill line x 3” x 5M Choke manifold x Standpipe, floor valves, etc Primary closing unit: Sara Koomey Control Unit, 3,000 psi, 316 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is an air-driven pump and emergency pressure is provided by bottled nitrogen. The remote closing operator panels are located in the doghouse and on accumulator unit. Page 12 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 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 spud. x 24 hours notice prior to testing BOPs. x 24 hours notice prior to casing running & cement operations. x Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email:melvin.rixse@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) Page 13 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 9.0 Pre-Rig, R/U, and Preparatory Work 9.1 Prior to the rig’s arrival, the following steps should have been completed (for more detail, refer to the 10-403 for NK-41A): x MIT 9-5/8” Casing (passed to 2,174psi on 12/11/24) x MIT-OA (established open shoe @ 1,900psi on 12/11/24) x CBL and drift of 9-5/8” Csg from 8,000’ to surface x Install 9-5/8” plug and pressure test same x Punch 9-5/8” csg @ ~6,990’ and circ clean through OA x Cement down 9-5/8” and up 9-5/8” x 13-3/8” annulus with annular planned TOC at 6,000’ x After cement reaches compressive strength, tag plug and CMIT TxIA t/2,500psi 9.2 NK-41B will utilize NK-41A’s wellhead and surface casing on DS-NK. Ensure to review attached surface plat and make sure rig is over appropriate wellhead. 9.3 Ensure PTD and drilling program are posted in the rig office and on the rig floor. 9.4 Level pad and ensure enough room for layout of rig footprint and R/U. 9.5 Rig mat footprint of rig. 9.6 Ensure any necessary wellhead equipment is staged prior to MIRU. 9.7 MIRU Parker 273 Ensure rig is centered over wellhead to prevent any wear to BOPE or wellhead. 9.8 Note: 9.8 ppg NaCl brine should be left in the well from the pre-rig decomplete work. Confirm fluids in handover to ensure consistent fluids will be in the well prior to displacing to milling fluid. 9.9 Ensure 5-3/4” liners in mud pumps. x NOV 12-P-160 1,600 HP mud pumps are rated at 5,085 psi, 466 gpm @ 120 spm @ 96% volumetric efficiency. g@ g Cement down 9-5/8” and up 9-5/8” x 13-3/8” annulus with annular planned TOC at 6,000’ x pp After cement reaches compressive strength, tag plug and CMIT TxIA t/2,500psi Page 14 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 10.0 N/U BOPE 10.1 Install TWC in hanger profile. Pressure test to 250/4,500 psi for 5 min. 10.2 N/D tree and adapter flange. 10.3 N/U 13-5/8 x 5M BOP as follows: x BOP configuration from top down: 13-5/8” x 5M annular / 13-5/8” x 5M double gate / 13- 5/8” x 5M mud cross / 13-5/8” x 5M single gate x Double gate ram should be dressed with 2-7/8” x 5” VBRs or 5” solid body rams in top cavity,blind ram in bottom cavity. x Single ram can be dressed with 2-7/8” x 5” VBRs or 5” solid body rams x NU bell nipple, install flowline. x Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to mud cross). x Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual valve 10.4 RU MPD RCD and related equipment 10.5 Notify AOGCC and Test BOP to 250/4,500 psi for 5/5 min. Test annular to 250/3,500 psi for 5/5 min. x Test with 5” test joint and test VBR’s with 4” and 5” test joints x Smallest and largest pipes to be ran x Confirm test pressures with PTD x Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure is trapped underneath test plug x Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech 10.6 RD BOP test equipment. 10.7 Pull TWC. 250/4,500 psi Page 15 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 11.0 Decomplete, Cut & Pull 9-5/8” 11.1 Pull hanger and pup joint to rig floor and L/D. 11.2 P/U 8-1/2” cleanout assembly: 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 Utilize used roller cone bit with jets removed for maximum flow. x Drill string will be 5” 19.5# S-135. 11.3 RIH w/cleanout assy to ~6,000’ MD 11.4 Slowly wash down and tag cement plug from pre-rig work. CBU 2-4x ensuring clean brine in and out. 11.5 Flow check well. POOH & LD cleanout assembly 11.6 MU mechanical casing cutter BHA per fishing representative. Make sure cutters are dressed to be able to cut 9-5/8” 47# casing. 11.7 RIH to cut depth @ ~5,000’ MD. Locate the collars above and below proposed cut depth. Cut casing in the middle of the joint identified by the coupling locate. x After the pressure drop indicating the cut is seen spin the cutter for an additional 15 minutes. This helps to ensure that the cutter blades have completely cut through the casing. x If the cut appears to go poorly (casing grabs blades, other anomalies), plan to make the casing stub polishing run. Final decision for the polishing/scraper run may be made once the cut joint is pulled 11.8 Line up to take returns from the OA to the flowback tank. Close annular around drillpipe, break circulation, and CBU 2x min at max rate. After consistent fluid in and out, shut down and flow check well for 10 minutes to confirm well is in balance. 11.9 POOH and LD casing cutter BHA. 11.10 Back out lockdown screws. x 9-5/8” casing was originally set on slips so there is a high probability that the casing was set in tension. However, be prepared for the potential of casing growth. If the last couple lockdown screws become tight when backing out, Stop and retighten LDS. RIH w/HWDP and hang off with a RTTS (or equivalent) packer. While staying connected to the packer, attempt to back out LDS again. Once successful, release RTTS, lay down packer, and HWDP. Page 16 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 11.11 Spear and pull 9-5/8” casing to the floor. Release spear and LD same. LD 9-5/8” casing down to the cut. Note torque required to break connections, overall condition of the casing, and the cut. Depending on condition, joints may be salvaged for future shoetrack/pup joints. Inspect casing for NORM prior to removal from location. Page 17 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 12.0 Set Whipstock, Mill 12-1/4” Window 12.1 MU 13-3/8” cleanout assembly (to include 12-1/4” bit and 13-3/8” casing scraper). Space out casing scraper where it will cover planned whipstock setting depth and contingency bridge plug depth. RIH with cleanout assembly to ~100’ above the cut. 12.2 CBU 2-4x while pumping pills/sweeps to help in cleaning the 13-3/8” casing. Ensure fluid is consistent both in and out before shutting down. 12.3 RU casing testing equipment and PT 13-3/8” casing to 2500 psi for 30 min, chart test. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001. 12.4 Flow check well for 10 minutes prior to tripping out. POOH & LD cleanout assembly. 12.5 CONTINGENCY: If unable to get passing PT of the 13-3/8”, P/U 13-3/8” mechanical plug, RIH to set depth (TBD based on cut depth) & set same. 12.6 Whipstock set depth information: x Planned TOW: 4,254’ x Whipstock should be set to avoid a collar while milling the window. x Drilling Foreman, Whipstock hand, and drilling engineer to agree on set depth 12.7 MU 12-1/4” mill/whipstock assembly as per WIS tally: x MU HWDP, string magnets, and float sub x Ensure ditch magnets are installed in shaker room and cleaned prior to running in with the whipstock 12.8 Install MWD and orient. Rack back mill assembly x Ensure a dedicated MWD is available for the orientation of the whipstock 12.9 Verify offset between MWD and the whipstock tray, witnessed and agreed by the Drilling Foreman, MWD/DD personnel, and WIS rep. Document and record offset in well file. 12.10 Slowly RIH with whipstock assembly per WIS rep. x RIH no faster than 1.5 to 2 minutes per stand. x Ensure workstring is stationary prior to setting in slips to avoid weakening shear bolt and prematurely tripping/setting the anchor. 12.11 Stop 30-45’ above planned set depth. Work torque out of string. Measure and record P/U and S/O weights. Obtain survey with MWD for orienting whipstock. 12.12 Orient whipstock to desired direction by turning DP in ¼ round increments. P/U and S/O on DP to work all torque out after oriented. (Being careful not to set trip anchor). Target orientation is 30q LOHS – Consult with milling hand * Notify AOGCC if casing test fails. - mgr Page 18 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 12.13 Whipstock orientation: x Desired orientation of the whipstock face is 15R to 45R, target is 20 ROHS x Hole Angle at window interval (@ 4,254’, 55° inc, 46° azi) x Sidetrack tangent section is 74q inclination and 63q azimuth 12.14 Once whipstock is in the desired orientation, set whipstock per WIS rep. 12.15 Displace well over to 9.0 ppg milling fluid. Confirm fluid in and out has correct parameters and sufficient for moving metal shavings/cuttings uphole: x Funnel visc: 40-60s x YP: 18-20 12.16 Record P/U, S/O weights, and free rotation. Slack off to top of whipstock and with light weight and low torque. Mill window as per whipstock contractor representative. Pump high visc sweeps as necessary. 12.17 Clean catch trays and ditch magnets frequently while milling window to collect metal cuttings/shavings. Track weight of recovered metal to gauge whether window milling was complete. 12.18 Mill window until the uppermost mill has passed across the entire tray. Dress and polish window as needed. 12.19 With upper mill at the end of the tray, this will drill ~ 20’ of new hole. 12.20 After window is milled but before POOH, shut down pumps and work milling assembly through window watching for drag. Dress and polish window as needed. After reaming, shut off pumps and rotary and dry drift window. 12.21 Circulate bottoms up until even MW in/out and hole is clean of metal shavings. Reduce mud properties for drilling or displace over to 9.0 ppg LSND drilling fluid. 45R 15R Page 19 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 12.22 Pull window milling assembly into 13-3/8” casing and perform FIT to 12.5ppg EMW. Chart test. Ensure test is recorded on same chart as the casing test. Document incremental volume pumped (and subsequent pressure) and volume returned. x 13-3/8” surface casing is fully cemented. Open hole weak point is the top of the window and ~ 4,254’ MD / ~ 3,956’ TVD. x 12.5 ppg FIT value is to cover over and above expected ECD while drilling interval. x 12.3 ppg provides >25 bbls based on 11.0 ppg MW +0.5ppg intensity, 10.0 ppg PP. x If 12.3 ppg EMW is not achieved, contact drilling engineer. 12.23 POOH and LD window milling BHA. Gauge all mills for wear. Depending on results, have backup milling assembly ready to dress window to desired dimensions. 12.24 PU stack washer and wash across BOPE. Function all rams to clear any potential milling debris. Pull window milling assembly into 13-3/8” casing and perform FIT to 12.5ppg * Casing test and FIT digital data to AOGCC upon completion of FIT. - mgre Page 20 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 13.0 Drill 12-1/4” Intermediate 1 Hole Section 13.1 P/U 12-1/4” RSS directional BHA. 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 Ensure MWD is R/U and operational. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. x Drill string will be 5” 19.5# S-135 XT50. x Run a non-ported float in the production hole section. 13.2 12-1/4” hole section mud program summary: x Density: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. x Solids Concentration:Keep the shaker screen size optimized and fluid running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible. x Rheology: Keep viscosifier additions reasonably low. Utilize sweeps (weighted, high vis, tandem) to inform hole cleaning efficiency. Ensure 6 rpm is > 12 (~hole diameter) for sufficient hole cleaning x Run the centrifuge as needed while drilling the intermediate hole, this will help with solids removal. x Dump and dilute as necessary to keep drilled solids to an absolute minimum. x MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, & Toolpusher office. System Type:9.0 – 11.0 ppg LSND drilling fluid Properties: Interval Density PV YP API FL HPHT Drill Solids MBT Hardness ~4,254’ – ~9,422’ Window –UG4 9.0 – 9.6 5 – 20 15 – 30 < 8 N/A <6% <12 <200 ~9,422’ – ~17,408’ UG4 –CM3 9.6 – 10.6 5 – 20 15 – 30 < 6 N/A <6% <20 <200 ~17,408’ – TD CM3 –TD 10.5 – 11.0 5 – 20 15 – 30 < 6 <10 <6% <20 <200 Page 21 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure System Formulation: Product- intermediate Size Pkg ppb or (% liquids) Soda Ash 50 lb sx 0.17 PowerVIS 25 lb sx 1.5 –2.0 M-I Pac UL 50 lb sx 3.0 Hydrahib/Kla-Stop 55 gal dm 1.0 –1.5 KCl 50 lb sx 10.7 SCREENKLEEN 55 gal dm 0.25 M-I Wate 50 lb sx 56 (as needed for wt) Busan 1060 55 gal dm 2.1 13.3 Displace wellbore to 10.0 ppg LSND drilling fluid 13.4 Obtain initial ECD benchmark readings prior to drilling ahead. 13.5 Drill 12-1/4” hole section from 13-3/8” window to ~ 9,200’ MD (~200’ MD above UG4) per Geologist and Drilling Engineer Utilizing the following parameters: x Flow Rate: 700-950 GPM x RPM: Maximize RPM when rotating Take the first couple stands to understand BHA tendency. x Ensure shakers are set up to handle this flowrate. Ensure shakers are running slightly wet to maximize solids removal efficiency. Check for holes in screens on every connection. x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex: concretion deflection x Monitor Torque and Drag with pumps on every 5 stands x Monitor ECD, pump pressure & hookload trends for hole cleaning indication. Attempt to limit drilling ECD to 1.0 ppg over calculated cleanhole ECD. x Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across any sands for any extended period of time. x Limit maximum instantaneous ROP to < 200 FPH. The SV sands will drill faster than this, but good hole cleaning practices now reduces time needed to cleanup prior to running casing. x Limit WOB to 20k max to maintain bit stability when encountering hard stringers in the UG4-UG1 x 12-1/4” Hole Section A/C: x There are no wells with a CF < 1.0 13.6 Toward the end of the above interval, begin to weight up from 9.0 ppg to 9.6 ppg. Ensure mud is a consistent 9.6 ppg ~200’ before entering the UG4. x If using a spike fluid to weight up, ensure the fluid is heated to avoid shocking the formation 13-3/8” window to ~ 9,200’ MD Page 22 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 13.7 Drill 12-1/4” hole section from ~9,200’ MD to ~ 17,200’ MD (~200’ MD above CM3) per Geologist and Drilling Engineer Utilizing the following parameters: x Flow Rate: 700-950 GPM x RPM: Maximize RPM when rotating x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex: concretion deflection x Monitor Torque and Drag with pumps on every 5 stands x Monitor ECD, pump pressure & hookload trends for hole cleaning indication. Attempt to limit drilling ECD to 1.0 ppg over calculated cleanhole ECD. x Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across any sands for any extended period of time. x Limit maximum instantaneous ROP to < 200 FPH. The UG and WS sands will drill faster than this, but good hole cleaning practices now reduces time needed to cleanup prior to running casing. x Unpredictable hard streaks can be encountered in the UG and WS formations. Reduce rotary speed while maintaining WOB to avoid high impact loading and subsequent PDC cutter damage. x 12-1/4” Hole Section A/C: x There are no wells with a CF < 1.0 13.8 Toward the end of the above interval, begin to weight up from 9.6 ppg to 10.5 ppg. Ensure mud is a consistent 10.5 ppg ~200’ before entering the CM3. 13.9 Drill 12-1/4” hole section from ~17,200’ MD to section TD (projected at ~17,507’ MD) per Geologist and Drilling Engineer Utilizing the following parameters: x Flow Rate: 700-950 GPM x RPM: Maximize RPM when rotating x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex: concretion deflection x Monitor Torque and Drag with pumps on every 5 stands x Monitor ECD, pump pressure & hookload trends for hole cleaning indication x Limit maximum instantaneous ROP to < 200 FPH. Good hole cleaning practices now reduces time needed to cleanup prior to running casing. x Limit WOB to 20k max to maintain bit stability when encountering hard stringers in the UG4-UG1 x Once CM3 is penetrated, limit ECD to 0.5 ppg over calculated clean-hole ECD. Pay close attention to pump pressure to reduce Colville breathing risk. x 12-1/4” Hole Section A/C: x There are no wells with a CF < 1.0 Page 23 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 13.10 At TD, CBU (minimum 5-7X, more if needed) at max rate and rotation (120+ rpm). Pump tandem sweeps x Obtain BHCT from MWD tools and provide to Halliburton cementers. x Rack back a stand at each bottoms up and reciprocate a full stand in between (while circulating the BU). Keep the pipe moving while pumping. x Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent stream, circulate more if necessary 13.11 BROOH to just below 12-1/4” window x Circulate at full drill rate unless losses are seen. x Rotate at maximum rpm that can be sustained. x Target pulling speed of 5 – 10 min/std (slip to slip time, not including connections), but adjust as hole conditions dictate. Slow pulling speed when backreaming through coal depths seen when drilling. x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling from the lower SVs. x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. x Monitor returns during the backream for increase in cuttings. With this high sail angle, cuttings in laterals will come back in waves and not a consistent stream so circulate more if necessary. 13.12 Slowly pull into the window and stop ~1-2 stands above the window, inside the 13-3/8” casing. CBU minimum 2x to clean the casing. Utilize sweeps as needed. Flow-check well prior to tripping out. 13.13 POOH and LD BHA. 13.14 Change out upper rams to 9-5/8” fixed-bore rams and test with 9-5/8” test joint. Page 24 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 14.0 Run 9-5/8” Intermediate 1 Casing 14.1 Well control preparedness: In the event of an influx of formation fluids while running the intermediate casing, the following well control response procedure will be followed: x P/U & M/U the 5” safety joint (with 9-5/8” crossover installed on bottom, TIW valve in open position on top, 5” handling joint above TIW). This joint shall be fully M/U and available prior to running the first joint of 9-5/8” casing. x Slack off and with 5” DP across the BOP, shut in ram or annular on 5” DP. Close TIW. x Proceed with well kill operations. 14.2 R/U 9-5/8” casing running equipment. x Ensure 9-5/8” 47# BTC x XT50 crossover is on rig floor and M/U to FOSV. x Use BOL 2000 (or equivalent) thread compound. Dope pin end only w/ paint brush. x R/U CRT equipment. x Ensure all casing has been drifted to 8-1/2” on location prior to running. x Note that 47# drift is 8.525” x Be sure to count the total # of joints on the deck 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. 14.3 P/U shoe joint, visually verify no debris inside joint. 14.4 Continue M/U & thread locking 120’ shoe track assembly consisting of: 9-5/8” Float Shoe 1 joint –9-5/8”, 2 Centralizers 10’ from each end w/ stop rings 1 joint – 9-5/8”, 1 Centralizer mid joint w/ stop ring 1 joint – 9-5/8”, 1 Centralizer mid joint w/ stop ring 9-5/8” Float Collar w/ Stage Cementer Bypass Baffle ‘Top Hat’ 1 joint – 9-5/8”, 1 Centralizer mid joint w/ stop ring x Ensure proper operation of float equipment while picking up. x Ensure to record S/N’s of all float equipment and stage tool components. 14.5 Continue running 9-5/8” intermediate casing x Fill casing while running using fill up line on rig floor. x Use BOL 2000 or equivalent thread compound. Dope pin end only w/ paint brush. x Centralization: x 1 centralizer every joint to within 120’ of the window x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Obtain up and down weights of the casing before entering open hole. Record rotating torque at 10 and 20 rpm x Likely to lose rotation capability around 11,600’ MD x See data sheets on the next page for MU torque for the 9-5/8” casing connection. Page 25 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 9-5/8” 47/# L-80 DWC/C Make-up Torque Casing OD Minimum Optimum Maximum 9-5/8” 40,000 ft-lbs 45,000 ft-lbs 59,400 ft-lbs Page 26 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 14.6 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 14.7 Slow in and out of slips. 14.8 RIH with 9-5/8” intermediate casing to 13-3/8” shoe at ~4,250’ MD. CBU and establish PU and SO weights prior to exiting shoe. 14.9 Continue to RIH with 9-5/8” intermediate casing using the following circulation strategy (Note: Take special care when staging pumps up and down to avoid packing off and breaking down formation): x 13-3/8” shoe to top WS2: Every 5th joint, staging up to planned cementing rate. Circulate for 5 minutes. x Top WS2 to TD: Every 10th joint, staging up to planned cementing rate. Circulate for 5 minutes. x Circulate down consecutive joints to achieve a full bottoms-up by TCM3 14.10 P/U hanger and landing joint and M/U to casing string. Casing shoe +/- 10’ from TD. 14.11 Break circulation at 1 bpm to avoid breaking down formation. Slowly stage up to full circulating rate (planned cementing rates). Allow circulating pressures to stabilize before increasing circulating rate to the next stage. Circulate 4 BU or more if needed to condition hole for cementing. Reduce YP to < 18 to help ensure success of cement job. Do not start the YP drop until casing is on bottom and cementers are ready. Page 27 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 15.0 Cement 9-5/8” Intermediate Casing 15.1 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 fluids can be delivered to the cementing unit at acceptable rates. x How to handle cement returns at surface. While not expected, ensure vac trucks are on standby and ready to assist. x Which pumps will be utilized for displacement, and how fluid will be fed to displacement pump. x Ensure adequate amounts 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. 15.2 Document efficiency of all possible displacement pumps prior to cement job. 15.3 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. 15.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and bottom plugs to ensure done in correct order. 15.5 Fill surface cement lines with water and pressure test. 15.6 Drop first bottom plug – HEC rep to witness. Pump spacer. 15.7 Drop second bottom plug – HEC rep to witness. Mix and pump lead cement per below calculations, confirm actual cement volumes with cementer after TD is reached. 15.8 Drop third bottom plug – HEC rep to witness. Mix and pump tail cement per below calculations, confirm actual cement volumes with cementer after TD is reached. x Cement volume based on annular volume + 40% open hole excess. Job will consist of lead & tail, TOC brought to ~14,000’ MD. Estimated Total Cement Volume: Page 28 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure Cement Slurry Design: 15.9 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 and continue with the cement job. 15.10 After pumping cement, drop top plug and displace with the rig pumps and LSND mud out of mud pits. x Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. x Ensure rig pump is used to displace cement. 15.11 Displacement calculation is in the Table in step 15.8. 15.12 Monitor returns closely while displacing cement. Adjust pump rate if losses or packing off are seen at any point during the job. 15.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling Engineer. 15.14 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. 15.15 While a low likelihood, be prepared for cement returns to surface. Open the shaker bypass line to the cuttings tank to dump any cement returns. Have black water available and vac trucks ready to assist. Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact with the cement. 15.16 Freeze protect 13-3/8” x 9-5/8” casing annulus to ~2,200’ MD with dead crude or diesel after cement tests indicate cement has reached 500 psi compressive strength. x Freeze protect with 131 bbls of dead crude/diesel Lead Slurry Tail Slurry System EconoCem HalCem Density 12.0 lb/gal 15.8 lb/gal Yield 2.35 ft3/sk 1.16 ft3/sk Mix Water 13.92 gal/sk 4.98 gal/sk Page 29 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure x Ensure total injection volume injected down the annulus (including any mud used to keep annulus open) doesn’t exceed 110% of the 13-3/8” x 9-5/8” annular volume. 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 jengel@hilcorp.com and joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 30 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 16.0 Drill 8-1/2” x 9-7/8” Intermediate 2 Hole Section 16.1 MU 8-1/2” Cleanout BHA (Milltooth Bit & 1.22° PDM) 16.2 TIH w/ 8-1/2” cleanout BHA to float equipment. Note depth TOC tagged on AM report. 16.3 R/U and test casing to 4500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and plot on FIT graph. Document incremental volume pumped (and subsequent pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001 16.4 Drill out shoe track and 20’ of new formation. 16.5 CBU and condition mud for FIT. 16.6 Conduct FIT to 12.8 ppg EMW. Chart Test. Ensure test is recorded on same chart as casing test. Document incremental volume pumped (and subsequent pressure) and volume returned. Submit casing test and FIT digital data to AOGCC. x 12.8 ppg FIT provides >>25bbls based on 11.5 ppg MW +0.5ppg kick intensity, 9.40 ppg EMW PP @ TD 16.7 POOH & LD Cleanout BHA 16.8 MU 8-1/2” x 9-7/8” directional BHA x RSS and Triple Combo x Ensure BHA components have been inspected previously. x Drift and caliper all components before MU. Visually verify no debris inside components that cannot be drifted. x Ensure MWD is RU and operational. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. x NOV underreamer will be utilized above the MWD to allow for 9-7/8” hole x NOV bit to match underreamer will be run. x Drill string will be 5” 19.5# S-135 XT50. x Run a solid float in the intermediate 2 hole section. 16.9 TIH w/ 8-1/2” x 9-7/8” BHA to 7” shoe. 16.10 Intermediate 2 hole section will use the same mud used to TD Intermediate 1 hole section. 16.11 8-1/2” x 9-7/8” hole section mud program summary: x Density: 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. * Casing test and FIT digital data to AOGCC upon completion of FIT. - mgr Page 31 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure x Solids Concentration: It is imperative that the solids concentration be kept low while drilling the production hole section. Keep the shaker screen size optimized and fluid running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible. x Rheology: Keep viscosifier additions to an absolute minimum (DUO-VIS / XCD). Data suggests excessive viscosifier concentrations can decrease return permeability. Do not pump high vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 10 (hole diameter) for sufficient hole cleaning x Run the centrifuge as needed while drilling the production hole, this will help with solids removal. x Dump and dilute as necessary to keep drilled solids to an absolute minimum. x MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, & Toolpusher office. System Type:10.5 – 11.5 ppg LSND drilling fluid Properties: Interval Density PV YP API FL HPHT Drill Solids MBT Hardness ~17,507’ – ~20,707’ Shoe –TCM1 10.5-11.0 5 – 20 15 – 30 <6 <10 <6% <20 <100 ~20,707’ – ~21,461’ CM1 –TD 11.0-11.5 5 – 20 15 – 30 <6 <10 <6% <20 <100 System Formulation: Product- intermediate Size Pkg ppb or (% liquids) Soda Ash 50 lb sx 0.17 PowerVIS 25 lb sx 1.5 –2.0 M-I Pac UL 50 lb sx 3.0 Hydrahib/Kla-Stop 55 gal dm 2.0 –1.5 KCl 50 lb sx 10.7 SCREENKLEEN 55 gal dm 0.25 M-I Wate 50 lb sx 56 (as needed for wt) Busan 1060 55 gal dm 2.1 16.12 Install MPD RCD 16.13 Begin drilling 8-1/2” hole section, on-bottom staging technique: x Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8K. x Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations Page 32 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure x If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to PU off bottom and restart on bottom staging technique. If stick slip continues, consider adding 0.5% lubes 16.14 Once ~300’ outside of the 9-5/8” shoe, pick up off bottom and activate underreamer per NOV procedure. Verify reamer blades are unlocked 16.15 Drill 8-1/2” x 9-7/8” hole section to ~20,500’ MD (~200’ above CM1) per geologist and Drilling Engineer utilizing the following parameters: x Flow Rate: 500-550 GPM, target min. AV’s in the 9-7/8” openhole: 180 ft/min, 530 GPM x Flow Rate: 500-550 GPM, AV’s in the 9-5/8” casing: 257 ft/min, 530 GPM x RPM: 120+ x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex: concretion deflection x Monitor Torque and Drag with pumps on every 5 stands x Monitor ECD, pump pressure & hookload trends for hole cleaning indication x Monitor downhole WOB/TOB and compare to surface parameters to ensure the bit or the underreamer isn’t being overworked x Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across any sands for an extended period of time. x Limit maximum instantaneous ROP to < 200 FPH. This is to minimize cutter damage if encountering concretions or the Tuffs section in the Colville. x Do not initiate backreaming while the underreamer is unlocked. Backreaming can damage the reamer cutting blocks or possibly back off the pilot BHA. x Prior to picking up off bottom for a connection, ensure WOB has drilled off (hookload and torque returning to free rotating values) and RPM gradually slowed to zero. This is to mitigate the risk of backing off the pilot BHA below the underreamer. x Target ROP is as fast as we can clean the hole without having to backream connections x MPD will be utilized to hold ECD and monitor any pressure build up on connections. x 8-1/2” x 9-7/8” Hole Section A/C: x There are no wells with a CF < 1.0 16.16 Toward the end of the above interval, begin to weight up from 10.5 ppg to 11.0 ppg. Ensure mud is a consistent 11.0 ppg ~200’ before entering the CM1 (projected top at 20,707’ MD). x Use a spike fluid to weight up and add black product for HRZ/Kingak stability. Ensure the fluid is heated to facilitate better mixing of the black product into the mud system and to avoid shocking the formation and inducing losses/breathing 16.17 Drill 8-1/2” hole section from ~20,500’ to section TD per Geologist and Drilling Engineer. x Flow Rate: 500-550 GPM, target min. AV’s 180 ft/min, 530 GPM in 9-7/8” openhole x Flow Rate: 500-550 GPM, target min. AV’s 257 ft/min, 530 GPM in 9-5/8” casing x RPM: 120+ Page 33 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex: concretion deflection x Monitor Torque and Drag with pumps on every 5 stands x Monitor ECD, pump pressure & hookload trends for hole cleaning indication x Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across the sand for any extended period of time. x Limit maximum instantaneous ROP to < 200 FPH while drilling through the Colville. This is to minimize cutter damage if encountering concretions or the Tuffs section in the Colville. x Once in the HRZ, limit maximum instantaneous ROP to < 100 FPH to TD. This is to minimize ECD spikes to cause instability in the shales. x Do not initiate backreaming while the underreamer is unlocked. Backreaming can damage the reamer cutting blocks or possibly back off the pilot BHA. x Prior to picking up off bottom for a connection, ensure WOB has drilled off (hookload and torque returning to free rotating values) and RPM gradutally slowed to zero. This is to mitigate the risk of backing off the pilot BHA. x Target ROP is as fast as we can clean the hole without having to backream connections x MPD will be utilized to hold ECD and monitor any pressure build up on connections. x 8-1/2” x 9-7/8” Hole Section A/C: x There are no wells with a CF < 1.0 16.18 TD will be in the SGR formation and confirmed via samples. Do not lock the underreamer blades until SGR samples are verified. Follow NOV/Halliburton parameters for rotating while circulating up samples with the blades unlocked. 16.19 Once samples are verified and the underreamer blades are locked closed, CBU at drilling rate and max rotation. Pump sweeps if needed x Monitor BU for increase in cuttings 16.20 Perform wiper trip to the 9-5/8” casing shoe x Pump out of the hole until above HRZ to maintain ECDs over shale stability minimums. x Pulling speed 5 – 10 min/stand (slip to slip time, not including connections), adjust as dictated by hole conditions x If pulling tight, trip back to TD and begin backreaming operations. x If backreaming operations are commenced, continue backreaming to the shoe 16.21 CBU minimum 5 times at 9-5/8” shoe at maximum flow rate and clean casing with high vis sweeps. 16.22 If trip to 9-5/8” shoe is clean, continue to POOH and LD BHA for upcoming liner run. 16.23 If trip to the shoe is troublesome, run back to TD and CBU 2x or until well cleans up, whichever comes later. Page 34 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 16.24 When at the 9-5/8” shoe, monitor well for flow. Increase mud weight if necessary. x Wellbore breathing has been seen on historical Niakuk wells. Perform extended flow checks to determine if well is breathing, treat all flow as an influx until proven otherwise x If necessary, increase MW at shoe for any higher than expected pressure seen 16.25 Pull RCD Bearing and install trip nipple. 16.26 POOH and LD BHA. Rabbit DP that will be used to run liner. Only LWD open hole logs are planned for the hole section (Triple Combo). There will not be any additional logging runs conducted. Page 35 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 17.0 Run 7” Intermediate 2 Liner 17.1 Well control preparedness: In the event of an influx of formation fluids while running the injection liner, the following well control response procedure will be followed: x P/U & M/U the 5” safety joint (with 7” crossover installed on bottom, TIW valve in open position on top, 5” handling joint above TIW). This joint shall be fully M/U and available prior to running the first joint of 7” liner. x Slack off and with 5” DP across the BOP, shut in ram or annular on 5” DP. Close TIW. x Proceed with well kill operations. 17.2 Change upper VBRs to 7” casing rams and test to 250 psi low, 4,500 psi high for 5/5 minutes using 7” test joint. 17.3 R/U 7” liner running equipment. x Ensure 7” 26# VT x XT50 crossover is on rig floor and M/U to FOSV. x Ensure all casing has been drifted on the deck prior to running. x Be sure to count the total # of joints on the deck 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. 17.4 Run 7” injection liner x Use Vam approved thread compound. Dope pin end only w/ paint brush. Wipe off excess. x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Use lift nubbins and stabbing guides for the liner run. x If liner length exceeds surface casing length, ensure centralizers are placed 1/jt for each joint outside of the surface shoe. x Obtain up and down weights of the liner before entering open hole. x See data sheet on the next page for MU torque for the 7” liner connections. x Centralization: x 1 centralizer every joint on all 7” liner 17.5 Run 7” liner as follows: 7” Float Shoe 1 solid joint – 7”, 2 Centralizers 10’ from each end w/ stop rings 7” Float Collar 1 solid joint – 7”, 1 Centralizer mid joint w/ stop rings 7” Landing collar 1 solid joint –7”, 1 Centralizer mid joint w/ stop rings 7” 26/# L-80 VT – Make up Torque Casing OD Minimum Optimum Maximum 7” 7,470 ft-lbs 8,300 ft-lbs 9,130 ft-lbs Page 36 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure Page 37 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 17.6 Ensure hanger/pkr will not be set in a 9-5/8” connection. x AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as per 20 AAC 25.030(d)(6). Plan is to place liner hanger with ~150’ overlap. Do not place liner hanger/packer across 9-5/8” connection. 17.7 Before picking up Baker SLZXP liner hanger / packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 17.8 M/U Baker SLZXP liner top packer to 7” liner. Circulate 2 liner volumes to clear string and allow for PAL mix to set 17.9 Note: PU, SO, ROT and torque of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 17.10 RIH with liner no faster than 30 ft/min – Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. x Ensure 5” DP has been drifted x Fill drill pipe on the fly. Monitor FL and if filling is required due to losses/surging. 17.11 Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to bottom. 17.12 Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, & 20 RPM. If torque approaches make-up torque of liner, discontinue rotation. 17.13 Continue to RIH with 7” intermediate 2 liner using the following circulation strategy (Note: Take special care when staging pumps up and down to avoid packing off and breaking down formation): x 9-5/8” shoe to top HRZ: Every 5th joint, staging up to planned cementing rate. Circulate for 5 minutes. x Circulate down consecutive joints to achieve a full bottoms-up by THRZ x Top HRZ to TD: Fill pipe only. Break circulation only if drag appears to be increasing or if there’s indications of getting stuck. Once circulation starts, circulate every stand down to TD. 17.14 Tag bottom and PU to position float shoe ~2’ off bottom. Last motion of the liner should be “up” to ensure it is set in tension. 17.15 Break circulation. Begin circulating at ~0.5 – 1 BPM and monitor pump pressures. Slowly stage up to full circulating rate (planned cementing rates). Allow circulating pressures to stabilize before increasing circulating rate to the next stage. Circulate 4 BU or more if needed to condition hole for cementing. Reduce YP to < 18 to help ensure success of cement job. Do not start the YP drop until liner is on bottom and cementers are ready. Do not exceed 1,600 psi while circulating for risk of prematurely setting liner hanger. Note all losses. Confirm all pressures with Baker. Page 38 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 18.0 Cement 7” Intermediate 2 Liner 18.1 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 How to handle cement returns at surface. Ensure vac trucks are on standby and ready to assist. x Which pumps will be utilized for displacement, and how fluid will be fed to displacement pump. x Ensure adequate amounts 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. 18.2 Document efficiency of all possible displacement pumps prior to cement job. 18.3 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. 18.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and bottom drillpipe darts into rotating cement head to ensure done in correct order. 18.5 Fill surface cement lines with water and pressure test. 18.6 Pump remaining spacer. 18.7 Drop lower drillpipe dart and pump cement per schedule below. Cement volume based on annular volume + 40% open hole excess. Job will consist of lead and tail slurries, TOC brought to top of liner. Estimated Total Cement Volume: Page 39 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure Cement Slurry Design: 18.8 Drop upper 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. 18.9 Displace cement at max rate of 7 bbl/min. Reduce pump rate to 2-3 bpm prior to latching each DP dart into liner wiper plug and park the string with liner on depth. Note plug departure from liner hanger running tool and resume pumping at full displacement rate. Displacement volume can be re-zeroed when the upper drillpipe dart latches into top liner wiper plug. 18.10 If elevated displacement pressures are encountered, position liner at setting depth and cease reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman immediately of any changes. 18.11 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. 18.12 Slack off 20K lbs on the SLZXP liner hanger/packer to ensure the HRDE setting tool is in compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4,500 psi to release the HRDE running tool Slack off total liner weight plus 30k to confirm hanger is set. 18.13 Bleed DP pressure to 0 psi and check floats. Pick up to expose rotating dog sub and set down 50K without pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating at 10-20 RPM and set down 50K again. 18.14 Pickup to verify that the HRD setting tool has released. If running tool cannot be hydraulically released, apply LH torque to mechanically release the setting tool. 18.15 Pressure up drill pipe to 500 psi and pick up to remove the RS packoff bushing from the RS nipple. Bump up pressure as required 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) Lead Slurry Tail Slurry System EconoCem HalCem Density 12.0 lb/gal 15.8 lb/gal Yield 2.35 ft3/sk 1.16 ft3/sk Mix Water 13.92 gal/sk 4.98 gal/sk Page 40 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 18.16 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. 18.17 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. While cement returns will be challenging to observe, watch for them and record the estimated volume. Rotate & circulate to clear cmt from DP. 18.18 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. 18.19 Change upper rams from 7” fixed to 2-7/8” x 5” VBRs and test with 4” and 5” test joints to 250 psi low / 4,500 psi high for 5/5 minutes. 18.20 Pressure test casing and liner to 250 psi low / 4,000 psi high for 30 minutes. Do not test until cement has reached minimum 500 psi compressive strength. 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 frank.roach@hilcorp.com and joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 41 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 19.0 Drill 6-1/8” Production Hole Section 19.1 MU 6-1/8” directional BHA x RSS and Triple Combo x Ensure BHA components have been inspected previously. x Drift and caliper all components before MU. Visually verify no debris inside components that cannot be drifted. x Ensure MWD is RU and operational. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. x Drill string will be a tapered string 5” 19.5# S-135 XT50 and 4” 14.0# S-135 XT39. x Run a solid float in the production hole section. 19.2 TIH w/ 6-1/8” BHA to top of 7” liner. Slowly enter liner top and continue t/TIH to landing collar. Note depth landing collar tagged on AM report. 19.3 RU and test casing/liner envelope to 4,000 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and plot on FIT graph. Document incremental volume pumped (and subsequent pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001. 19.4 Drill out shoe track to 10’ above float shoe. Displace well to 9.7 ppg solids-free drilling fluid. 19.5 Drill out remaining shoe track and 20’ of new formation. 19.6 CBU and condition mud for FIT. x Conduct FIT to 11.5 ppg EMW. Chart Test. Ensure test is recorded on same chart as casing test. Document incremental volume pumped (and subsequent pressure) and volume returned. Submit casing test and FIT digital data to AOGCC. x 11.5 ppg FIT provides >>25bbls based on 10.4 ppg MW +0.5ppg kick intensity, 9.40 ppg EMW PP @TD 19.7 6-1/8” hole section mud program summary: x Density: Primary weighting material to be used for the hole section will be sodium chloride. Additional NaCl will be on location to weight up the active system (1) ppg above highest anticipated MW. x Solids Concentration: It is imperative that the solids concentration be kept low while drilling the production hole section. Keep the shaker screen size optimized and fluid running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible. * Casing test and FIT digital data to AOGCC upon completion of FIT. Page 42 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure x Rheology: Keep viscosifier additions to a minimum (FLO-VIS). Utilize high vis sweeps and tandem sweeps as necessary for hole cleaning. Ensure 6 rpm is > 6 (hole diameter) for sufficient hole cleaning x Run the centrifuge as needed while drilling the production hole, this will help with solids removal. x Dump and dilute as necessary to keep drilled solids to an absolute minimum. x MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, & Toolpusher office. System Type:9.7 – 10.4 ppg PowerPro drilling fluid Properties: Interval Density PV YP API FL HPHT Drill Solids MBT Hardness Production 9.7-10.4 5 –20 15 –25 <10 NA <8 <10.0 <200 Product- production Size Pkg ppb or (% liquids) Busan 1060 55 gal dm 0.095 FLOTROL 55 lb sx 6 CONQOR 404 WH (8.5 gal/100 bbls)55 gal dm 0.2 FLO-VIS PLUS 25 lb sx 0.7 KCl 50 lb sx 10.7 SMB 50 lb sx 0.45 LOTORQ 55 gal dm 1.0 SAFE-CARB 10 (verify)50 lb sx 10 SAFE-CARB 20 (verify)50 lb sx 10 Soda Ash 50 lb sx 0.5 19.8 Install MPD RCD 19.9 Begin drilling 6-1/8” hole section, on-bottom staging technique: x Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8K. x Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations x If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to PU off bottom and restart on bottom staging technique. If stick slip continues, consider adding 0.5% lubes 19.10 Drill 6-1/8” hole section to section TD per Geologist and Drilling Engineer. x Flow Rate: 250-350 GPM, target min. AV’s in the open hole section: 200 ft/min, 175 GPM Page 43 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure x Flow Rate: 250-350 GPM, AV’s in the 7” section w/4” DP: 200 ft/min, 191 GPM x Flow Rate: 250-350 GPM, AV’s in the 9-5/8” section w/5” DP: 170 ft/min, 350 GPM x RPM: 120+ x Pay close attention to circulating pressures. At this depth and with a 5” x 4” tapered drillstring, circulating pressures may approach maximum of Parker 273’s circulating system. Adjust circulating rates and ROP accordingly. x Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly wet to maximize solids removal efficiency. Check for holes in screens on every connection. x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex: concretion deflection x Monitor Torque and Drag with pumps on every 5 stands x Monitor ECD, pump pressure & hookload trends for hole cleaning indication x Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across the sand for any extended period of time. x Reservoir plan is to drill down into the Ivishak sands before turning up and landing back in the Sag River sands for the horizontal. x There are no projected fault crossings in the production interval. x After making a connection, it may be necessary to start rotation prior to bringing on the pumps. This is to help break the static gels in the mud and minimize the ECD. x Limit maximum instantaneous ROP to < 100 FPH. The sands will drill faster than this, but this is a very short interval to TD. x Be aware of Zone 3 conglomerates and Zone 2 chert. While these intervals are short due to the hole angle, these formations can damage the bit and necessitate a bit trip. x MPD will be utilized to hold ECD and monitor pressure build up on connections. x 6-1/8” Hole Section A/C: x There are no wells with a CF < 1.0 19.11 TD Will be called by the geologist when all tools have reached TD, CBU at drilling rate and max rotation. Pump sweeps if needed x Monitor BU for increase in cuttings 19.12 BROOH to the 7” shoe. x Circulate at full drilling rate x Pulling speed 5 – 10 min/stand (slip to slip time, not including connections), adjust as dictated by hole conditions x If pulling tight, trip back to TD and begin backreaming operations. 19.13 CBU minimum 5 times at the 7” shoe at maximum rate and clean casing with high vis sweeps. 19.14 When at the 9-5/8” shoe, monitor well for flow. Increase mud weight if necessary. x Perform extended flow checks to determine if well is overbalanced. Treat all flow as an influx until proven otherwise Page 44 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure x If necessary, increase MW at shoe for any higher than expected pressure observed 19.15 Pull RCD Bearing and install trip nipple. 19.16 POOH and LD BHA. Rabbit DP that will be used to run liner. Only LWD open hole logs are planned for the hole section (Triple Combo). There will not be any additional logging runs conducted. Page 45 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 20.0 Run 4-1/2” Production Liner 20.1 Well control preparedness: In the event of an influx of formation fluids while running the injection liner, the following well control response procedure will be followed: When M/U & running 4-1/2” liner: x P/U & M/U the 5” safety joint (with 4-1/2” crossover installed on bottom, TIW valve in open position on top, 5” handling joint above TIW). This joint shall be fully M/U and available prior to running the first joint of 4-1/2” liner. x Slack off and with 5” DP across the BOP, shut in ram or annular on 5” DP. Close TIW. x Proceed with well kill operations. When 4-1/2” liner is fully picked up and RIH on 4” DP: x P/U & M/U the 5” safety joint (with 4” crossover installed on bottom, TIW valve in open position on top, 5” handling joint above TIW). This joint shall be fully M/U and available prior to running the first stand of 4” drillpipe. x Slack off and with 5” DP across the BOP, shut in ram or annular on 5” DP. Close TIW. x Proceed with well kill operations. 20.2 Upper VBRs to cover the 4-1/2” liner, 5” x 4” drillpipe used in this operation. 20.3 R/U 4-1/2” liner running equipment. x Ensure 4-1/2” 12.6# VT x XT50 crossover is on rig floor and M/U to FOSV. x Ensure 4 XT39 x XT50 crossover is on rig floor and M/U to FOSV. x Ensure all casing has been drifted on the deck prior to running. x Be sure to count the total # of joints on the deck 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. 20.4 Run 4-1/2” production liner x Use Vam approved thread compound. Dope pin end only w/ paint brush. Wipe off excess. x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Use lift nubbins and stabbing guides for the liner run. x Obtain up and down weights of the liner before entering open hole. x See data sheet on the next page for MU torque for the 4-1/2” liner connections. x Run 2 centralizers per joint. One centralizer free floating with stop rings at 4’ and 10’ above pin. Second centralizer locked down 10’ below box. Centralize no higher than 50’ below 7” shoe. 4-1/2” 12.6/# 13Cr-80 VT – Make up Torque Casing OD Minimum Optimum Maximum 4-1/2” 4,000 ft-lbs 4,440 ft-lbs 4,880 ft-lbs Page 46 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure Page 47 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 20.5 Ensure hanger/pkr will not be set in a 7” connection. x AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as per 20 AAC 25.030(d)(6). Plan is to place liner hanger with ~150’ overlap. Do not place liner hanger/packer across 7” connection. 20.6 Before picking up Baker Flexlock III/ZXP liner hanger / packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 20.7 M/U Baker Flexlock III/ZXP liner hanger / packer assy to 4-1/2” liner. Circulate 2 liner volumes to clear string and allow for PAL mix to set 20.8 Note: PU, SO, ROT and torque of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 20.9 RIH with liner no faster than 30 ft/min – Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. x Ensure all 4” and 5” DP for the liner run has been drifted x Run enough 4” DP such that the 5” x 4” DP XO is ~100’ above the 7” liner top with liner on bottom. x Fill drill pipe on the fly. Monitor FL and if filling is required due to losses/surging. 20.10 Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to bottom. 20.11 Before switching elevators and handling equipment from 4” DP to 5” DP, flow check well for 10 minutes. 20.12 Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, & 20 RPM. If torque approaches make-up torque of liner, discontinue rotation. 20.13 Tag bottom and PU to position float shoe ~2’ off bottom. 20.14 Break circulation. Begin circulating at ~0.5 – 1 BPM and monitor pump pressures. Slowly stage up to full circulating rate (planned cementing rates). Allow circulating pressures to stabilize before increasing circulating rate to the next stage. Circulate 4 BU or more if needed to condition hole for cementing. Reduce YP to < 18 to help ensure success of cement job. Do not start the YP drop until liner is on bottom and cementers are ready. Do not exceed 1,600 psi while circulating for risk of prematurely setting liner hanger. Note all losses. Confirm all pressures with Baker. Page 48 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 21.0 Cement 4-1/2” Production Liner 21.1 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 How to handle cement returns at surface. Ensure vac trucks are on standby and ready to assist. x Which pumps will be utilized for displacement, and how fluid will be fed to displacement pump. x Ensure adequate amounts 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. 21.2 Document efficiency of all possible displacement pumps prior to cement job. 21.3 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. 21.4 R/U cement line (if not already done so). Company Rep to witness loading of the drillpipe dart into rotating cement head. 21.5 Prior to starting cement job, drop ball and set Flexlock liner hanger per Baker representative. 21.6 Slack off 20K lbs on the Flexlock/ZXP liner hanger/packer assembly to ensure the HRDE setting tool is in compression for release from the Flexlock/ZXP liner hanger/packer assembly. Continue pressuring up 4,500 psi to release ball from setting sleeve and the HRDE running tool. Slack off total liner weight plus 30k to confirm hanger is set. 21.7 Fill surface cement lines with water and pressure test. 21.8 Pump remaining spacer. 21.9 Cement volume based on annular volume + 40% open hole excess. Job will consist of tail slurry, TOC brought to top of liner. Page 49 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure Estimated Total Cement Volume: Cement Slurry Design: 21.10 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. 21.11 Displace cement at max rate of 7 bbl/min. Reduce pump rate to 2-3 bpm and park liner on depth 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. 21.12 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. 21.13 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. 21.14 Bleed DP pressure to 0 psi and check floats. Pick up to expose rotating dog sub and set down 50K Pick back up and begin rotating at 10-20 RPM and set down 50K again. 21.15 Pickup to verify that the HRD setting tool has released. If running tool cannot be hydraulically released, apply LH torque to mechanically release the setting tool. 21.16 Pressure up drill pipe to 500 psi and pick up to remove the RS packoff bushing from the RS nipple. Bump up pressure as required to maintain 500 psi DP pressure while moving pipe until Tail Slurry System HalCem Density 15.8 lb/gal Yield 1.16 ft3/sk Mix Water 4.98 gal/sk Page 50 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 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) 21.17 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. 21.18 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. While cement returns will be challenging to observe, watch for them and record the estimated volume. Rotate & circulate to clear cmt from DP. 21.19 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. 21.20 Pressure test casing and liner to 250 psi low / 4,000 psi high for 30 minutes. Do not test until cement has reached minimum 1,000 psi compressive strength. Note: Once running tool is LD, swap to the completion AFE. 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 frank.roach@hilcorp.com and joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 51 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 22.0 Run Upper Completion/ Post Rig Work 22.1 RU to run 4-1/2” 12.6#, 13Cr-80 Vam Top tubing. x Ensure wear bushing is pulled. x Ensure 4-1/2”, 12.6#, Vam Top x 5” XT50 crossover is on rig floor and M/U to FOSV. x Ensure all tubing has been drifted in the pipe shed prior to running. x Be sure to count the total # of joints in the pipe shed before running. x Keep hole covered while RU casing tools. x Record OD’s, ID’s, lengths, SN’s of all components with vendor & model info. x Monitor displacement from wellbore while RIH. 22.2 PU, MU and RH with the following 4-1/2” completion jewelry (tally to be provided by Operations Engineer): x Torque Turn All Connections x Tubing Jewelry to include (top to bottom): x 1x SSSV nipple profile x 6x GLMs (size and final number to be determined by OE) x 1x ‘X’ Nipple x 1x Production Packer x 1x ‘X’ Nipple x 1x ‘XN’ Nipple with RHC profile installed x 1x WLEG x Tubing is 4-1/2”, 12.6#, 13Cr-80, Vam Top 4-1/2” 12.6/# 13Cr-80 Vam Top – Make up Torque Casing OD Minimum Optimum Maximum 4-1/2” 4,000 ft-lbs 4,440 ft-lbs 4,880 ft-lbs Page 52 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure Page 53 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 22.3 Space out the completion to land such that the 4-1/2” WLEG is inserted half-way into the PBR on the 4-1/2” production liner. Record PU and SO weights prior to picking up tubing hanger. 22.4 MU the tubing hanger and land same. Run in the lock-down screws and torque to spec. 22.5 Reverse circulate heated kill-weight brine. Circulate surface-to-surface at a maximum of 4 BPM with brine and inhibited brine as follows: x Clean brine within the tubing from WLEG to surface x Inhibited brine on the annular side from the shear valve depth to the WLEG x Clean brine on the annular side from surface down to the shear valve. 22.6 Install and pressure test TWC from above. 22.7 ND BOPE. NU the tubing head adapter and tree. 22.8 PT the tubing hanger void to 500/5,000 psi. PT the tree to 250/5,000 psi. 22.9 RU lubricator and pull TWC. 22.10 Freeze protect the wellbore. x Rig up to pump heated diesel down the IA, taking returns up the tubing up the tubing. Reverse 188 bbls heated diesel into the IA. Do not exceed 3bpm while circulating. x Shut in the IA. x Line up to U-tube from the IA to the tubing. x U-tube the diesel and freeze protect the tubing and IA to ~2,200’ MD. 22.11 After u-tube is complete, RU lubricator and install BPV. 22.12 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over with valve alignment as per operations personnel. Page 54 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 22.13 RDMO Parker 273 i. POST RIG WELL WORK (sundry to follow) 1. Slickline/Fullbore a. Pull BPV. b. Set production packer c. Test Tbg and IA to 250 psi low, 4,000 psi high for 5/30 minutes i. Chart test d. Perforate production interval e. Change out GLV per GL ENGR if not done already 2. Well Tie-In Page 55 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 23.0 Parker 273 Rig BOP Schematic Page 56 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 24.0 Wellhead Schematic Page 57 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 25.0 Days Vs Depth Page 58 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 26.0 Formation Tops & Information Page 59 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure Page 60 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure Page 61 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure Page 62 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 27.0 Anticipated Drilling Hazards 12-1/4” Hole Section: Hole Cleaning: Maintain rheology of mud system. Utilize sweeps to evaluate and maintain good hole cleaning (weighted, high-vis, and low-vis/high-vis tandem sweeps all have seen success, depending on hole angle). Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge as needed to control drilled solids. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 800 gpm Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: Crossing faults, known or unknown, can result in drilling into unstable formations that may impact future drilling and liner runs. Talk with Geologist to ensure all known faults are identified and prepared for accordingly. H2S: DS-NK is an H2S location. Below are the most recent H2S values of monitored wells in the Ivishak Pool. Well Name H2S Level Date of Reading #1 Closest SHL Well H2S Level NK-25 20 ppm 4/20/2012 #2 Closest SHL Well H2S Level NK-26A 8 ppm 8/17/2024 #1 Closest BHL Well H2S Level NK-42 76 ppm 2/26/2023 #2 Closest BHL Well H2S Level NK-22A 180 ppm 1/22/2023 Max. Recorded H2S on nearest Pad/Facility NK-21 1,580 ppm 6/25/2022 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. Page 63 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Abnormal Pressures and Temperatures: P Reservoir pressures are expected to be normal. Utilize MPD to mitigate any abnormal pressure seen. Ugnu/West Sak Hardstreaks: Hard formations (which are not necessarily predictable) can be encountered resulting in damage to PDC cutters. Damage occurs due to high impact loading of the bit cutting structure when hard streaks are hit at high ROP. Follow the appropriate mitigation strategy of reducing rotary speed while maintaining WOB. Colville Breathing: This is associated with higher mud weights and higher ECD’s in the Colville mudstones. Monitor ECDs and mud properties. Fingerprint connections to confirm breathing and not a well control event. Anti-Collision Take directional surveys every stand, take additional surveys if necessary. Continuously monitor drilling parameters for signs of magnetic interference with another well. Reference A/C report in directional plan. 12-1/4” Hole Section Specific AC: x There are no wells with a CF < 1.0 Note: abnormal pressures expected in shales/mudstones from CM3 through Kingak, however no permeable formations anticipated to be abnormally pressured. Kuparuk anticipated to be at 0.494 psi/ft gradient. See attached emails. -A.Dewhurst 19DEC24 Page 64 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 8-1/2” x 9-7/8” Hole Section: Hole Cleaning: Maintain rheology of mud system. Utilize sweeps to evaluate and maintain good hole cleaning (weighted, high-vis, and low-vis/high-vis tandem sweeps all have seen success, depending on hole angle). Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge as needed to control drilled solids. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Reduce ROP (as opposed to flow rate) to control ECD. Maintain circulation rate of > 500 gpm Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: No faults are forecasted to be crossed in this interval. Crossing faults, known or unknown, can result in drilling into unstable formations that may impact future drilling and liner runs. Talk with Geologist to ensure all known faults are identified and prepared for accordingly. H2S: DS-NK is an H2S location. Below are the most recent H2S values of monitored wells in the Ivishak Pool. Well Name H2S Level Date of Reading #1 Closest SHL Well H2S Level NK-25 20 ppm 4/20/2012 #2 Closest SHL Well H2S Level NK-26A 8 ppm 8/17/2024 #1 Closest BHL Well H2S Level NK-42 76 ppm 2/26/2023 #2 Closest BHL Well H2S Level NK-22A 180 ppm 1/22/2023 Max. Recorded H2S on nearest Pad/Facility NK-21 1,580 ppm 6/25/2022 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 65 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure Abnormal Pressures and Temperatures: Reservoir pressures are expected to be normal. Utilize MPD to mitigate any abnormal pressure seen. Colville Breathing: This is associated with higher mud weights and higher ECD’s in the Colville mudstones. Monitor ECDs and mud properties. Fingerprint connections to confirm breathing and not a well control event. Tuffs or “Shale Wall” (CM1): The top of the CM1 is lithologically similar to the shallower CM intervals, but contains some interbedded volcanic tuff beds. Tuffs are hard and abrasive, especially at the top of the interval. Reduce WOB and ROP to maximize bit and reamer life when drilling through the CM1. Formation Breakout (HRZ/Kingak instability): This is related to the fissile (finely laminated) nature of the formation in conjunction with higher pore pressure, which requires higher mud weight to maintain wellbore stability. If splintering cuttings are observed at surface, additional circulations and mud weight may be required. Anti-Collision Take directional surveys every stand, take additional surveys if necessary. Continuously monitor drilling parameters for signs of magnetic interference with another well. Reference A/C report in directional plan. 8.5” x 9-7/8” Hole Section Specific AC: x There are no wells with a CF < 1.0. Note: abnormal pressures expected in shales/mudstones from CM3 through Kingak, however no permeable formations anticipated to be abnormally pressured. Kuparuk anticipated to be at 0.494 psi/ft gradient. See attached emails. -A.Dewhurst 19DEC24 Page 66 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 6-1/8” Hole Section: Hole Cleaning: Maintain rheology of mud system. Utilize sweeps to evaluate and maintain good hole cleaning (weighted, high-vis, and low-vis/high-vis tandem sweeps all have seen success, depending on hole angle). Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge as needed to control drilled solids. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Reduce ROP (as opposed to flow rate) to control ECD. Maintain circulation rate of > 250 gpm Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: There are 3 possible fault crossings in this interval (2 high probability and 1 low probability). All 3 faults have throws < 100’ and have a low lost circulation risk. Crossing faults, known or unknown, can result in drilling into unstable formations that may impact future drilling and liner runs. Talk with Geologist to ensure all known faults are identified and prepared for accordingly. H2S: DS-NK is an H2S location. Below are the most recent H2S values of monitored wells in the Ivishak Pool. Well Name H2S Level Date of Reading #1 Closest SHL Well H2S Level NK-25 20 ppm 4/20/2012 #2 Closest SHL Well H2S Level NK-26A 8 ppm 8/17/2024 #1 Closest BHL Well H2S Level NK-42 76 ppm 2/26/2023 #2 Closest BHL Well H2S Level NK-22A 180 ppm 1/22/2023 Max. Recorded H2S on nearest Pad/Facility NK-21 1,580 ppm 6/25/2022 4. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 5. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. Page 67 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 6. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Abnormal Pressures and Temperatures: Reservoir pressures are expected to be normal. Utilize MPD to mitigate any abnormal pressure seen. Shublik Breathing: This is associated with higher mud weights and higher ECD’s in the Shublik carbonates. This is different in comparison to the breathing potential in the Colville Mudstones in that the formation will take fluid, but release gas. If treated like a traditional influx, the subsequent weight-up will start the process over with more fluid being lost and then more gas being released. Circulating out the gas via driller’s method and monitor pressures to determine if this is a breathing event or if it is an influx. Zone 4 and Zone 3 Conglomerates; Zone 2 Hard Streaks: Zone 3 conglomerates and Zone 2 chert/hard streaks can hinder ROP. Bit selection is key to avoid a bit trip. Maintain WOB to work through and maintain directional control through the zones. Anti-Collision Take directional surveys every stand, take additional surveys if necessary. Continuously monitor drilling parameters for signs of magnetic interference with another well. Reference A/C report in directional plan. 6-1/8” Hole Section Specific AC: x There are no wells with a CF < 1.0. Page 68 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 28.0 Parker 273 Rig Layout Page 69 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 29.0 FIT 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. Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental volume pumped and returned during test. Page 70 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 30.0 Parker 273 Rig Choke Manifold Schematic Page 71 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 31.0 Casing Design Page 72 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 32.0 12-1/4” Hole Section MASP Page 73 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 33.0 8-1/2” x 9-7/8” Hole Section MASP 9255 * 0.546 = 5032 psi 5032 - 926 = 4127 psi 4127 PSI - mgr Page 74 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 34.0 6-1/8” Hole Section MASP Page 75 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 35.0 Spider Plot (NAD 27) (Governmental Sections) Page 76 Prudhoe Bay East NK-41B Sag/Ivishak Producer Drilling Procedure 36.0 Surface Plat (As Built) (NAD 27) 6WDQGDUG3URSRVDO5HSRUW 'HFHPEHU 3ODQ1.%ZS +LOFRUS1RUWK6ORSH//& 1LDNXN 1. 3ODQ1. 3ODQ1.% 3000400050006000700080009000100001100012000True Vertical Depth (2000 usft/in)0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 11000 12000 13000 14000 15000 16000 17000 18000 19000Vertical Section at 62.15° (2000 usft/in)NK-41B wp03 tgt1NK-41B wp03 tgt3NK-41B wp03 tgt21800019000200002100021225NK-41PB2220002250023742NK-41225002300023561NK-41A19000200002100022093NK-41PB335004000450050005500600065007000750080008500900095001000010500110001150012000125001300013500140001450015000155001600016500170001750020613NK-41PB113 3/8" x 17 1/2" TOW9 5/8" x 12 1/4"7" x 8 1/2"4 1/2" x 6 1/8"45005000550060006500700075008000850090009500100001050011000115001200012500130001350014000145001500015500160001650017000175001800018500190001950020500210002150021951NK-41B wp05KOP : Start Dir 8.6º/100' : 4254' MD, 3955.83'TVD : 20° RT TFEnd Dir : 4278.4' MD, 3969.35' TVDStart Dir 4º/100' : 4308.4' MD, 3985.55'TVDEnd Dir : 4952.04' MD, 4249.3' TVDStart Dir 4º/100' : 6952.04' MD, 4781.09'TVDEnd Dir : 7085.83' MD, 4816.7' TVDStart Dir 4º/100' : 19125.72' MD, 8020.12'TVDEnd Dir : 20240.06' MD, 8684.75' TVDTotal Depth : 21950.86' MD, 10166.35' TVDSV4SV3SV2SV1UG4UG3UG1TWSCM3CM2CM1HRZTKUPTKNGTSGRTSHUTSADZone 3Zone 2CZone 2BZone 2AZone 1BZone 1ABSADHilcorp North Slope, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Ellipsoid SeparationWarning Method: Error RatioWELL DETAILS: Plan: NK-41Ground Level: 19.40+N/-S+E/-WNorthingEastingLatittudeLongitude0.000.005980017.95 721841.38 70° 20' 51.6024 N 148° 11' 56.1339 WSURVEY PROGRAMDate: 2023-11-15T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool106.25 4254.00 NK-41PB1 Srvy 6 GYD CT DMS (NK-41PB1) 3_Gyro-CT_Drill pipe4254.00 4650.00 NK-41B wp05 (Plan: NK-41B) GYD_Quest GWD4650.00 17507.00 NK-41B wp05 (Plan: NK-41B) 3_MWD+HRGM+MS+Sag17507.00 21462.00 NK-41B wp05 (Plan: NK-41B) 3_MWD+HRGM+MS+Sag21461.00 21950.86 NK-41B wp05 (Plan: NK-41B) 3_MWD+HRGM+MS+SagFORMATION TOP DETAILSTVDPath TVDssPath MDPath Formation4012.35 3946.00 4358.90 SV44376.35 4310.00 5429.86 SV34548.35 4482.00 6076.74 SV24996.35 4930.00 7761.04 SV15438.35 5372.00 9422.28 UG45957.35 5891.00 11372.91 UG36352.35 6286.00 12857.50 UG17381.35 7315.00 16724.94 TWS7563.35 7497.00 17408.98 CM38702.35 8636.00 20260.38 CM29089.35 9023.00 20707.25 CM19255.35 9189.00 20898.93 HRZ9457.35 9391.00 21132.18 TKUP9557.35 9491.00 21247.65 TKNG9735.35 9669.00 21453.19 TSGR9811.35 9745.00 21540.94 TSHU9886.35 9820.00 21627.55 TSAD9900.35 9834.00 21643.71 Zone 39933.35 9867.00 21681.82 Zone 2C10001.35 9935.00 21760.34 Zone 2B10049.35 9983.00 21815.76 Zone 2A10081.35 10015.00 21852.71 Zone 1B10115.35 10049.00 21891.97 Zone 1A10136.35 10070.00 21916.22 BSADREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: NK-41, True NorthVertical (TVD) Reference:NK-41B Plan @ 66.35usftMeasured Depth Reference:NK-41B Plan @ 66.35usftCalculation Method: Minimum CurvatureProject:NiakukSite:NKWell:Plan: NK-41Wellbore:Plan: NK-41BDesign:NK-41B wp05CASING DETAILSTVD TVDSS MD SizeName3956.40 3890.05 4255.00 13-3/8 13 3/8" x 17 1/2" TOW7589.40 7523.05 17506.88 9-5/8 9 5/8" x 12 1/4"9742.40 9676.05 21461.33 7 7" x 8 1/2"10166.35 10100.00 21950.87 4-1/2 4 1/2" x 6 1/8"SECTION DETAILSSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation1 4254.00 55.36 46.06 3955.83 642.49 710.81 0.00 0.00 928.62 KOP : Start Dir 8.6º/100' : 4254' MD, 3955.83'TVD : 20° RT TF2 4278.40 57.33 46.93 3969.35 656.46 725.54 8.60 20.00 948.17 End Dir : 4278.4' MD, 3969.35' TVD3 4308.40 57.33 46.93 3985.55 673.71 743.99 0.00 0.00 972.54 Start Dir 4º/100' : 4308.4' MD, 3985.55'TVD4 4952.04 74.58 68.00 4249.30 980.10 1237.85 4.00 52.94 1552.34 End Dir : 4952.04' MD, 4249.3' TVD5 6952.04 74.58 68.00 4781.09 1702.35 3025.47 0.00 0.00 3470.30 Start Dir 4º/100' : 6952.04' MD, 4781.09'TVD6 7085.83 74.57 62.45 4816.70 1756.37 3142.52 4.00 -90.85 3599.04 End Dir : 7085.83' MD, 4816.7' TVD7 19125.72 74.57 62.45 8020.12 7124.72 13432.22 0.00 0.00 15204.79 Start Dir 4º/100' : 19125.72' MD, 8020.12'TVD8 20240.06 30.00 63.24 8684.75 7518.65 14196.06 4.00 179.44 16064.18 End Dir : 20240.06' MD, 8684.75' TVD9 20340.06 30.00 63.24 8771.35 7541.17 14240.70 0.00 0.00 16114.17 NK-41B wp03 tgt110 21950.86 30.00 63.24 10166.35 7903.80 14959.85 0.00 0.00 16919.43 NK-41B wp03 tgt3 Total Depth : 21950.86' MD, 10166.35' TVD 01000200030004000500060007000800090001000011000120001300014000South(-)/North(+) (2000 usft/in)-2000 -1000 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 11000 12000 13000 14000 15000 16000 17000West(-)/East(+) (2000 usft/in)NK-41B wp03 tgt2NK-41B wp03 tgt3NK-41B wp03 tgt182508500875090009224NK-41PB287509000950010148NK-418 75 0 9 00 0 9 2 5 0 95 0 0 9 7 5 0 1 0 0 8 7NK-41ANK-41PB31 0 0 03000350040004250450047505000525055005750600062506500675070007250750077508000NK-41PB113 3/8" x 17 1/2" TOW9 5/8" x 12 1/4"7" x 8 1/2"4 1/2" x 6 1/8"4 7 5 0 5 0 0 0 5 2 5 0 5 5 0 0 5 7 5 0 6 0 0 0 6 2 5 0 6 5 0 0 6 7 5 0 7 0 00 7 2 5 0 7 5 0 0 7 7 5 0 8 0 0 0 8 2 5 0 8 7 5 0 9 5 0 0 1 0 1 6 6NK-41B wp05KOP : Start Dir 8.6º/100' : 4254' MD, 3955.83'TVD : 20° RT TFEnd Dir : 4278.4' MD, 3969.35' TVDStart Dir 4º/100' : 4308.4' MD, 3985.55'TVDEnd Dir : 4952.04' MD, 4249.3' TVDStart Dir 4º/100' : 6952.04' MD, 4781.09'TVDEnd Dir : 7085.83' MD, 4816.7' TVDStart Dir 4º/100' : 19125.72' MD, 8020.12'TVDEnd Dir : 20240.06' MD, 8684.75' TVDTotal Depth : 21950.86' MD, 10166.35' TVDCASING DETAILSTVDTVDSS MDSize Name3956.40 3890.05 4255.00 13-3/8 13 3/8" x 17 1/2" TOW7589.40 7523.05 17506.88 9-5/8 9 5/8" x 12 1/4"9742.40 9676.05 21461.33 7 7" x 8 1/2"10166.35 10100.00 21950.87 4-1/2 4 1/2" x 6 1/8"Project: NiakukSite: NKWell: Plan: NK-41Wellbore: Plan: NK-41BPlan: NK-41B wp05WELL DETAILS: Plan: NK-41Ground Level: 19.40+N/-S +E/-W Northing Easting Latittude Longitude0.00 0.005980017.95721841.38 70° 20' 51.6024 N 148° 11' 56.1339 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: NK-41, True NorthVertical (TVD) Reference: NK-41B Plan @ 66.35usftMeasured Depth Reference:NK-41B Plan @ 66.35usftCalculation 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Just double-checked with our Niakuk geologist (Ryan Phelps, added to the email for the reply) and conƱrmed that we only anticipate the Kuparuk being a permeable zone capable of Ʋow within the CM3-Kingak abnormal pressure zone. Regards, Frank V Roach Drilling Engineer Hilcorp Alaska, LLC 907.854.2321 mobile 907.777.8413 office From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Tuesday, December 17, 2024 15:28 To: Frank Roach <frank.roach@hilcorp.com>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Cc: Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: [EXTERNAL] PBU NK-41B PTD (224-153): Question Frank, I am compleƟng my review of the PBU NK-41B PTD and have one quesƟon: x I note that the geo prog in SecƟon 26 shows anƟcipated pore pressure gradients over 0.5 psi/Ō beginning at CM3. Besides the Kuparuk (0.494 psi/Ō), would you conĮrm that you do not anƟcipate encountering any other permeable zones capable of Ňowing within this zone of abnormal pressure, from CM3 through Kingak? Thanks, Andy Andrew Dewhurst Senior Petroleum Geologist Alaska Oil and Gas ConservaƟon Commission 333 W. 7th Ave, Anchorage, AK 99501 andrew.dewhurst@alaska.gov CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 2 Direct: (907) 793-1254 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. 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. PBU NK-41B 224-153 For any cuttings collected, submit a set of washed and dried cuttings to AOGCC as per 20 AAC 25.071(b)(2). -A.Dewhurst 17DEC24 SAG RIV UNDEF OILPRUDHOE BAY WELL PERMIT CHECKLISTCompanyHilcorp North Slope, LLCWell Name:PRUDHOE BAY UN NIA NK-41BInitial Class/TypeDEV / PENDGeoArea890Unit11650On/Off ShoreOffProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2241530PRUDHOE BAY, SAG RIV UNDEF OIL - 640165NA1 Permit fee attachedYes ADL034630, ADL034635, and ADL0346342 Lease number appropriateYes3 Unique well name and numberYes PRUDHOE BAY, SAG RIV UNDEF OIL - 640165 - governed by Statewide Regs4 Well located in a defined poolYes5 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)Yes 20" conductor set before drilling parent well.18 Conductor string providedYes Original surface casing set to 4925' TVD. This well will sidetrack for SC at 4254' MD @ 3950' TVD19 Surface casing protects all known USDWsYes This is a sidetrack from existing casing20 CMT vol adequate to circulate on conductor & surf csgYes This is a sidetrack from existing surface casing. An FIT will be performed after window milling21 CMT vol adequate to tie-in long string to surf csgYes Fully cemented intermediate_2 and production liner.22 CMT will cover all known productive horizonsYes Very long intermedite_1. Hilcorp modeling worst case in tension passes.23 Casing designs adequate for C, T, B & permafrostYes Parker 273 rig has adequate tankage and good trucking support.24 Adequate tankage or reserve pitYes Sundry 324-698 is approved.25 If a re-drill, has a 10-403 for abandonment been approvedYes Halliburton collision scan passes against all offset wells with HSE collision risk26 Adequate wellbore separation proposedYes All drilling done on BOPE.27 If diverter required, does it meet regulationsYes All fluids overbalanced to pore pressure. Notable over pressure in intediate_2 of 10.0+ ppg28 Drilling fluid program schematic & equip list adequateYes 1 annular, 3 ram stack tested to 4500 psi.29 BOPEs, do they meet regulationYes 13-5/8" , 5000 psi stack tested to 4500 psi.30 BOPE press rating appropriate; test to (put psig in comments)Yes Parker 273 has 14 x 3-1/8" manual gate valves, 1 x 3-1/8" manual choke and 1 x 3-1/16" remote31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownYes Monitoring will be required.33 Is presence of H2S gas probableNA This is a development well.34 Mechanical condition of wells within AOR verified (For service well only)No NK-Pad is an H2S Pad. H2S measures are required. Max reading of 1,580 ppm recorded at NK-21 (2022).35 Permit can be issued w/o hydrogen sulfide measuresYes Overpressure (~10.5 ppg EMW) anticipated in Seabee, HRZ,and Kingak36 Data presented on potential overpressure zonesNA But no permeable formatations anticipated to be abnormally pressured.37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprADDDate12/17/2024ApprMGRDate12/20/2024ApprADDDate12/19/2024AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateThis well to be drilled into area outside of current Raven Oil Pool boundary. As such, it must be drilled using state rules. Operator has applied to expand Ravel Oil Pool to include this location.